[Federal Register Volume 89, Number 47 (Friday, March 8, 2024)]
[Rules and Regulations]
[Pages 16820-17227]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-00366]
[[Page 16819]]
Vol. 89
Friday,
No. 47
March 8, 2024
Part II
Environmental Protection Agency
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40 CFR Part 60
Standards of Performance for New, Reconstructed, and Modified Sources
and Emissions Guidelines for Existing Sources: Oil and Natural Gas
Sector Climate Review; Final Rule
Federal Register / Vol. 89 , No. 47 / Friday, March 8, 2024 / Rules
and Regulations
[[Page 16820]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2021-0317; FRL-8510-01-OAR]
RIN 2060-AV16
Standards of Performance for New, Reconstructed, and Modified
Sources and Emissions Guidelines for Existing Sources: Oil and Natural
Gas Sector Climate Review
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: The Environmental Protection Agency (EPA) is finalizing
multiple actions to reduce air pollution emissions from the Crude Oil
and Natural Gas source category. First, the EPA is finalizing revisions
to the new source performance standards (NSPS) regulating greenhouse
gases (GHGs) and volatile organic compounds (VOCs) emissions for the
Crude Oil and Natural Gas source category pursuant to the Clean Air Act
(CAA). Second, the EPA is finalizing emission guidelines (EG) under the
CAA for states to follow in developing, submitting, and implementing
state plans to establish performance standards to limit GHG emissions
from existing sources (designated facilities) in the Crude Oil and
Natural Gas source category. Third, the EPA is finalizing several
related actions stemming from the joint resolution of Congress, adopted
on June 30, 2021, under the Congressional Review Act (CRA),
disapproving the EPA's final rule titled, ``Oil and Natural Gas Sector:
Emission Standards for New, Reconstructed, and Modified Sources
Review,'' September 14, 2020 (``2020 Policy Rule''). Fourth, the EPA is
finalizing a protocol under the general provisions for optical gas
imaging (OGI).
DATES: This final rule is effective on May 7, 2024. The incorporation
by reference (IBR) of certain publications listed in the rules is
approved by the Director of the Federal Register as of May 7, 2024.
ADDRESSES: The EPA has established a docket for this rulemaking under
Docket ID No. EPA-HQ-OAR-2021-0317. All documents in the docket are
listed on the https://www.regulations.gov/ website. Although listed,
some information is not publicly available, e.g., Confidential Business
Information (CBI) or other information whose disclosure is restricted
by statute. Certain other material, such as copyrighted material, is
not placed on the internet and will be publicly available only in hard
copy form. Publicly available docket materials are available
electronically through https://www.regulations.gov/.
FOR FURTHER INFORMATION CONTACT: Ms. Amy Hambrick, Sector Policies and
Programs Division (E143-05), Office of Air Quality Planning and
Standards, U.S. Environmental Protection Agency, 109 T.W. Alexander
Drive, P.O. Box 12055, Research Triangle Park, North Carolina, 27711;
telephone number: (919) 541-0964; email address: [email protected].
SUPPLEMENTARY INFORMATION: Preamble acronyms and abbreviations.
Throughout this document the use of ``we,'' ``us,'' or ``our'' is
intended to refer to the EPA. We use multiple acronyms and terms in
this preamble. While this list may not be exhaustive, to ease the
reading of this preamble and for reference purposes, the EPA defines
the following terms and acronyms here:
AMEL alternative means of emission limitation
ANSI American National Standards Institute
API American Petroleum Institute
ARPA-E Advanced Research Projects Agency-Energy
ASME American Society of Mechanical Engineers
ASTM ASTM, International
AVO audible, visual, and olfactory
AWP alternative work practice
bbl barrels of crude oil
BLM Bureau of Land Management
boe barrels of oil equivalents
BOEM Bureau of Ocean Energy Management
BSER best system of emission reduction
Btu/scf British thermal units per standard cubic foot
[deg]C degrees Celsius
CAA Clean Air Act
CBI Confidential Business Information
CCR Code of Colorado Regulations
CDX EPA's Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CFR Code of Federal Regulations
CO carbon monoxide
CO2 carbon dioxide
CO2 Eq. carbon dioxide equivalent
COS carbonyl sulfide
CRA Congressional Review Act
CS2 carbon disulfide
CVS closed vent systems
D.C. Circuit U.S. Court of Appeals for the District of Columbia
Circuit
DOE Department of Energy
EAV equivalent annual value
EDF Environmental Defense Fund
EG emission guidelines
EIA U.S. Energy Information Administration
EJ environmental justice
E.O. Executive Order
EPA Environmental Protection Agency
ESD emergency shutdown devices
[deg]F degrees Fahrenheit
FEAST Fugitive Emissions Abatement Simulation Toolkit
FR Federal Register
FrEDI EPA's Framework for Evaluating Damages and Impacts model
FRFA final regulatory flexibility analysis
g/hr grams per hour
GHG greenhouse gas
GHGI Inventory of U.S. Greenhouse Gas Emissions and Sinks
GHGRP Greenhouse Gas Reporting Program
GOR gas-to-oil ratio
H2S hydrogen sulfide
HAP hazardous air pollutant(s)
ICR information collection request
IRFA initial regulatory flexibility analysis
IWG Interagency Working Group on the Social Cost of Greenhouse Gases
kg kilograms
kg/hr kilograms per hour
kt kilotons
lb/yr pounds per year
low-E low emission
LDAR leak detection and repair
LPE legally and practicably enforceable
Mcf thousand cubic feet
MW megawatt
NAAQS national ambient air quality standards
NAICS North American Industry Classification System
NDE no detectable emissions
NIE no identifiable emissions
NESHAP national emission standards for hazardous air pollutants
NGO non-governmental organization
NHV net heating value
NOX nitrogen oxides
NSPS new source performance standards
NTTAA National Technology Transfer and Advancement Act
O2 oxygen
OAQPS Office of Air Quality Planning and Standards
OGI optical gas imaging
OMB Office of Management and Budget
PM particulate matter
PM2.5 particulate matter with a diameter of 2.5
micrometers or less
ppb parts per billion
ppm parts per million
PRA Paperwork Reduction Act
PSD prevention of significant deterioration
PTE potential to emit
PV present value
REC reduced emissions completion
RFA Regulatory Flexibility Act
RIA regulatory impact analysis
RTC response to comments
RULOF remaining useful life and other factors
SBAR Small Business Advocacy Review
SC-CH4 social cost of methane
SC-CO2 social cost of carbon dioxide
SC-GHG social cost of greenhouse gases
SC-N2O social cost of nitrous oxide
scf standard cubic feet
scfh standard cubic feet per hour
scfm standard cubic feet per minute
SIP State Implementation Plan
SO2 sulfur dioxide
SPeCS State Planning Electronic Collaboration System
tpy tons per year
the court U.S. Court of Appeals for the District of Columbia Circuit
[[Page 16821]]
TAR Tribal Authority Rule
TIP Tribal Implementation Plan
TSD technical support document
UMRA Unfunded Mandates Reform Act
U.S. United States
VCS voluntary consensus standards
VOC volatile organic compound(s)
VRU vapor recovery unit
Organization of this document. The information in this preamble is
organized as follows:
I. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document and other related
information?
C. Judicial Review and Administrative Review
II. Executive Summary
A. Purpose of the Regulatory Actions
B. Summary of the Major Provisions of This Regulatory Action
C. Costs and Benefits
III. Air Emissions From the Crude Oil and Natural Gas Sector and
Public Health and Welfare
A. Impacts of GHGs, VOCs, and SO2 Emissions on Public
Health and Welfare
B. Profile of the Oil and Natural Gas Industry and Its Emissions
IV. Statutory Background and Regulatory History
A. Statutory Background of CAA Sections 111(b), 111(d), and
General Implementing Regulations
B. What is the regulatory history and litigation background of
NSPS and EG for the oil and natural gas industry?
C. Congressional Review Act (CRA) Joint Resolution of
Disapproval
V. Legal Basis for Final Rule Scope
A. Introduction
B. Overview
C. Comments
D. Response to Comments and Discussion
VI. Other Actions and Related Efforts
A. Related State Actions and Other Federal Actions Regulating
Oil and Natural Gas Sources
B. Industry and Voluntary Actions To Address Climate Change
C. Methane Emissions Reduction Program
VII. Summary of Engagement With Pertinent Stakeholders
VIII. Overview of Control and Control Costs
A. Control of Methane and VOC Emissions in the Crude Oil and
Natural Gas Source Category--Overview
B. How does the EPA evaluate control costs in this final action?
IX. Interaction of the Rules and Response to Significant Comments
Thereon
A. What date defines a new, modified, or reconstructed source
for purposes of the final NSPS OOOOb?
B. What date defines an existing source for purposes of the
final EG OOOOc?
C. How will the final EG OOOOc impact sources already subject to
NSPS KKK, NSPS OOOO, or NSPS OOOOa?
X. Summary of Final Standards NSPS OOOOb and EG OOOOc
A. Fugitive Emissions From Well Sites, Centralized Production
Facilities, and Compressor Stations
B. Advanced Methane Detection Technology Work Practices
C. Super Emitter Program
D. Process Controllers
E. Pumps
F. Wells and Associated Operations
G. Centrifugal Compressors
H. Combustion Control Devices
I. Reciprocating Compressors
J. Storage Vessels
K. Covers and Closed Vent Systems
L. Equipment Leaks at Natural Gas Processing Plants
M. Sweetening Units
N. Electronic Reporting
O. Prevention of Significant Deterioration and Title V
Permitting
XI. Significant Comments and Changes Since Supplemental Proposal for
NSPS OOOOb and EG OOOOc
A. Fugitive Emissions from Well Sites, Centralized Production
Facilities, and Compressor Stations
B. Advanced Methane Detection Technology Work Practices
C. Super Emitter Program
D. Process Controllers
E. Pumps
F. Wells and Associated Operations
G. Centrifugal Compressors
H. Combustion Control Devices
I. Reciprocating Compressors
J. Storage Vessels
K. Covers and Closed Vent Systems
L. Equipment Leaks at Natural Gas Processing Plants
M. Sweetening Units
XII. Significant Comments and Changes Since Proposal for NSPS OOOOa
and NSPS OOOO
A. Low Production Well Site Exemption Rescission
B. Compressor Station Quarterly Monitoring
C. Delay-of-Repair Provisions
D. Applicability/Scope of the Rule
XIII. Significant Comments and Changes to Emission Guidelines for
State, Tribal, and Federal Plan Development for Existing Sources
A. Overview
B. Components of EG
C. Establishing Standards of Performance in State Plans
D. Components of State Plan Submission
E. Timing of State Plan Submissions and Compliance Times
F. EPA Action on State Plans and Promulgation of Federal Plans
G. Tribes and the Planning Process Under CAA Section 111(d)
XIV. Use of Optical Gas Imaging in Leak Detection (Appendix K) and
Response to Significant Comments
A. Changes Since Supplemental Proposal
B. Summary of Requirements
XV. Prevention of Significant Deterioration and Title V Permitting
XVI. Summary of Cost, Environmental, and Economic Impacts
A. What are the air quality impacts?
B. What are the secondary impacts?
C. What are the cost impacts?
D. What are the economic impacts?
E. What are the benefits?
F. What analyses of environmental justice did we conduct?
XVII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 14094: Modernizing Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act (NTTAA) and
1 CFR Part 51
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations and Executive Order 14096: Revitalizing Our Nation's
Commitment to Environmental Justice for All
K. Congressional Review Act (CRA)
I. General Information
A. Does this action apply to me?
The source category that is the subject of this final rulemaking is
composed of the Crude Oil and Natural Gas source category regulated
under CAA section 111 New Source Performance Standards and Emission
Guidelines. The North American Industry Classification System (NAICS)
codes for the industrial source category affected by the NSPS actions
finalized in this rulemaking are summarized in table 1. The NAICS codes
serve as a guide for readers outlining the type of entities that the
final NSPS actions are likely to affect. The NSPS codified in 40 Code
of Regulations (CFR) part 60, subpart OOOOb, are directly applicable to
affected facilities that begin construction, reconstruction, or
modification after December 6, 2022. Final amendments to 40 CFR part
60, subpart OOOO, are applicable to affected facilities that began
construction, reconstruction, or modification after August 23, 2011,
and on or before September 18, 2015. Final amendments to 40 CFR part
60, subpart OOOOa, are applicable to affected facilities that began
construction, reconstruction, or modification after September 18, 2015,
and on or before December 6, 2022. As shown in table 1, Federal, state,
and local government entities would not be affected by the NSPS
actions.
[[Page 16822]]
Table 1--Industrial Source Categories Affected by NSPS Actions
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Category NAICS Code\1\ Examples of regulated entities
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Industry........................... 211120 Crude Petroleum Extraction.
211130 Natural Gas Extraction.
221210 Natural Gas Distribution.
486110 Pipeline Distribution of Crude Oil.
486210 Pipeline Transportation of Natural Gas.
Federal Government................. . . . . Not affected.
State and Local Government......... . . . . Not affected.
Tribal Government.................. 921150 American Indian and Alaska Native Tribal Governments.
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\1\ North American Industry Classification System (NAICS).
This table is not intended to be exhaustive but rather provides a
guide for readers regarding entities likely to be affected by the NSPS
actions. Other types of entities not listed in the table could also be
affected by these NSPS actions. To determine whether your entity is
affected by any of the NSPS actions, you should carefully examine the
applicability criteria found in the final NSPS rules. If you have
questions regarding the applicability of the NSPS rules to a particular
entity, consult the person listed in the FOR FURTHER INFORMATION
CONTACT section, your state air pollution control agency with delegated
authority for NSPS, or your EPA Regional Office.
The issuance of CAA section 111(d) final EG does not impose binding
requirements directly on existing sources. The EG codified in 40 CFR
part 60, subpart OOOOc, applies to states in the development,
submittal, and implementation of state plans to establish performance
standards to reduce emissions of GHGs from designated facilities that
are existing sources on or before December 6, 2022. Under the Tribal
Authority Rule (TAR), eligible Tribes may seek approval to implement a
plan under CAA section 111(d) in a manner similar to a state. See 40
CFR part 49, subpart A. Tribes may, but are not required to, seek
approval for treatment in a manner similar to a state for purposes of
developing a Tribal implementation plan (TIP) implementing the EG
codified in 40 CFR part 60, subpart OOOOc. The TAR authorizes Tribes to
develop and implement their own air quality programs, or portions
thereof, under the CAA. However, it does not require Tribes to develop
a CAA program. Tribes may implement programs that are most relevant to
their air quality needs. If a Tribe does not seek and obtain the
authority from the EPA to establish a TIP, the EPA has the authority to
establish a Federal CAA section 111(d) plan for designated facilities
that are located in areas of Indian country.\1\ A Federal plan would
apply to all designated facilities located in the areas of Indian
country covered by the Federal plan unless and until the EPA approves a
TIP applicable to those facilities.
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\1\ See the EPA's website, https://www.epa.gov/tribal/tribes-approved-treatment-state-tas, for information on those Tribes that
have treatment as a state for specific environmental regulatory
programs, administrative functions, and grant programs.
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B. Where can I get a copy of this document and other related
information?
In addition to being available in the docket, at Docket ID No. EPA-
HQ-OAR-2021-0317 located at https://www.regulations.gov/, an electronic
copy of this final rulemaking is available on the internet at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.
Following signature by the EPA Administrator, the EPA will post a copy
of this final rulemaking at this same website. Following publication in
the Federal Register, the EPA will post the Federal Register version of
the final rulemaking and key technical documents at this same website.
C. Judicial Review and Administrative Review
Under Clean Air Act (CAA) section 307(b)(1), judicial review of
this final rulemaking is available only by filing a petition for review
in the United States Court of Appeals for the District of Columbia
Circuit by May 7, 2024. Under CAA section 307(b)(2), the requirements
established by this final rulemaking may not be challenged separately
in any civil or criminal proceedings brought by the EPA to enforce the
requirements.
Section 307(d)(7)(B) of the CAA further provides that ``[o]nly an
objection to a rule or procedure which was raised with reasonable
specificity during the period for public comment (including any public
hearing) may be raised during judicial review.'' This section also
provides a mechanism for the EPA to convene a proceeding for
reconsideration, ``[i]f the person raising an objection can demonstrate
to the EPA that it was impracticable to raise such objection within
[the period for public comment] or if the grounds for such objection
arose after the period for public comment, (but within the time
specified for judicial review) and if such objection is of central
relevance to the outcome of the rule.'' Any person seeking to make such
a demonstration to us should submit a Petition for Reconsideration to
the Office of the Administrator, U.S. Environmental Protection Agency,
Room 3000, WJC West Building, 1200 Pennsylvania Ave. NW, Washington, DC
20460, with a copy to both the person(s) listed in the preceding FOR
FURTHER INFORMATION CONTACT section, and the Associate General Counsel
for the Air and Radiation Law Office, Office of General Counsel (Mail
Code 2344A), U.S. Environmental Protection Agency, 1200 Pennsylvania
Ave. NW, Washington, DC 20460.
II. Executive Summary
A. Purpose of the Regulatory Actions
On November 15, 2021, the EPA published a proposed rule (``November
2021 Proposal'') to mitigate climate-destabilizing pollution and
protect human health by reducing greenhouse gas (GHG) and VOC emissions
from the oil and natural gas industry,\2\ specifically the Crude Oil
and Natural Gas source category.3 4 In the November
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2021 Proposal, the EPA proposed new standards of performance under
section 111(b) of the CAA for GHGs (in the form of methane limitations)
and VOC emissions from new, modified, and reconstructed sources in this
source category, as well as revisions to standards of performance
already codified at 40 CFR part 60, subparts OOOO and OOOOa. The EPA
also proposed EG under section 111(d) of the CAA for GHGs emissions (in
the form of methane limitations) from existing sources (designated
facilities).\5\ The new CAA section 111 NSPS and EG would be codified
in 40 CFR part 60 at subpart OOOOb (NSPS OOOOb) and subpart OOOOc (EG
OOOOc), respectively. The EPA also proposed several related actions
stemming from the joint resolution of Congress, adopted on June 30,
2021, under the CRA disapproving the EPA's final rule titled, ``Oil and
Natural Gas Sector: Emission Standards for New, Reconstructed, and
Modified Sources Review,'' September 14, 2020 (``2020 Policy Rule'').
Lastly, in the November 2021 Proposal the EPA proposed a protocol under
the general provisions for OGI.
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\2\ The EPA characterizes the oil and natural gas industry
operations as being generally composed of four segments: (1)
extraction and production of crude oil and natural gas (``oil and
natural gas production''), (2) natural gas processing, (3) natural
gas transmission and storage, and (4) natural gas distribution.
\3\ ``Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review.'' Proposed rule. 86 FR 63110,
November 15, 2021.
\4\ The EPA defines the Crude Oil and Natural Gas source
category to mean: (1) crude oil production, which includes the well
and extends to the point of custody transfer to the crude oil
transmission pipeline or any other forms of transportation; and (2)
natural gas production, processing, transmission, and storage, which
include the well and extend to, but do not include, the local
distribution company custody transfer station, commonly referred to
as the ``city-gate.''
\5\ The term ``designated facility'' means ``any existing
facility which emits a designated pollutant and which would be
subject to a standard of performance for that pollutant if the
existing facility were an affected facility.'' See 40 CFR 60.21a(b).
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On December 6, 2022, the EPA published a supplemental proposed rule
(``December 2022 Supplemental Proposal'') that was composed of two main
additions.\6\ First, the EPA updated, strengthened, and expanded on the
NSPS OOOOb standards proposed in November 2021 under CAA section 111(b)
for GHGs (in the form of methane limitations) and VOC emissions from
new, modified, and reconstructed facilities. Second, the EPA updated,
strengthened, and expanded the presumptive standards proposed for EG
OOOOc in the November 2021 Proposal as part of the CAA section 111(d)
EG for GHGs emissions (in the form of methane limitations) from
designated facilities. For purposes of EG OOOOc, the EPA also proposed
the implementation requirements for state plans developed to limit GHGs
pollution (in the form of methane limitations) from designated
facilities in the Crude Oil and Natural Gas source category under CAA
section 111(d).
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\6\ ``Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review.'' Supplemental notice of
proposed rulemaking. 87 FR 74702, December 6, 2022.
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The purpose of this final rulemaking is to finalize these multiple
actions to reduce air emissions from the Crude Oil and Natural Gas
source category. First, the EPA finalizes NSPS OOOOb regulating GHG (in
the form of a limitation on emissions of methane) and VOCs emissions
for the Crude Oil and Natural Gas source category pursuant to CAA
section 111(b)(1)(B). Second, the EPA finalizes the presumptive
standards in EG OOOOc to limit GHGs emissions (in the form of methane
limitations) from designated facilities in the Crude Oil and Natural
Gas source category, as well as requirements under the CAA section
111(d) for states to follow in developing, submitting, and implementing
state plans to establish performance standards. Third, the EPA
finalizes several related actions stemming from the joint resolution of
Congress, adopted on June 30, 2021, under the CRA, disapproving the
2020 Policy Rule. Fourth, the EPA finalizes a protocol under the
general provisions of 40 CFR part 60 for OGI.
These final actions stem from the EPA's authority and obligation
under CAA section 111 to directly regulate categories of new stationary
sources that cause or contribute to endangerment from air pollution and
to promulgate EG for states to follow in regulating existing sources
(designated facilities) in the source category. This final rulemaking
takes a significant step forward in mitigating climate-destabilizing
pollution and protecting human health by reducing GHG and VOC emissions
from the oil and natural gas industry, specifically the Crude Oil and
Natural Gas source category. These mitigations are based on proven,
cost-effective technologies already required by prior EPA regulations
or states' regulations or deployed by industry leaders to reduce this
dangerous pollution. The final rules will also encourage the deployment
of innovative technologies that currently exist to rapidly and cost-
effectively detect and reduce methane pollution and promote further
innovation that is already under way to find even more efficient and
effective ways to mitigate this pollution. Because methane is the main
component of natural gas, the rules also result in more saleable
product.
The oil and natural gas industry is the United States' largest
industrial emitter of methane, a highly potent GHG. Emissions of
methane from human activities are responsible for about one-third of
the warming due to well-mixed GHGs and constitute the second most
important warming agent arising from human activity after carbon
dioxide (CO2).\7\ According to the Intergovernmental Panel
on Climate Change (IPCC), strong, rapid, and sustained methane
reductions are critical to reducing near-term disruption of the climate
system as well as a vital complement to reductions in other GHGs that
are needed to limit the long-term extent of climate change and its
destructive impacts. The oil and natural gas industry also emits other
harmful pollutants in varying concentrations and amounts, including
CO2, VOC, sulfur dioxide (SO2), nitrogen oxides
(NOX), hydrogen sulfide (H2S), carbon disulfide
(CS2), and carbonyl sulfide (COS), as well as benzene,
toluene, ethylbenzene, and xylenes (this group is commonly referred to
as ``BTEX''), and n-hexane.
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\7\ A well-mixed gas is one with an atmospheric lifetime longer
than a year or two, which allows the gas to be mixed around the
world.
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Under the authority of CAA section 111, this rulemaking finalizes
comprehensive standards of performance for GHG emissions (in the form
of methane limitations) and VOC emissions for new, modified, and
reconstructed sources in the Crude Oil and Natural Gas source category,
including sources located in the production, processing, and
transmission and storage segments. For designated facilities, this
rulemaking finalizes EG containing presumptive standards for GHG in the
form of methane limitations. States must follow these EG to submit to
the EPA plans that establish standards of performance for designated
facilities and provide for implementation and enforcement of such
standards. The EPA will provide support for states in developing their
plans to reduce methane emissions from designated facilities within the
Crude Oil and Natural Gas source category. Under the TAR, eligible
Tribes may seek approval to implement a plan under CAA section 111(d)
in a manner similar to a state. See 40 CFR part 49, subpart A. Tribes
may, but are not required to, seek approval for treatment in a manner
similar to a state for purposes of developing a TIP implementing the EG
codified in 40 CFR part 60, subpart OOOOc. The TAR authorizes Tribes to
develop and implement one or more of their own air quality programs, or
portions thereof, under the CAA. However, it does not require Tribes to
develop a CAA program. Tribes may implement programs that are most
relevant to their air quality needs. If a Tribe does not seek and
obtain the authority from the EPA to establish a TIP, the EPA has the
authority to establish a Federal CAA section 111(d)
[[Page 16824]]
plan for designated facilities that are located in areas of Indian
country.\8\ A Federal plan would apply to all designated facilities
located in the areas of Indian country covered by the Federal plan
unless and until the EPA approves a TIP applicable to those facilities.
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\8\ See the EPA website, https://www.epa.gov/tribal/tribes-approved-treatment-state-tas, for information on those Tribes that
have treatment as a state for specific environmental regulatory
programs, administrative functions, and grant programs.
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The EPA is finalizing these actions in accordance with its legal
obligations and authorities following a review directed by Executive
Order (E.O.) 13990, ``Protecting Public Health and the Environment and
Restoring Science to Tackle the Climate Crisis,'' issued on January 20,
2021. These final actions address the harmful consequences of climate
change, which is already resulting in severe and growing human and
economic costs within the United States (and globally too). According
to the IPCC AR6 assessment, ``It is unequivocal that human influence
has warmed the atmosphere, ocean and land. Widespread and rapid changes
in the atmosphere, ocean, cryosphere and biosphere have occurred.'' The
IPCC AR6 assessment states that these changes have led to increases in
heat waves and wildfire weather, reductions in air quality, more
intense hurricanes and rainfall events, and rising sea level. These
changes, along with future projected changes, endanger the physical
survival, health, economic well-being, and quality of life of people
living in the United States (U.S.), especially those in the most
vulnerable communities.
Methane is both the main component of natural gas and a potent GHG.
Using one standard metric (the 100-year global warming potential (GWP),
which is a measure of the climate impact of emissions of 1 ton of a GHG
over 100 years relative to the impact of the emissions of 1 ton of
CO2 over the same time frame), methane has about 30 times as
much climate impact as CO2. Because methane has a shorter
lifetime than CO2, it has a larger relative impact over
shorter time frames, and a smaller one over longer time frames: the
IPCC AR6 assessment found that ``Over time scales of 10 to 20 years,
the global temperature response to a year's worth of current emissions
of SLCFs [short lived climate forcers] is at least as large as that due
to a year's worth of CO2 emissions.'' \9\ The IPCC estimated
that, depending on the reference scenario, collective reductions in
these SLCFs (methane, ozone precursors, and hydrofluorocarbons (HFCs))
could reduce warming by 0.2 degrees Celsius ([deg]C) (more than one-
third of a degree Fahrenheit ([deg]F) in 2040 and 0.8 [deg]C (almost
1.5 [deg]F) by the end of the century. As methane is the most important
SLCF, this makes methane mitigation one of the best opportunities for
reducing near-term warming. Emissions from human activities have
already more than doubled atmospheric methane concentrations since
1750, and that concentration has been growing larger at record rates in
recent years.\10\ In the absence of additional reduction policies,
methane emissions are projected to continue rising through at least
2040.
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\9\ However, the IPCC AR6 assessment cautioned that ``[t]he
effects of the SLCFs decay rapidly over the first few decades after
pulse emission. Consequently, on time scales longer than about 30
years, the net long-term temperature effects of sectors and regions
are dominated by CO2.''
\10\ Naik, V., S. Szopa, B. Adhikary, P. Artaxo, T. Berntsen,
W.D. Collins, S. Fuzzi, L. Gallardo, A. Kiendler 41 Scharr, Z.
Klimont, H. Liao, N. Unger, P. Zanis, 2021, Short-Lived Climate
Forcers. In: Climate Change 42 2021: The Physical Science Basis.
Contribution of Working Group I to the Sixth Assessment Report of
the 43 Intergovernmental Panel on Climate Change [Masson-Delmotte,
V., P. Zhai, A. Pirani, S.L. Connors, C. 44 P[eacute]an, S. Berger,
N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K. Leitzell, E.
Lonnoy, J.B.R. 45 Matthews, T.K. Maycock, T. Waterfield, O.
Yelek[ccedil]i, R. Yu and B. Zhou (eds.)]. Cambridge University 46
Press. In Press.
---------------------------------------------------------------------------
Methane's radiative efficiency means that immediate reductions in
methane emissions, including from sources in the Crude Oil and Natural
Gas source category, can help reduce near-term warming. As natural gas
is composed primarily of methane, every natural gas leak or intentional
release of natural gas through venting or other processes constitutes a
release of methane. Reducing human-caused methane emissions, such as
controlling natural gas leaks and releases through the measures in this
final action, is critical to addressing climate change and its effects.
See section III of this preamble for further discussion on the air
emissions from the Crude Oil and Natural Gas source category climate
change, including discussion of the impacts of GHGs, VOCs, and
SO2 emissions on public health and welfare.
Methane and VOC emissions from the Crude Oil and Natural Gas source
category result from a variety of industry operations across the supply
chain. As natural gas moves through the necessarily interconnected
system of exploration, production, storage, processing, and
transmission that brings it from wellhead to commerce, emissions
primarily result from intentional venting, unintentional gas carry-
through (e.g., vortexing from separator drain, improper liquid level
settings, liquid level control valve on an upstream separator or
scrubber does not seal properly at the end of an automated liquid
dumping event, inefficient separation of gas and liquid phases
occurring upstream of tanks allowing some gas carry-through), routine
maintenance, unintentional fugitive emissions, flaring, malfunctions,
abnormal process conditions, and system upsets. These emissions are
associated with a range of specific equipment and practices, including
leaking valves, connectors, and other components at well sites and
compressor stations; leaks and vented emissions from storage vessels;
releases from natural gas-driven pumps and natural gas-driven process
controllers; liquids unloading at well sites; and venting or under-
performing flaring of associated gas from oil wells. But technical
innovations have produced a range of technologies and best practices to
monitor, eliminate, or minimize these emissions, which in many cases
have the benefit of reducing multiple pollutants at once and recovering
saleable product. These technologies and best practices have been
deployed by individual oil and natural gas companies, required by state
regulations, or reflected in regulations issued by the EPA and other
Federal agencies.
In developing this final rulemaking, the EPA applied the latest
available information to finalize the analyses presented in the
December 2022 Supplemental Proposal. This latest information provided
additional insights into lessons learned from states' regulatory
efforts, the emission reduction efforts of leading companies, the
continued development of new and developing technologies, and
information and data from peer-reviewed literature and emission
measurement efforts across the U.S.
In both the November 2021 Proposal and the December 2022
Supplemental Proposal, the EPA solicited comment on various aspects of
the proposed rules. This final rulemaking responds to the nearly one
million total public comments the Agency received. A wide range of
stakeholders, including state and local governments, Tribal nations,
representatives of the oil and natural gas industry, communities
affected by oil and gas pollution, environmental and public health
organizations, submitted public comments on both the November 2021
Proposal and the December 2022 Supplemental Proposal. Following the
November 2021 Proposal, over 470,000 public comments were submitted.
After the December 2022 Supplemental
[[Page 16825]]
Proposal, over 515,000 additional public comments were submitted. Many
commenters representing diverse perspectives expressed general support
for the proposals and requested that the EPA further strengthen the
proposed rules and make them more comprehensive. Other commenters
highlighted implementation or cost concerns related to elements of both
proposals or provided specific data and information that the EPA was
able to use to refine or revise several of the proposed standards
included in the December 2022 Supplemental Proposal.
This final action also builds on extensive engagement with states,
Tribes, and a broad range of stakeholders. The EPA conducted
stakeholder trainings after both the November 2021 Proposal and the
December 2022 Supplemental Proposal for communities with environmental
justice (EJ) concerns, Tribes, and small businesses. The EPA held 3-day
virtual public hearings for both the November 2021 Proposal and the
December 2022 Supplemental Proposal with over 600 speakers and hundreds
of viewers on livestream. Tribal consultations were completed after the
November 2021 Proposal at the request of the Northern Arapahoe Tribe,
Mandan, Hidatsa and Arikara Nation (MHA Nation), and Eastern Shoshone
Tribe.\11\ Additional Tribal consultation was completed at the request
of MHA Nation and an informational meeting was held with the Ute Tribe
after the December 2022 Supplemental Proposal.\12\ Through this
stakeholder engagement, the EPA heard from diverse voices and
perspectives, all of which provided ideas and information that helped
shape and inform this final rulemaking.
---------------------------------------------------------------------------
\11\ See Memorandum in EPA-HQ-OAR-2021-0317.
\12\ See Memorandum in EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------
In this final rulemaking, the EPA is finalizing updates to various
aspects of the proposed rules because of the information received
through the public comment process. For example, after review of the
comments, the EPA is finalizing updates to allow owners and operators
the option to use advanced methane monitoring technologies for
detecting fugitive emissions. All stakeholders supported allowing for
the use of alternative technologies and provided the EPA with
constructive feedback and information to help finalize this aspect of
the rulemaking, along with improvements that provide greater
flexibility for owners and operators while ensuring these technologies
are used in an effective way to detect methane emissions. Among other
things, the EPA is finalizing changes from the December 2022
Supplemental Proposal that will allow owners and operators to use
multiple advanced technologies in combination, and facilitate the use
of the best advanced technologies that we know of by streamlining
certain of the proposed monitoring requirements associated with their
use. The EPA is also finalizing an efficient pathway for demonstrating
that new technologies meet the performance requirements established
under this rulemaking, and approving their use under this program. The
final rulemaking allows for either a periodic screening approach or a
continuous monitoring approach. The EPA believes this program will
allow owners and operators to leverage advanced technologies that are
already available to detect methane emissions rapidly with accuracy, as
well as to incorporate promising new technologies that are emerging in
this rapidly evolving field.
As a result of information provided through the public comment
process, the EPA is also finalizing revisions to the proposed
requirements for new sources to limit routine flaring of associated
gas. During the comment period, the EPA received extensive information
regarding alternatives to routine flaring, state-level requirements to
limit or prohibit routine flaring, and commitments that owners and
operators have already made voluntarily to phase out routine flaring in
the near future. Based on this information and the EPA's updated BSER
analysis, the EPA is finalizing requirements that will phase out and
eventually prohibit routine flaring of associated gas from newly
constructed wells that are developed after the effective date of this
rule. These requirements include reasonable exemptions for certain
temporary and emergency uses of flaring, and a transition period to
allow owners and operators adequate time to incorporate this
requirement into their development plans and to deploy any necessary
equipment and controls. For a subcategory of existing wells (with
documented methane of 40 tons per year (tpy) or less), the EPA is
finalizing modifications to its December 2022 Supplemental Proposal to
allow routine flaring. This approach reflects information the EPA
received during this rulemaking, and the EPA's updated BSER analysis,
that indicates that alternatives to routine flaring at such wells are
generally costly and could be technically challenging to implement,
while achieving relatively small emission reductions. For higher-
emitting existing (above 40 tpy methane), modified, and reconstructed
wells, the EPA is finalizing the provisions proposed in the December
2022 Supplemental Proposal limiting routine flaring to situations in
which a sales line to collect the associated gas is not available, and
the owner and operator has submitted a demonstration that other
alternatives to routine flaring are not available due to technical
infeasibility. With the updates made in this final rulemaking in
response to comments, the EPA believes that the final rules and
emission guidelines provide an approach to limiting routine flaring
from associated gas that achieves significant reductions in emissions,
while also providing owners and operators with flexibility to utilize
routine flaring where needed and sufficient lead time to implement
alternatives to routine flaring at newly developed wells.
Further, the EPA is finalizing, with certain revisions,
requirements proposed in the December 2022 Supplemental Proposal to
monitor flares to ensure proper operation and assure continual
compliance. Improperly operating flares are a well-documented large
source of emissions, and requiring operators to monitor and fix these
problems will yield significant methane reductions.
In addition, the EPA is finalizing a Super Emitter Program as part
of this rulemaking that requires owners and operators to take
appropriate action to investigate very large emissions events upon
receiving from the EPA a notification from a certified entity, and if
necessary, take steps to ensure compliance with the applicable
regulation(s). The EPA has made important modifications to this program
based on comments received on the December 2022 Supplemental Proposal.
Public comments informed the EPA that there is widespread recognition
of the need to address super-emitters, that it is critical for the EPA
to have a central role in the program, and that timely information-
sharing and response is key to being able to achieve emission
reductions. As a result, the final Super Emitter Program provides a
central role for the EPA in receiving notifications from certified
third parties and verifying that these notifications are complete and
have properly documented the existence of a super-emitting event before
sending them to the appropriate owner or operator. In addition, as
proposed, the EPA will have a central role in approving monitoring
technologies, certifying and de-certifying notifiers, requiring that
third parties submit
[[Page 16826]]
notifications within a limited timeframe, and obligating operators to
subsequently respond in a timely manner. These targeted changes for the
Super Emitter Program are intended to ensure that the program operates
with a high degree of accuracy, integrity, and transparency, while
providing owners and operators with prompt and reliable notifications
of super-emitting events that may require follow-up investigation and
remediation. See sections X and XI of this preamble for a full summary
and rationale of the changes since proposal.
After careful consideration of the public comments, the EPA is
finalizing other aspects of the rulemaking as proposed. For example,
the EPA is finalizing the NSPS and EG for process controllers (formerly
referred to as pneumatic controllers) as proposed. For both the NSPS
and EG, process controllers are required to meet a methane and VOC
emission rate of zero.\13\ Another area of the rulemaking that the EPA
is finalizing as proposed is liquids unloading. These sources are
required to comply with best management practices for every well that
undergoes liquids unloading that results in vented emissions. The EPA
is also finalizing standards for well completions and sweetening units
as proposed. See sections X and XI of this preamble for a full summary
and rationale of the areas of the rulemaking that are being finalized
as proposed.
---------------------------------------------------------------------------
\13\ See tables 3 and 4 of this preamble for a summary of
process controller standards in Alaska.
---------------------------------------------------------------------------
The EPA conducted an analysis of EJ in the development of this
final rulemaking and sought to ensure equitable treatment and
meaningful involvement of all people regardless of race, color,
national origin, or income in the process. The EPA engaged and
consulted representatives of frontline communities that are directly
affected by and particularly vulnerable to the climate and health
impacts of pollution from this source category through interactions
such as webinars, listening sessions, and meetings. These opportunities
allowed the EPA to hear directly from the public, especially
overburdened and underserved communities, on the development of the
rulemaking and to factor these concerns into the rulemaking. The
extensive pollution reduction measures in this final rulemaking will
collectively reduce the emissions of a suite of harmful pollutants and
their associated health impacts in communities adjacent to these
emission sources. A full discussion and summary of engagement with
pertinent stakeholders can be found in section VII of the preamble. A
full discussion of the analysis of EJ is found in section XVI.F of the
preamble.
In this final rulemaking, the EPA has conducted a comprehensive
analysis of the available data from emission sources in the Crude Oil
and Natural Gas source category, the latest available information on
control measures and techniques, and information submitted by
stakeholders through the public comment process to identify achievable,
cost-effective measures to significantly reduce emissions, consistent
with the requirements of section 111 of the CAA. This final rulemaking
will lead to significant and cost-effective reductions in climate and
health-harming pollution and encourage development and deployment of
innovative technologies to further reduce this pollution in the Crude
Oil and Natural Gas source category.
As described in more detail below, the EPA recognizes that several
states and other Federal agencies currently regulate the oil and
natural gas industry. The EPA also recognizes that these state and
other Federal agency regulatory programs have matured since the EPA
began implementing the current NSPS requirements in 2012 and 2016. The
EPA further acknowledges the technical innovations that the oil and
natural gas industry has made during the past decade; this industry
operates at a fast pace and changes constantly as technology evolves.
The EPA commends these efforts and recognizes states for their
innovative standards, alternative compliance options, and
implementation strategies, and these final actions build upon progress
made by certain states and Federal agencies in reducing GHG and VOC
emissions. See preamble section VI for further discussion of Related
State Actions and Other Federal Actions Regulating Oil and Natural Gas
Sources and Industry and Voluntary Actions to Address Climate Change.
As the Federal agency with primary responsibility to protect human
health and the environment, the EPA has the unique responsibility and
authority to regulate harmful air pollutants emitted by the Crude Oil
and Natural Gas source category. The EPA recognizes that states and
other Federal agencies regulate in accordance with their respective
legal authorities and within their respective jurisdictions but
collectively do not fully and consistently address the range of sources
and emission reduction measures contained in this final rulemaking.
Direct Federal regulation of methane from new, reconstructed, and
modified sources in this category, combined with approved state plans
that are consistent with the EPA's EG presumptive standards for
designated facilities (existing sources), will help reduce both
climate- and other health-harming pollution from a large number of
sources that are either unregulated or from which additional, cost-
effective reductions are available, level the regulatory playing field,
and help promote technological innovation.
Included in this final rulemaking are the final new subparts NSPS
OOOOb and EG OOOOc and amendatory regulatory text for NSPS OOOO, NSPS
OOOOa, and 40 CFR part 60, subpart KKK (NSPS KKK). The public docket
for this rulemaking also includes the full text redline versions of
NSPS OOOO, NSPS OOOOa, and NSPS KKK amendments.\14\ In addition, the
EPA is providing a Response to Comments (RTC) document and updated
documents including the technical support document (TSD), supporting
information collection request (ICR) burden statements, and regulatory
impact analysis (RIA) that seeks to account for the full impacts of
these proposed actions.
---------------------------------------------------------------------------
\14\ Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------
B. Summary of the Major Provisions of This Regulatory Action
This final rulemaking includes four distinct groups of actions
under the CAA each of which could have been promulgated as a separate
final rule. First, pursuant to CAA section 111(b)(1)(B), the EPA has
reviewed, and is finalizing revisions to, the standards of performance
for the Crude Oil and Natural Gas source category published in 2012 and
2016 and amended in 2020, codified at 40 CFR part 60, subpart OOOO--
``Standards of Performance for Crude Oil and Natural Gas Facilities for
Which Construction, Modification, or Reconstruction Commenced After
August 23, 2011, and on or Before September 18, 2015'' (2012 NSPS) and
subpart OOOOa--``Standards of Performance for Crude Oil and Natural Gas
Facilities for which Construction, Modification or Reconstruction
Commenced After September 18, 2015'' (2016 NSPS OOOOa). Specifically,
the EPA is updating, strengthening, and expanding the current
requirements under CAA section 111(b) for methane and VOC emissions
from sources that commenced construction, modification, or
reconstruction after December 6, 2022. These final standards of
performance will be in a new subpart, 40 CFR part 60, subpart OOOOb
(NSPS OOOOb), and include standards for emission sources previously not
regulated under the 2012 NSPS OOOO and 2016 NSPS OOOOa.
[[Page 16827]]
Second, pursuant to CAA section 111(d), the EPA is finalizing the
first nationwide EG for states to limit methane pollution from
designated facilities in the Crude Oil and Natural Gas source category.
The EG being finalized in this rulemaking will be in a new subpart, 40
CFR part 60, subpart OOOOc (EG OOOOc). The EG finalizes presumptive
standards for GHG emissions (in the form of methane limitations) from
designated facilities that commenced construction, reconstruction, or
modification on or before December 6, 2022, and implementation
requirements designed to inform states in the development, submittal,
and implementation of state plans that are required to establish
standards of performance for emissions of GHGs from their designated
facilities in the Crude Oil and Natural Gas source category. The EPA is
also finalizing regulatory language in NSPS OOOO, NSPS OOOOa, and NSPS
KKK to provide clarity on when sources transition from being subject to
these NSPS and become subject to a state or Federal plan implementing
EG OOOOc.
Third, the EPA is taking several related actions stemming from the
joint resolution of Congress, adopted on June 30, 2021, under the CRA,
disapproving the EPA's final rule titled, ``Oil and Natural Gas Sector:
Emission Standards for New, Reconstructed, and Modified Sources
Review,'' 85 FR 57018 (September 14, 2020) (``2020 Policy Rule''). As
explained in section XII of this document, the EPA is finalizing
amendments to the 2016 NSPS OOOOa to address (1) certain
inconsistencies between the VOC and methane standards resulting from
the disapproval of the 2020 Policy Rule and (2) certain determinations
made in the final rule titled, ``Oil and Natural Gas Sector: Emission
Standards for New, Reconstructed, and Modified Sources
Reconsideration,'' 85 FR 57398 (September 15, 2020) (``2020 Technical
Rule''), specifically with respect to fugitive emissions monitoring at
low production well sites and gathering and boosting stations. With
respect to the latter, as described below, the EPA is finalizing the
rescission of provisions of the 2020 Technical Rule that were not
supported by the record for that rule or by our subsequent information
and analysis.
In addition, in this final rulemaking the EPA updates the NSPS OOOO
and NSPS OOOOa provisions in the CFR to reflect the CRA resolution's
disapproval of the final 2020 Policy Rule, specifically, the
reinstatement of the NSPS OOOO and NSPS OOOOa requirements that the
2020 Policy Rule repealed but that came back into effect immediately
upon enactment of the CRA resolution. It should be noted that these
requirements have come back into effect already, even prior to these
updates to CFR text to reflect them.\15\ The EPA waited to make these
updates to the CFR text until the final rule simply because it was more
efficient and clearer to amend the CFR once at the end of this
rulemaking process to account for all changes to the 2012 NSPS OOOO (77
FR 49490, August 16, 2012) and 2016 NSPS OOOOa at the same time.
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\15\ See Congressional Review Act Resolution to Disapprove EPA's
2020 Oil and Gas Policy Rule Questions and Answers (June 30, 2021)
available at https://www.epa.gov/system/files/documents/2021-07/qa_cra_for_2020_oil_and_gas_policy_rule.6.30.2021.pdf.
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Fourth, the EPA is finalizing a protocol for the use of OGI in leak
detection being finalized as appendix K to 40 CFR part 60 (referred to
hereafter as appendix K). While this protocol is being finalized in
this action, the applicability of the protocol is broader. The protocol
is applicable to facilities when specified in a referencing subpart to
help determine the presence and location of leaks; it is not currently
applicable for use in direct emission rate measurements from sources.
The protocol does not on its own apply to any sources. For NSPS OOOOb
and EG OOOOc, we are finalizing the use of the protocol for application
at natural gas processing plants. The protocol may be applied to other
sources only when incorporated through rulemaking to a specific
subpart.
Each group of actions just described is severable from the other.
In addition, within each group of actions, the requirements governing
each emission source are separate from and so severable from the
requirements for each other emission source. Specifically, for each
emission source, the EPA separately analyzed and determined the
appropriate BSER. And for each emission source, the EPA conducted a
separate analysis for new sources governed by the NSPS and for existing
sources covered by the EG. Each of the requirements in this final rule
is functionally independent--i.e., may operate in practice
independently of the other standards of performance.
As CAA section 111(a)(1) requires, the standards of performance
being finalized in this rulemaking reflect ``the degree of emission
limitation achievable through the application of the best system of
emission reduction [BSER] which (taking into account the cost of
achieving such reduction and any nonair quality health and
environmental impact and energy requirement) the Administrator
determines has been adequately demonstrated.'' \16\ This rulemaking
further finalizes EG for designated facilities, under which states must
submit plans which establish standards of performance that reflect the
degree of emission limitation achievable through application of the
BSER, as identified in the final EG. In this final rulemaking, we
evaluated new data made available to the EPA and information provided
from public comments on the December 2022 Supplemental Proposal to
update the analyses and evaluate whether revisions to the proposed BSER
should be considered. For any potential control measure evaluated in
this rulemaking, as in the December 2022 Supplemental Proposal, the EPA
evaluated the emission reductions achievable through these measures and
employed multiple approaches to evaluate the reasonableness of control
costs associated with the options under consideration. For example, in
evaluating controls for reducing VOC and methane emissions from new
sources, we considered a control measure's cost effectiveness under
both a ``single-pollutant cost effectiveness'' approach and a
``multipollutant cost effectiveness'' approach to appropriately
consider that the systems of emission reduction considered in this
rulemaking \17\ typically achieve reductions in multiple pollutants at
once and secure a multiplicity of climate and public health benefits.
For both NSPS OOOOb and EG OOOOc, we also compared: (1) the capital
costs that would be incurred through compliance with the final
standards against the industry's current level of capital expenditures
and (2) the annualized costs against the industry's estimated annual
revenues. For a detailed discussion of the EPA's consideration of this
and other BSER statutory elements, see sections IV and VIII of this
[[Page 16828]]
preamble. Table 2 summarizes the applicability dates for the four
subparts that the EPA is finalizing.
---------------------------------------------------------------------------
\16\ The EPA notes that design, equipment, work practice, or
operational standards established under CAA section 111(h) (commonly
referred to as ``work practice standards'') reflect the ``best
technological system of continuous emission reduction'' and that
this phrasing differs from the ``best system of emission reduction''
phrase in the definition of ``standard of performance'' in CAA
section 111(a)(1). Although the differences in these phrases may be
meaningful in other contexts, for purposes of evaluating the sources
and systems of emission reduction at issue in this rulemaking, the
EPA has applied these concepts in an essentially comparable manner
because the systems of emission reduction the EPA evaluated are all
technological.
\17\ For EG OOOOc, where the pollutant is GHGs in the form of
limitations on methane, the EPA considered a control measure's cost
effectiveness under a ``single-pollutant cost effectiveness''
approach.
Table 2--Applicable Dates for Subparts Addressed in This Rulemaking \18\
------------------------------------------------------------------------
Subpart Source type Applicable dates
------------------------------------------------------------------------
40 CFR part 60, subpart OOOO.... New, modified, or After August 23,
reconstructed 2011, and on or
sources. before September
18, 2015.
40 CFR part 60, subpart OOOOa... New, modified, or After September
reconstructed 18, 2015, and on
sources. or before
December 6, 2022.
40 CFR part 60, subpart OOOOb... New, modified, or After December 6,
reconstructed 2022.
sources.
40 CFR part 60, subpart OOOOc... Existing sources.. On or before
December 6, 2022.
------------------------------------------------------------------------
1. New Source Performance Standards for New, Modified, and
Reconstructed Sources After December 6, 2022 (NSPS OOOOb)
---------------------------------------------------------------------------
\18\ See preamble section IX, ``Interaction of the Rules and
Response to Significant Comments Thereon'' for discussion on the
applicable dates.
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As described in section X of this preamble, the EPA is finalizing
several changes to the BSER and the NSPS for certain affected
facilities based on a review of new data made available to the EPA and
information provided in public comments. For the other NSPS that
generally remain unchanged, the EPA is finalizing them as proposed in
the November 2021 Proposal and/or December 2022 Supplemental Proposal.
The EPA is also finalizing further justifications, flexibilities, or
clarifications, as needed, based on the public comments and other
additional information received, as described in section X of this
preamble. The NSPS applies to affected sources across the Crude Oil and
Natural Gas source category, including the production, processing,
transmission, and storage segments, for which construction,
reconstruction, or modification commenced after December 6, 2022, which
is the date of publication of the supplemental proposal for NSPS OOOOb.
In particular, this action finalizes changes to strengthen the
proposed VOC and methane standards addressing: fugitive emissions from
well sites; monitoring of control devices; super-emitters; storage
vessels; associated gas; pumps; equipment leaks at gas plants; appendix
K; centrifugal compressors; and reciprocating compressors. It generally
leaves unchanged the SO2 performance standard for sweetening
units and the VOC and methane performance standards for well
completions, gas well liquids unloading operations, process
controllers, and fugitive emissions from compressor stations. A summary
of the final BSER determination and final NSPS for affected sources for
which construction, reconstruction, or modification commenced after
December 6, 2022 (NSPS OOOOb), is presented in table 2. See sections X
and XI of this preamble for a complete discussion of the changes to the
BSER determination and NSPS requirements.
The final NSPS OOOOb also includes provisions for the use of
advanced methane detection technologies that allow for periodic
screening or continuous monitoring for fugitive emissions and emissions
from covers and closed vent systems (CVS) used to route emissions to
control devices. These advanced methane detection technologies could
also be used to identify super-emitter emissions events sooner and
outside the normal periodic OGI monitoring for fugitive emissions,
control devices, covers on storage vessels, and CVS. Therefore, the EPA
is finalizing a Super Emitter Program where an owner or operator must
investigate, and if necessary, take steps to ensure compliance with the
applicable regulation(s) upon receiving certified notifications of
detected emissions that are 100 kilograms per hour (kg/hr) of methane
or greater. See section X.C of this preamble for a complete discussion
of these final provisions.
2. EG for Sources Constructed Prior to December 6, 2022 (EG OOOOc)
As described in sections X and XI of this preamble, the EPA is
finalizing several changes to the BSER determinations and presumptive
standards that were proposed under the authority of CAA section 111(d)
in the November 2021 Proposal and/or the December 2022 Supplemental
Proposal. These changes are based on a review of new data made
available to the EPA and information provided in public comments. In
the November 2021 Proposal, the EPA proposed the first nationwide EG
for GHG (in the form of methane limitations) for the Crude Oil and
Natural Gas source category, including the production, processing, and
transmission and storage segments (EG OOOOc). In the December 2022
Supplemental Proposal, the EPA proposed key implementation information
unique to the EG for stakeholders.
This action finalizes revisions to strengthen the proposed
presumptive standards for methane addressing: fugitive emissions from
well sites; monitoring of control devices; super-emitters; storage
vessels; associated gas; pumps; equipment leaks at gas plants; appendix
K; centrifugal compressors; and reciprocating compressors. It generally
leaves unchanged the presumptive standards for gas well liquids
unloading operations, process controllers, and fugitive emissions from
compressor stations. A summary of the final BSER determination and
final presumptive standards for EG OOOOc is presented in table 3. See
section X of this preamble for a complete discussion of the changes to
the BSER determination and final presumptive standards.
The final EG OOOOc also includes the same provisions described for
NSPS OOOOb that allow for the use of alternative test methods using
advanced methane detection technologies for periodic screening or
continuous monitoring for fugitive emissions and emissions from covers
and CVS used to route emissions to control devices. Finally, the EPA is
also finalizing in the final EG OOOOc presumptive requirements for
state plans to include a Super Emitter Program, where an owner or
operator must investigate, and if necessary, take steps to ensure
compliance with the applicable regulation(s) upon receiving certified
notifications of detected emissions that are 100 kilograms per hour
(kg/hr) of methane or greater. See section X of this preamble for a
complete discussion of these final provisions.
[[Page 16829]]
As stated in the November 2021 Proposal \19\ and the December 2022
Supplemental Proposal,\20\ when the EPA establishes NSPS for a source
category, the EPA is required to issue EG to reduce emissions of
certain pollutants from existing sources in that same source category.
In such circumstances, under CAA section 111(d), the EPA must issue
regulations to establish procedures under which states submit plans to
establish, implement, and enforce standards of performance for existing
sources for certain air pollutants to which a Federal NSPS would apply
if such existing source were a new source. Thus, the issuance of CAA
section 111(d) final EG does not impose binding requirements directly
on existing sources but instead provides requirements for states in
developing their plans. There is a fundamental requirement under CAA
section 111(d) that a state's standards of performance in its state
plan submittal are no less stringent than the presumptive standard
determined by the EPA, which derives from the definition of ``standard
of performance'' in CAA section 111(a)(1). Further, as provided in CAA
section 111(d), a state may choose to take into account remaining
useful life and other factors (RULOF) in applying a standard of
performance to a particular source, consistent with the CAA, the EPA's
implementing regulations, and the final EG.
---------------------------------------------------------------------------
\19\ See 86 FR 63117 (November 15, 2021).
\20\ See 87 FR 74702 (December 6, 2022).
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The EPA is finalizing changes to the BSER determinations and the
degree of limitation achievable through application of the BSER for
certain existing equipment, processes, and activities across the Crude
Oil and Natural Gas source category. Those changes are discussed in
section X of this preamble. Section XIII of this preamble discusses the
components of EG, including the steps, requirements, and considerations
associated with the development, submittal, and implementation of
state, Tribal, and Federal plans, as appropriate. For the EG, the EPA
is translating the degree of emission limitation achievable through
application of the BSER (i.e., level of stringency) into presumptive
standards that states may use in the development of state plans for
specific designated facilities. In doing so, the EPA has formatted the
final EG OOOOc such that if a state chooses to adopt these presumptive
standards as the standards of performance in a state plan, the EPA
could approve such a plan as meeting the requirements of CAA section
111(d) and the finalized EG, if the plan meets all other applicable
requirements. In this way, the presumptive standards included in the
final EG OOOOc serve a function similar to that of a model rule,\21\
because they are intended to assist states in developing their plan
submissions by providing states with a starting point for standards
that are based on general industry parameters and assumptions. The EPA
anticipates that providing these presumptive standards will create a
streamlined approach for states in developing state plans and for the
EPA in evaluating state plans. However, the EPA's action on each state
plan submission is carried out via rulemaking, which includes public
notice and comment. Inclusion of presumptive standards in the final EG
does not predetermine the outcomes of any future rulemaking on state
plan submittals.
---------------------------------------------------------------------------
\21\ The presumptive standards are not the same as a Federal
plan under CAA section 111(d)(2). The EPA has an obligation to
promulgate a Federal plan if a state fails to submit a satisfactory
plan. In such circumstances, the final EG and presumptive standards
would serve as a guide to the development of a Federal plan. See
section XIII.F of this document for information on Federal plans.
---------------------------------------------------------------------------
Designated facilities located in Indian country would not be
encompassed within a state's CAA section 111(d) plan. Instead, an
eligible Tribe that has one or more designated facilities located in
its area of Indian country would have the opportunity, but not the
obligation, to seek authority and submit a plan that establishes
standards of performance for those facilities on its Tribal lands. If a
Tribe does not submit a plan, or if the EPA does not approve a Tribe's
plan, then the EPA has the authority to establish a Federal plan for
designated facilities located within that Tribe's area of Indian
country. A summary of the final EG for existing sources (EG OOOOc) for
the oil and natural gas sector is presented in table 4. See section X
of this preamble for a complete discussion of the final EG
requirements.
3. Final Amendments to 2016 NSPS OOOOa, and CRA-Related CFR Updates
The EPA is finalizing modifications to the 2016 NSPS OOOOa to
address certain amendments to the VOC standards for sources in the
production and processing segments finalized in the 2020 Technical
Rule. Because the methane standards for the production and processing
segments and all standards for the transmission and storage segment
were removed from the 2016 NSPS OOOOa via the 2020 Policy Rule prior to
the finalization of the 2020 Technical Rule, the latter amendments
apply only to the 2016 NSPS OOOOa VOC standards for the production and
processing segments. In this final rulemaking, the EPA also is applying
some of the 2020 Technical Rule amendments to the methane standards for
all industry segments and to VOC standards for the transmission and
storage segment in the 2016 NSPS OOOOa. These amendments are associated
with the requirements for well completions, pumps, closed vent systems,
fugitive emissions, alternative means of emission limitation (AMELs),
and onshore natural gas processing plants, as well as other technical
clarifications and corrections. The EPA is also finalizing a repeal of
the amendments in the 2020 Technical Rule that (1) exempted low
production well sites from monitoring fugitive emissions and (2)
changed monitoring of VOC emissions at gathering and boosting
compressor stations from quarterly to semiannual, which currently
applies only to VOC standards (not methane standards) from the
production and processing segments. A summary of the final amendments
to the 2016 OOOOa NSPS is presented in section XII of this preamble.
Lastly, in this rulemaking, the EPA updates the NSPS OOOO and OOOOa
provisions in the CFR to reflect the CRA resolution's disapproval of
the final 2020 Policy Rule, specifically, the reinstatement of the NSPS
OOOO and OOOOa requirements that the 2020 Policy Rule repealed but that
came back into effect immediately upon enactment of the CRA resolution.
The EPA waited to make the updates to the CFR text until the final
rulemaking because it would be more efficient and clearer to amend the
CFR once at the end of this rulemaking process to account for all
changes to the 2012 NSPS OOOO and 2016 NSPS OOOOa at the same time,
rather than make piecemeal amendments to the CFR.
[[Page 16830]]
Table 3--Summary of Final BSER and Final New Source Performance
Standards for GHGs and VOCs (NSPS OOOOb) \22\
------------------------------------------------------------------------
Final new source
performance
Affected source Final BSER standards for GHGs
and VOCs
------------------------------------------------------------------------
Fugitive Emissions: Single Quarterly AVO Quarterly AVO
Wellhead Only Well Sites and monitoring surveys. First
Small Well Sites. surveys. attempt at repair
within 15 days
after detecting
fugitive
emissions. Final
repair within 15
days after first
attempt.
Fugitive
monitoring
continues for all
well sites until
the site has been
closed, including
plugging the
wells at the site
and submitting a
well closure
report.
Fugitive Emissions: Multi- Quarterly AVO Quarterly AVO
wellhead Only Well Sites (2 or monitoring surveys. First
more wellheads). surveys. attempt at repair
AND............... within 15 days
Monitoring and after detecting
repair based on fugitive
semiannual emissions. Final
monitoring using repair within 15
OGI \2\. days after first
attempt.
Semiannual OGI
monitoring
(Optional
semiannual EPA
Method 21
monitoring with
500 ppm defined
as a leak).
First attempt at
repair within 30
days after
detecting
fugitive
emissions. Final
repair within 30
days after first
attempt.
Fugitive
monitoring
continues for all
well sites until
the site has been
closed, including
plugging the
wells at the site
and submitting a
well closure
report.
Fugitive Emissions: Well Sites Bimonthly AVO Bimonthly AVO
with Major Production and monitoring surveys. First
Processing Equipment and surveys (i.e., attempt at repair
Centralized Production every other within 15 days
Facilities. month). after detecting
AND............... fugitive
Monitoring and emissions. Final
repair based on repair within 15
quarterly days after first
monitoring using attempt.
OGI. AND
Well sites with
specified major
production and
processing
equipment:
Quarterly OGI
monitoring.
(Optional
quarterly EPA
Method 21
monitoring with
500 ppm defined
as a leak).
First attempt at
repair within 30
days after
detecting
fugitive
emissions. Final
repair within 30
days after first
attempt.
Fugitive
monitoring
continues for all
well sites until
the site has been
closed, including
plugging the
wells at the site
and submitting a
well closure
report.
Fugitive Emissions: Compressor Monthly AVO Monthly AVO
Stations. monitoring surveys. First
surveys. attempt at repair
AND............... within 15 days
Monitoring and after detecting
repair based on fugitive
quarterly emissions. Final
monitoring using repair within 15
OGI. days after first
attempt.
AND
Quarterly OGI
monitoring.
(Optional
quarterly EPA
Method 21
monitoring with
500 ppm defined
as a leak).
First attempt at
repair within 30
days after
detecting
fugitive
emissions. Final
repair within 30
days after first
attempt.
Fugitive Emissions: Well Sites Monitoring and Annual OGI
and Compressor Stations on repair based on monitoring.
Alaska North Slope. annual monitoring (Optional annual
using OGI. EPA Method 21
monitoring with
500 ppm defined
as a leak).
First attempt at
repair within 30
days after
detecting
fugitive
emissions. Final
repair within 30
days after first
attempt.
Storage Vessels: A Single Capture and route 95 percent
Storage Vessel or Tank Battery to a control reduction of VOC
with PTE \4\ of 6 tpy or more device. and methane.
of VOC or PTE of 20 tpy or more
of methane.
Process Controllers: Natural Gas- Use of zero- VOC and GHG
driven. emissions (methane)
controllers. emission rate of
zero.
Process Controllers: Alaska (at Use of low-bleed Natural gas bleed
sites where onsite power is not process rate no greater
available--continuous bleed controllers. than 6 scfh.\5\
natural gas-driven).
Process Controllers: Alaska (at Monitor and repair OGI monitoring and
sites where onsite power is not through fugitive repair of
available--intermittent natural emissions program. emissions from
gas-driven). controller
malfunctions.
[[Page 16831]]
Well Liquids Unloading.......... Best management Perform best
practices to management
minimize or practices to
eliminate methane minimize or
and VOC emissions eliminate methane
to the maximum and VOC emissions
extent possible. to the maximum
extent possible
from liquids
unloading events
that vent
emissions to the
atmosphere.
Wet Seal Centrifugal Compressors Capture and route 95 percent
(except for those located at emissions from reduction of
well sites). the wet seal methane and VOC
fluid degassing emissions.
system to a
control device.
Wet Seal Centrifugal Compressors (Optional) Monitoring and
(except for those located at Monitoring and repair to
well sites): Self-contained repair to maintain
centrifugal compressors and wet maintain volumetric flow
seal compressors equipped with volumetric flow rate at or below
a mechanical seal. rate at or below 3 scfm per
3 scfm. compressor seal.
Wet Seal Centrifugal Compressors (Optional) Monitoring and
(except for those located at Monitoring and repair to
well sites): Alaska North Slope repair to maintain
centrifugal compressors maintain volumetric flow
equipped with a seal oil volumetric flow rate at or below
recovery system. rate at or below 9 scfm per
9 scfm per seal. compressor seal.
Dry Seal Centrifugal Compressors Monitoring and Monitoring and
(except for those located at repair to repair of seal to
well sites). maintain maintain
volumetric flow volumetric flow
rate at or below rate at or below
10 scfm \7\ per 10 scfm per
seal. compressor seal.
Reciprocating Compressors Monitoring and Monitoring and
(except for those located at repair or replace repair or
well sites). the reciprocating replacement of
compressor rod rod packing to
packing in order maintain
to maintain volumetric flow
volumetric flow rate at or below
rate at or below 2 scfm per
2 scfm per cylinder.
cylinder.
Pumps: Natural gas-driven....... Use of zero- GHG (methane) and
emissions pumps. VOC emission rate
of zero.
Pumps: Natural gas-driven (at Use of an existing Route pump
sites where onsite power is not VRU or control emissions to a
available and there are fewer device. process if VRU is
than 3 diaphragm pumps). onsite, or to
control device if
onsite.
Well Completions: Subcategory 1 Combination of REC Applies to each
(non-wildcat and non- \8\ and the use well completion
delineation wells). of a completion operation with
combustion device. hydraulic
fracturing.
REC in combination
with a completion
combustion
device; venting
in lieu of
combustion where
combustion would
present
demonstrable
safety hazards.
Initial flowback
stage: Route to a
storage vessel or
completion vessel
(frac tank, lined
pit, or other
vessel) and
separator.
Separation
flowback stage:
Route all salable
gas from the
separator to a
flow line or
collection
system, reinject
the gas into the
well or another
well, use the gas
as an onsite fuel
source or use for
another useful
purpose that a
purchased fuel or
raw material
would serve. If
technically
infeasible to
route recovered
gas as specified,
recovered gas
must be
combusted. All
liquids must be
routed to a
storage vessel or
well completion
vessel,
collection
system, or be
reinjected into
the well or
another well.
The operator is
required to have
(and use) a
separator onsite
during the entire
flowback period.
[[Page 16832]]
Well Completions: Subcategory 2 Use of a Applies to each
(exploratory, wildcat, and completion well completion
delineation wells and non- combustion device. operation with
wildcat and non-delineation low- hydraulic
pressure wells). fracturing.
The operator is
not required to
have a separator
onsite. Either:
(1) Route all
flowback to a
completion
combustion device
with a continuous
pilot flame; or
(2) Route all
flowback into one
or more well
completion
vessels and
commence
operation of a
separator unless
it is technically
infeasible for a
separator to
function. Any gas
present in the
flowback before
the separator can
function is not
subject to
control under
this section.
Capture and
direct recovered
gas to a
completion
combustion device
with a continuous
pilot flame.
For both options
(1) and (2),
combustion is not
required in
conditions that
may result in a
fire hazard or
explosion, or
where high heat
emissions from a
completion
combustion device
may negatively
impact tundra,
permafrost, or
waterways.
Equipment Leaks at Natural Gas LDAR \9\ with LDAR with OGI
Processing Plants. bimonthly OGI. following
procedures in
appendix K.
New Wells with Associated Gas Route associated Route associated
that commenced construction gas to a sales gas to a sales
after May 7, 2026. line. line; or, the gas
can be used for
another useful
purpose that a
purchased fuel,
chemical
feedstock, or raw
material would
serve, or
recovered from
the separator and
reinjected into
the well or
injected into
another well.
New wells with Associated Gas Route associated Route associated
that commenced construction gas to a sales gas to a sales
between May 7, 2024, and May 7, line. line; or, the gas
2026. can be used for
another useful
purpose that a
purchased fuel,
chemical
feedstock, or raw
material would
serve, or
recovered from
the separator and
reinjected into
the well or
injected into
another well. If
demonstrated, and
documented
annually, that
routing to a
sales line and
the alternatives
are not
technically
feasible, the
associated gas
can be routed to
a flare or other
control device
that achieves at
least 95 percent
reduction in GHG
(methane) and VOC
emissions. A
second
infeasibility
determination may
not extend beyond
24 months from
effective date.
New Wells with Associated Gas Route associated Route associated
that Commenced Construction gas to a sales gas to a sales
after December 6, 2022, and line. line; or, the gas
before May 7, 2024. can be used for
another useful
purpose that a
purchased fuel,
chemical
feedstock, or raw
material would
serve, or
recovered from
the separator and
reinjected into
the well or
injected into
another well. If
demonstrated, and
documented
annually, that
routing to a
sales line and
the alternatives
are not
technically
feasible, the
associated gas
can be routed to
a flare or other
control device
that achieves at
least 95 percent
reduction in GHG
(methane) and VOC
emissions.
[[Page 16833]]
Wells with Associated Gas Route associated Route associated
Reconstructed or Modified after gas to a sales gas to a sales
December 6, 2022. line. line; or, the gas
can be used for
another useful
purpose that a
purchased fuel,
chemical
feedstock, or raw
material would
serve, or
recovered from
the separator and
reinjected into
the well or
injected into
another well. If
demonstrated, and
documented
annually, that
routing to a
sales line and
the alternatives
are not
technically
feasible, the
associated gas
can be routed to
a flare or other
control device
that achieves at
least 95 percent
reduction in GHG
(methane) and VOC
emissions.
Sweetening Units................ Achieve SO2 Achieve required
emission minimum SO2
reduction emission
efficiency. reduction
efficiency.
------------------------------------------------------------------------
\1\ tpy (tons per year).
\2\ OGI (optical gas imaging).
\3\ ppm (parts per million).
\4\ PTE (potential to emit).
\5\ scfh (standard cubic feet per hour).
\6\ BMP (best management practices).
\7\ scfm (standard cubic feet per minute).
\8\ REC (reduced emissions completion).
\9\ LDAR (leak detection and repair).
---------------------------------------------------------------------------
\22\ For fugitive emissions at well sites,centralized production
facilities, and compressor stations, the EPA is finalizing an
advanced measurement technology compliance option to use alternative
periodic screening and alternative continuous monitoring instead of
OGI and AVO monitoring.
Table 4--Summary of Final BSER and Final Presumptive Standards for GHGs
From Designated Facilities (EG OOOOc) \23\
------------------------------------------------------------------------
Final presumptive
Designated facility Final BSER standards for GHGs
------------------------------------------------------------------------
Fugitive Emissions: Single Quarterly AVO Quarterly AVO
Wellhead Only Well Sites and monitoring surveys. First
Small Well Sites. surveys. attempt at repair
within 15 days
after detecting
fugitive
emissions. Final
repair within 15
days after first
attempt.
Fugitive
monitoring
continues for all
well sites until
the site has been
closed, including
plugging the
wells at the site
and submitting a
well closure
report.
Fugitive Emissions: Multi- Quarterly AVO Quarterly AVO
wellhead Only Well Sites (2 or monitoring surveys. First
more wellheads). surveys. attempt at repair
within 15 days
after detecting
fugitive
emissions. Final
repair within 15
days after first
attempt.
AND Semiannual OGI
monitoring
(Optional semi-
Monitoring and annual EPA Method
repair based on 21 monitoring
semiannual with 500 ppm
monitoring using defined as a
OGI\2\. leak).
First attempt at
repair within 30
days after
detecting
fugitive
emissions. Final
repair within 30
days after first
attempt.
Fugitive
monitoring
continues for all
well sites until
the site has been
closed, including
plugging the
wells at the site
and submitting a
well closure
report.
Fugitive Emissions: Well Sites Bimonthly AVO Bimonthly AVO
and Centralized Production monitoring surveys. First
Facilities. surveys (i.e., attempt at repair
every other within 15 days
month). after detecting
fugitive
emissions. Final
repair within 15
days after first
attempt.
AND AND
Monitoring and Well sites with
repair based on specified major
quarterly production and
monitoring using processing
OGI. equipment:
Quarterly OGI
monitoring.
(Optional
quarterly EPA
Method 21
monitoring with
500 ppm defined
as a leak).
[[Page 16834]]
First attempt at
repair within 30
days after
finding fugitive
emissions. Final
repair within 30
days after first
attempt.
Fugitive
monitoring
continues for all
well sites until
the site has been
closed, including
plugging the
wells at the site
and submitting a
well closure
report.
Fugitive Emissions: Compressor Monthly AVO Monthly AVO
Stations. monitoring surveys. First
surveys. attempt at repair
within 15 days
after detecting
fugitive
emissions. Final
repair within 15
days after first
attempt.
AND AND
Monitoring and Quarterly OGI
repair based on monitoring.
quarterly (Optional
monitoring using quarterly EPA
OGI. Method 21
monitoring with
500 ppm defined
as a leak).
First attempt at
repair within 30
days after
detecting
fugitive
emissions. Final
repair within 30
days after first
attempt.
Fugitive Emissions: Well Sites Monitoring and Annual OGI
and Compressor Stations on repair based on monitoring.
Alaska North Slope. annual monitoring (Optional annual
using OGI. EPA Method 21
monitoring with
500 ppm defined
as a leak).
First attempt at
repair within 30
days after
finding fugitive
emissions. Final
repair within 30
days after first
attempt.
Storage Vessels: Tank Battery Capture and route 95 percent
with PTE of 20 tpy or More of to a control reduction of
Methane. device. methane.
Process Controllers: Natural gas- Use of zero- GHG (methane)
driven. emissions emission rate of
controllers. zero.
Process Controllers: Alaska (at Use of low-bleed Natural gas bleed
sites where onsite power is not process rate no greater
available--continuous bleed controllers. than 6 scfh.
natural gas-driven).
Process Controllers: Alaska (at Monitor and repair OGI monitoring and
sites where onsite power is not through fugitive repair of
available--intermittent natural emissions program. emissions from
gas-driven). controller
malfunctions.
Gas Well Liquids Unloading...... Best management Perform best
practices to management
minimize or practices to
eliminate methane minimize or
and VOC emissions eliminate methane
to the maximum and VOC emissions
extent possible. to the maximum
extent possible
from liquids
unloading events
that vent
emissions to the
atmosphere.
Wet Seal Centrifugal Compressors Monitoring and Monitoring and
(except for those located at repair to repair to
well sites). maintain maintain
volumetric flow volumetric flow
rate at or below rate at or below
3 scfm\7\. 3 scfm per seal.
Wet Seal Centrifugal Compressors Monitoring and Monitoring and
(except for those located at repair to repair to
well sites): Self-contained maintain maintain
centrifugal compressors and wet volumetric flow volumetric flow
seal compressors equipped with rate at or below rate at or below
a mechanical seal. 3 scfm. 3 scfm per seal.
Wet Seal Centrifugal Compressors Monitoring and Monitoring and
(except for those located at repair to repair to
well sites): Alaska North Slope maintain maintain
centrifugal compressors volumetric flow volumetric flow
equipped with a seal oil rate at or below rate at or below
recovery system. 9 scfm. 9 scfm per seal.
Dry Seal Centrifugal Compressors Monitoring and Monitoring and
(except for those located at repair to repair to
well sites). maintain maintain
volumetric flow volumetric flow
rate at or below rate at or below
10 scfm\7\. 10 scfm per seal.
Reciprocating Compressors Monitoring and Monitoring and
(except for those located at repair or replace repair to
well sites). the reciprocating maintain
compressor rod volumetric flow
packing in order rate at or below
to maintain 2 scfm per
volumetric flow cylinder.
rate at or below
2 scfm.
Pumps: Natural gas-driven....... Use of zero- GHG (methane)
emissions pumps. emission rate of
zero.
Pumps: Natural gas-driven (at Use of an existing Route pump
sites where onsite power is not VRU or control emissions to a
available and there are fewer device. process if VRU is
than 3 diaphragm pumps). onsite, or to
control device if
onsite.
Equipment Leaks at Natural Gas LDAR with LDAR with OGI
Processing Plants. bimonthly OGI. following
procedures in
appendix K.
[[Page 16835]]
Wells with Associated Gas Route associated Route associated
greater than 40 tpy methane. gas to a sales gas to a sales
line. line.
Alternatively,
the gas can be
used as an onsite
fuel source or
used for another
useful purpose
that a purchased
fuel or raw
material would
serve, or be
injected into the
well or another
well. If
demonstrated, and
annually
documented, that
a sales line and
alternatives are
not technically
feasible, the gas
can be routed to
a flare or other
control device
that achieves at
least 95 percent
reduction in
methane
emissions.
Wells with Associated Gas 40 tpy Route associated Route associated
methane or less. gas to a flare or gas to a sales
other control line.
device that Alternatively,
achieves at least the gas can be
95 percent used as an onsite
reduction in fuel source or
methane emissions. used for another
useful purpose
that a purchased
fuel or raw
material would
serve, or be
injected into the
well or another
well.
Alternatively,
the gas can be
routed to a flare
or other control
device that
achieves at least
95 percent
reduction in
methane
emissions.
------------------------------------------------------------------------
C. Costs and Benefits
---------------------------------------------------------------------------
\23\ For fugitive emissions at well sites, centralized
production facilities, and compressor stations, the EPA is
finalizing an advanced measurement technology compliance option to
use alternative periodic screening and alternative continuous
monitoring instead of OGI and AVO monitoring.
---------------------------------------------------------------------------
In accordance with the requirements of E.O. 12866, the EPA
projected the emissions reductions, costs, and benefits that may result
from this final rulemaking. These results are presented in detail in
the RIA accompanying this final rulemaking developed in response to
E.O. 12866. The RIA focuses on the elements of the final rules that are
likely to result in quantifiable cost or emissions changes compared to
a baseline without the rule. We estimated the cost, emissions, and
benefit impacts for the 2024 to 2038 period. We present the present
value (PV) and equivalent annual value (EAV) of costs, benefits, and
net benefits of this rulemaking in 2019 dollars.
The initial analysis year in the RIA is 2024 as we assume the NSPS
rules will take effect early in 2024. The EG will take longer to go
into effect as states will need to develop implementation plans in
response to the EG and have them approved by the EPA. We assume in the
RIA that this process will take 4 years, and so EG impacts will begin
in 2028. The final analysis year is 2038, which allows us to provide up
to 15 years of projected impacts after the NSPS is assumed to take
effect and 11 years of projected impacts after the EG is assumed to
take effect.
The cost analysis presented in the RIA reflects a nationwide
engineering analysis of compliance cost and emissions reductions, of
which there are two main components. The first component is a set of
representative or model plants for each regulated facility, segment,
and control option. The characteristics of the model plant include
typical equipment, operating characteristics, and representative
factors including baseline emissions and the costs, emissions
reductions, and product recovery resulting from each control option.
The second component is a set of projections of activity data for
affected facilities, distinguished by vintage, year, and other
necessary attributes (e.g., oil versus natural gas wells). Impacts are
calculated by setting parameters on how and when affected facilities
are assumed to respond to a particular regulatory regime, multiplying
activity data by model plant cost and emissions estimates, differencing
from the baseline scenario, and then summing to the desired level of
aggregation. In addition to emissions reductions, some control options
result in natural gas recovery, which can then be combusted in
production or sold. Where applicable, we present projected compliance
costs with and without the projected revenues from product recovery.
The EPA expects climate and health benefits due to the emissions
reductions projected under this final rulemaking. The EPA estimated the
monetized climate benefits of methane emission reductions expected from
these final rules using estimates of the social cost of methane (SC-
CH4) that reflect recent advances in the scientific
literature on climate change and its economic impacts and incorporate
recommendations made by the National Academies of Science, Engineering,
and Medicine (National Academies 2017). The EPA presented these
estimates in a sensitivity analysis in the December 2022 RIA, solicited
public comment on the methodology and use of these estimates, and has
conducted an external peer review of these estimates, as discussed in
section XVI.E of this preamble.
In addition to climate benefits from methane emissions reductions,
the EPA expects that VOC emission reductions under the final rulemaking
will improve air quality and improve health and welfare due to reduced
exposure to ozone, particulate matter with a diameter of 2.5
micrometers or less (PM2.5), and hazardous air pollutants
(HAP). In a national-level analysis of public health impacts, the EPA
used the environmental Benefits Mapping and Analysis Program--Community
Edition (BenMAP-CE) software program to quantify counts of premature
deaths and illnesses attributable to photochemical modeled changes in
summer season average ozone concentrations resulting from projected VOC
emissions reductions under the rulemaking. The methods for quantifying
the number and value of air pollution-attributable premature deaths and
illnesses are described in the RIA for this action and the TSD titled
Estimating PM2.5- and Ozone-Attributable Health
Benefits.\24\ These reductions in health-harming pollution would result
in significant public health benefits including avoided
[[Page 16836]]
premature deaths, reductions in new asthma cases and incidences of
asthma symptoms, reductions in hospital admissions and emergency
department visits, and reductions in lost school days.
---------------------------------------------------------------------------
\24\ https://www.epa.gov/system/files/documents/2023-01/Estimating%20PM2.5-%20and%20Ozone-Attributable%20Health%20Benefits%20TSD_0.pdf.
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The EPA notes that the benefits analysis is distinct from the
statutory BSER determinations finalized herein, which are based on the
statutory factors the EPA is required to consider under section 111(a)
of the CAA (including cost, energy requirements and nonair quality
health, and environmental impacts). The assessment of benefits
described above and in the RIA is presented solely for the purposes of
complying with E.O. 12866 and providing the public with a complete
depiction of the impacts of the rulemaking.
The projected national-level emissions reductions over the 2024 to
2038 period anticipated under the finalized requirements are presented
in table 5. Table 6 presents the PV and EAV of the projected benefits,
costs, and net benefits over the 2024 to 2038 period under the final
rule using discount rates of 2, 3, and 7 percent.
Table 5--Projected Emissions Reductions Under the Final Rules, 2024-2038
Total
------------------------------------------------------------------------
Emissions reductions
Pollutant (2024-2038 total)
------------------------------------------------------------------------
Methane (million short tons) \a\.................. 58
VOC (million short tons).......................... 16
Hazardous Air Pollutant (million short tons)...... 0.59
Methane (million metric tons CO2 Eq.) \b\......... 1,500
------------------------------------------------------------------------
\a\ To convert from short tons to metric tons, multiply the short tons
by 0.907. Alternatively, to convert metric tons to short tons,
multiply metric tons by 1.102.
\b\ Carbon dioxide equivalent (CO2 Eq). calculated using a global
warming potential of 28.
Table 6--Benefits, Costs, Net Benefits, and Emissions Reductions Under the Final Rules, 2024-2038
[Dollar Estimates in Millions of 2019 Dollars] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
2 Percent near-term Ramsey discount rate
-----------------------------------------------------------------------------------------------
PV EAV PV EAV PV EAV
--------------------------------------------------------------------------------------------------------------------------------------------------------
Climate Benefits \b\.................................... $110,000 $8,500 $110,000 $8,500 $110,000 $8,500
--------------------------------------------------------------------------------------------------------------------------------------------------------
2 Percent discount rate 3 Percent discount rate 7 Percent discount rate
-----------------------------------------------------------------------------------------------
PV EAV PV EAV PV EAV
--------------------------------------------------------------------------------------------------------------------------------------------------------
Ozone Health Benefits \c\............................... $7,000 $540 $6,100 $510 $3,500 $380
Net Compliance Costs.................................... 19,000 1,500 18,000 1,500 14,000 1,600
Compliance Costs........................................ 31,000 2,400 29,000 2,400 22,000 2,400
Value of Product Recovery............................... 13,000 980 11,000 950 7,400 820
Net Benefits \d\........................................ 97,000 7,600 97,000 7,500 98,000 7,300
--------------------------------------------------------------------------------------------------------------------------------------------------------
Non-Monetized Benefits.................................. Climate and ozone-related health benefits from reducing 58 million short tons of methane from
2024 to 2038.
Benefits to provision of ecosystem services associated with reduced ozone concentrations from
reducing 16 million short tons of VOC from 2024 to 2038.
PM2.5-related health benefits from reducing 16 million short tons of VOC from 2024 to 2038.
HAP benefits from reducing 590 thousand short tons of HAP from 2024 to 2038.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures. Totals may not appear to add correctly due to rounding.
\b\ Climate benefits are based on reductions in methane emissions and are calculated using three different estimates of the SC-CH4 (under 1.5 percent,
2.0 percent, and 2.5 percent near-term Ramsey discount rates). For the presentational purposes of this table, we show the climate benefits associated
with the SC-CH4 at the 2 percent near-term Ramsey discount rate. Please see tables 3.4 and 3.5 in the RIA for the full range of monetized climate
benefit estimates. All net benefits are calculated using climate benefits discounted at the 2 percent near-term rate.
\c\ Monetized benefits include those related to public health associated with reductions in ozone concentrations. The health benefits are associated
with several point estimates.
\d\ Several categories of climate, human health, and welfare benefits from methane, VOC, and HAP emissions reductions remain unmonetized and are thus
not directly reflected in the quantified benefit estimates in the table.
III. Air Emissions From the Crude Oil and Natural Gas Sector and Public
Health and Welfare
A. Impacts of GHGs, VOCs, and SO2 Emissions on Public Health
and Welfare
As noted previously, the oil and natural gas industry emits a wide
range of pollutants, including GHGs (such as methane and
CO2), VOCs, SO2, NOX, H2S,
CS2, and COS. See 49 FR 2636, 2637 (January 20, 1984). As
noted below, to this point the EPA has focused its regulatory efforts
under CAA section 111 on GHGs, VOC, and SO2.\25\
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\25\ We note that the EPA's focus on GHGs (in particular
methane), VOC, and SO2 in these analyses does not in any
way limit the EPA's authority to promulgate standards that would
apply to other pollutants emitted from the Crude Oil and Natural Gas
source category, if the EPA determines in the future that such
action is appropriate.
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1. Climate Change Impacts From GHGs Emissions
Elevated concentrations of GHGs are and have been warming the
planet, leading to changes in the Earth's climate including changes in
the frequency and intensity of heat waves, precipitation, and extreme
weather events; rising seas; and retreating snow and ice. The changes
taking place in the atmosphere as a result of the well-documented
[[Page 16837]]
buildup of GHGs due to human activities are changing the climate at a
pace and in a way that threatens human health, society, and the natural
environment. Human-produced GHGs, largely derived from our reliance on
fossil fuels, are causing serious and life-threatening environmental
and health impacts. While the EPA is not making any new scientific or
factual findings with regard to the well-documented impact of GHG
emissions on public health and welfare in support of this rulemaking,
the EPA is providing some scientific background on climate change to
offer additional context for this rulemaking and to increase the
public's understanding of the environmental impacts of GHGs.
Extensive additional information on climate change is available in
the scientific assessments and the EPA documents that are briefly
described in this section of this preamble, as well as in the technical
and scientific information supporting them. One of those documents is
the EPA's 2009 Endangerment and Cause or Contribute Findings for GHGs
Under Section 202(a) of the CAA (74 FR 66496, December 15, 2009).\26\
In the 2009 Endangerment Findings, the Administrator found under
section 202(a) of the CAA that elevated atmospheric concentrations of
six key well-mixed GHGs--CO2, methane, N2O, HFCs,
perfluorocarbons (PFCs), and sulfur hexafluoride (SF6)--
``may reasonably be anticipated to endanger the public health and
welfare of current and future generations'' (74 FR 66523, December 15,
2009), and the science and observed changes since that time have
confirmed and strengthened the understanding and concerns regarding the
climate risks considered in the Findings. The 2009 Endangerment
Findings, together with the extensive scientific and technical evidence
in the supporting record, documented that climate change caused by
human emissions of GHGs threatens the public health of the U.S.
population. It explained that by raising average temperatures, climate
change increases the likelihood of heat waves, which are associated
with increased deaths and illnesses (74 FR 66497, December 15, 2009).
While climate change also increases the likelihood of reductions in
cold-related mortality, evidence indicates that the increases in heat
mortality will be larger than the decreases in cold mortality in the
U.S. (74 FR 66525, December 15, 2009). The 2009 Endangerment Findings
further explained that compared to a future without climate change,
climate change is expected to increase tropospheric ozone pollution
over broad areas of the U.S., including in the largest metropolitan
areas with the worst tropospheric ozone problems, and thereby increase
the risk of adverse effects on public health (74 FR 66525, December 15,
2009). Climate change is also expected to cause more intense
hurricanes, and more frequent and intense storms of other types, and
heavy precipitation, with impacts on other areas of public health such
as the potential for increased deaths, injuries, infectious and
waterborne diseases, and stress-related disorders (74 FR 66525,
December 15, 2009). Children, the elderly, and the poor are among the
most vulnerable to these climate-related health effects (74 FR 66498,
December 15, 2009).
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\26\ In describing these 2009 Findings in this proposal, the EPA
is neither reopening nor revisiting them.
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The 2009 Endangerment Findings also documented, together with the
extensive scientific and technical evidence in the supporting record,
that climate change touches nearly every aspect of public welfare \27\
in the U.S. with resulting economic costs, including: changes in water
supply and quality due to increased frequency of drought and extreme
rainfall events; increased risk of storm surge and flooding in coastal
areas and land loss due to inundation; increases in peak electricity
demand and risks to electricity infrastructure; and the potential for
significant agricultural disruptions and crop failures (though offset
to some extent by carbon fertilization). These impacts are also global
and may exacerbate problems outside the U.S. that raise humanitarian,
trade, and national security issues for the U.S. (74 FR 66530, December
15, 2009).
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\27\ The CAA states in section 302(h) that ``[a]ll language
referring to effects on welfare includes, but is not limited to,
effects on soils, water, crops, vegetation, manmade materials,
animals, wildlife, weather, visibility, and climate, damage to and
deterioration of property, and hazards to transportation, as well as
effects on economic values and on personal comfort and well-being,
whether caused by transformation, conversion, or combination with
other air pollutants.'' 42 U.S.C. 7602(h).
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In 2016, the Administrator similarly issued Endangerment and Cause
or Contribute Findings for GHG emissions from aircraft under section
231(a)(2)(A) of the CAA (81 FR 54422, August 15, 2016).\28\ In the 2016
Endangerment Findings, the Administrator found that the body of
scientific evidence amassed in the record for the 2009 Endangerment
Findings compellingly supported a similar endangerment finding under
CAA section 231(a)(2)(A) and also found that the science assessments
released between the 2009 and the 2016 Findings ``strengthen and
further support the judgment that GHGs in the atmosphere may reasonably
be anticipated to endanger the public health and welfare of current and
future generations.'' (81 FR 54424, August 15, 2016).
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\28\ In describing these 2016 Findings in this proposal, the EPA
is neither reopening nor revisiting them.
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Since the 2016 Endangerment Findings, the climate has continued to
change, with new records being set for several climate indicators such
as global average surface temperatures, GHG concentrations, and sea
level rise. Moreover, heavy precipitation events have increased in the
eastern U.S. while agricultural and ecological drought has increased in
the western U.S. along with more intense and larger wildfires.\29\
These and other trends are examples of the risks discussed the 2009 and
2016 Endangerment Findings that have already been experienced.
Additionally, major scientific assessments continue to demonstrate
advances in our understanding of the climate system and the impacts
that GHGs have on public health and welfare both for current and future
generations. These updated observations and projections document the
rapid rate of current and future climate change both globally and in
the U.S. These assessments include:
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\29\ See later in this section of the document for specific
examples. An additional resource for indicators can be found at
https://www.epa.gov/climate-indicators.
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[[Page 16838]]
U.S. Global Change Research Program's (USGCRP) 2016
Climate and Health Assessment \30\ and 2017-2018 Fourth National
Climate Assessment (NCA4) 31 32
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\30\ USGCRP, 2016: The Impacts of Climate Change on Human Health
in the United States: A Scientific Assessment. Crimmins, A., J.
Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J. Eisen,
N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M. Mills, S.
Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S. Global Change
Research Program, Washington, DC, 312 pp.
\31\ USGCRP, 2017: Climate Science Special Report: Fourth
National Climate Assessment, Volume I [Wuebbles, D.J., D.W. Fahey,
K.A. Hibbard, D.J. Dokken, B.C. Stewart, and T.K. Maycock (eds.)].
U.S. Global Change Research Program, Washington, DC, USA, 470 pp,
doi: 10.7930/J0J964J6.
\32\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller,
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, 1515 pp. doi:10.7930/NCA4.2018.
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IPCC's 2018 Global Warming of 1.5 [deg]C,\33\ 2019 Climate
Change and Land,\34\ and the 2019 Ocean and Cryosphere in a Changing
Climate \35\ assessments, as well as the 2023 IPCC Sixth Assessment
Report (AR6).\36\
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\33\ IPCC, 2018: Global Warming of 1.5 [deg]C. An IPCC Special
Report on the impacts of global warming of 1.5 [deg]C above pre-
industrial levels and related global greenhouse gas emission
pathways, in the context of strengthening the global response to the
threat of climate change, sustainable development, and efforts to
eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. P[ouml]rtner,
D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C.
P[eacute]an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X.
Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T.
Waterfield (eds.)].
\34\ IPCC, 2019: Climate Change and Land: an IPCC special report
on climate change, desertification, land degradation, sustainable
land management, food security, and greenhouse gas fluxes in
terrestrial ecosystems [P.R. Shukla, J. Skea, E. Calvo Buendia, V.
Masson-Delmotte, H.-O. P[ouml]rtner, D. C. Roberts, P. Zhai, R.
Slade, S. Connors, R. van Diemen, M. Ferrat, E. Haughey, S. Luz, S.
Neogi, M. Pathak, J. Petzold, J. Portugal Pereira, P. Vyas, E.
Huntley, K. Kissick, M. Belkacemi, J. Malley, (eds.)].
\35\ IPCC, 2019: IPCC Special Report on the Ocean and Cryosphere
in a Changing Climate [H.-O. P[ouml]rtner, DC Roberts, V. Masson-
Delmotte, P. Zhai, M. Tignor, E. Poloczanska, K. Mintenbeck, A.
Alegr[iacute]a, M. Nicolai, A. Okem, J. Petzold, B. Rama, N.M. Weyer
(eds.)].
\36\ IPCC, 2023: Summary for Policymakers. In: Climate Change
2023: Synthesis Report. Contribution of Working Groups I, II and III
to the Sixth Assessment Report of the Intergovernmental Panel on
Climate Change [Core Writing Team, H. Lee and J. Romero (eds.)].
IPCC, Geneva, Switzerland, pp. 1-34, doi:10.59327/IPCC/AR6-
9789291691647.001.
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The NAS 2016 Attribution of Extreme Weather Events in the
Context of Climate Change,\37\ 2017 Valuing Climate Damages: Updating
Estimation of the Social Cost of Carbon Dioxide,\38\ and 2019 Climate
Change and Ecosystems \39\ assessments.
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\37\ National Academies of Sciences, Engineering, and Medicine.
2016. Attribution of Extreme Weather Events in the Context of
Climate Change. Washington, DC: The National Academies Press.
https://dio.org/10.17226/21852.
\38\ National Academies of Sciences, Engineering, and Medicine.
2017. Valuing Climate Damages: Updating Estimation of the Social
Cost of Carbon Dioxide. Washington, DC: The National Academies
Press. https://doi.org/10.17226/24651.
\39\ National Academies of Sciences, Engineering, and Medicine.
2019. Climate Change and Ecosystems. Washington, DC: The National
Academies Press. https://doi.org/10.17226/25504.
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National Oceanic and Atmospheric Administration's (NOAA)
annual State of the Climate reports published by the Bulletin of the
American Meteorological Society,\40\ most recently in 2022.
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\40\ Blunden, J. and T. Boyer, Eds., 2022: ``State of the
Climate in 2021''. Bull. Amer. Meteor. Soc., 103 (8), Si-S465,
https://doi.org/10.1175/2022BAMSStateoftheClimate.1.
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EPA Climate Change and Social Vulnerability in the United
States: A Focus on Six Impacts (2021).\41\
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\41\ EPA. 2021. Climate Change and Social Vulnerability in the
United States: A Focus on Six Impacts. U.S. Environmental Protection
Agency, EPA 430-R-21-003.
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The most recent information demonstrates that the climate is
continuing to change in response to the human-induced buildup of GHGs
in the atmosphere. These recent assessments show that atmospheric
concentrations of GHGs have risen to a level that has no precedent in
human history and that they continue to climb, primarily because of
both historical and current anthropogenic emissions, and that these
elevated concentrations endanger our health by affecting our food and
water sources, the air we breathe, the weather we experience, and our
interactions with the natural and built environments. For example,
atmospheric concentrations of one of these GHGs, CO2,
measured at Mauna Loa in Hawaii and at other sites around the world
reached 419 parts per million (ppm) in 2022 (nearly 50 percent higher
than preindustrial levels) \42\ and have continued to rise at a rapid
rate. Global average temperature has increased by about 1.1 [deg]C (2.0
[deg]F) in the 2011-2020 decade relative to 1850-1900.\43\ The years
2015-2021 were the warmest 7 years in the 1880-2021 record,
contributing to the warmest decade on record with a decadal temperature
of 0.82 [deg]C (1.48 [deg]F) above the 20th century.44 45
The IPCC determined (with medium confidence) that this past decade was
warmer than any multi-century period in at least the past 100,000
years.\46\ Global average sea level has risen by about 8 inches (about
21 centimeters (cm)) from 1901 to 2018, with the rate from 2006 to 2018
(0.15 inches/year or 3.7 millimeters (mm)/year) almost twice the rate
over the 1971 to 2006 period, and three times the rate of the 1901 to
2018 period.\47\ The rate of sea level rise over the 20th century was
higher than in any other century in at least the last 2,800 years.\48\
Higher CO2 concentrations have led to acidification of the
surface ocean in recent decades to an extent unusual in the past 2
million years, with negative impacts on marine organisms that use
calcium carbonate to build shells or skeletons.\49\ Arctic sea ice
extent continues to decline in all months of the year; the most rapid
reductions occur in September (very likely almost a 13 percent decrease
per decade between 1979 and 2018) and are unprecedented in at least
1,000 years.\50\ Human-induced climate change has led to heatwaves and
heavy precipitation becoming more frequent and more intense, along with
increases in agricultural and ecological droughts \51\ in many
regions.\52\
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\42\ https://gml.noaa.gov/webdata/ccgg/trends/co2/co2_annmean_mlo.txt.
\43\ IPCC, 2021: Summary for Policymakers. In: Climate Change
2021: The Physical Science Basis. Contribution of Working Group I to
the Sixth Assessment Report of the Intergovernmental Panel on
Climate Change [Masson-Delmotte, V., P. Zhai, A. Pirani, S.L.
Connors, C. P[eacute]an, S. Berger, N. Caud, Y. Chen, L. Goldfarb,
M.I. Gomis, M. Huang, K. Leitzell, E. Lonnoy, J.B.R. Matthews, T.K.
Maycock, T. Waterfield, O. Yelek[ccedil]i, R. Yu, and B. Zhou
(eds.)]. Cambridge University Press, Cambridge, United Kingdom and
New York, NY, USA, pp. 3-32, doi:10.1017/9781009157896.001.
\44\ NOAA National Centers for Environmental Information, State
of the Climate 2021 retrieved on August 3, 2023, from https://www.ncei.noaa.gov/bams-state-of-climate.
\45\ Blunden, et al. 2022.
\46\ IPCC, 2021.
\47\ IPCC, 2021.
\48\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller,
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, 1515 pp. doi:10.7930/NCA4.2018.
\49\ IPCC, 2021.
\27\ IPCC, 2021.
\51\ These are drought measures based on soil moisture.
\52\ IPCC, 2021.
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The assessment literature demonstrates that modest additional
amounts of warming may lead to a climate different from anything humans
have ever experienced. The 2022 CO2 concentration of 419 ppm
is already higher than at any time in the last 2 million years.\53\ If
concentrations exceed 450 ppm, they would likely be higher than any
time in the past 23 million years: \54\ at the current rate of increase
of more than 2 ppm a year, this would
[[Page 16839]]
occur in about 15 years. While GHGs are not the only factor that
controls climate, it is illustrative that 3 million years ago (the last
time CO2 concentrations were above 400 ppm) Greenland was
not yet completely covered by ice and still supported forests, while 23
million years ago (the last time concentrations were above 450 ppm) the
West Antarctic ice sheet was not yet developed, indicating the
possibility that high GHG concentrations could lead to a world that
looks very different from today and from the conditions in which human
civilization has developed. If the Greenland and Antarctic ice sheets
were to melt substantially, sea levels would rise dramatically--the
IPCC estimated that over the next 2,000 years, sea level will rise by 7
to 10 feet even if warming is limited to 1.5 [deg]C (2.7 [deg]F), from
7 to 20 feet if limited to 2 [deg]C (3.6 [deg]F), and by 60 to 70 feet
if warming is allowed to reach 5 [deg]C (9 [deg]F) above preindustrial
levels.\55\ For context, almost all of the city of Miami is less than
25 feet above sea level, and the NCA4 stated that 13 million Americans
would be at risk of migration due to 6 feet of sea level rise.
Moreover, the CO2 being absorbed by the ocean has resulted
in changes in ocean chemistry due to acidification of a magnitude not
seen in 65 million years,\56\ putting many marine species--particularly
calcifying species--at risk.
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\53\ Annual Mauna Loa CO2 concentration data from
https://gml.noaa.gov/webdata/ccgg/trends/co2/co2_annmean_mlo.txt,
accessed September 9, 2023.
\54\ IPCC, 2013.
\55\ IPCC, 2021.
\56\ IPCC, 2018.
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The NCA4 found that it is very likely (greater than 90 percent
likelihood) that by mid-century, the Arctic Ocean will be almost
entirely free of sea ice by late summer for the first time in about 2
million years.\57\ Coral reefs will be at risk for almost complete (99
percent) losses with 1 [deg]C (1.8 [deg]F) of additional warming from
today (2 [deg]C or 3.6 [deg]F since preindustrial). At this
temperature, between 8 and 18 percent of animal, plant, and insect
species could lose over half of the geographic area with suitable
climate for their survival, and 7 to 10 percent of rangeland livestock
would be projected to be lost.\58\ The IPCC similarly found that
climate change has caused substantial damages and increasingly
irreversible losses in terrestrial, freshwater, and coastal and open
ocean marine ecosystems.
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\57\ USGCRP, 2018.
\58\ IPCC, 2018.
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Scientific assessments also demonstrate that even modest additional
amounts of warming may lead to a climate different from anything humans
have ever experienced. Every additional increment of temperature comes
with consequences. For example, the half degree of warming from 1.5 to
2 [deg]C (0.9 [deg]F of warming from 2.7 [deg]F to 3.6 [deg]F) above
preindustrial temperatures is projected on a global scale to expose 420
million more people to frequent extreme heatwaves, and 62 million more
people to frequent exceptional heatwaves (where heatwaves are defined
based on a heat wave magnitude index which takes into account duration
and intensity--using this index, the 2003 French heat wave that led to
almost 15,000 deaths would be classified as an ``extreme heatwave'' and
the 2010 Russian heatwave which led to thousands of deaths and
extensive wildfires would be classified as ``exceptional''). It would
increase the frequency of sea-ice-free Arctic summers from once in 100
years to once in a decade. It could lead to 4 inches of additional sea
level rise by the end of the century, exposing an additional 10 million
people to risks of inundation as well as increasing the probability of
triggering instabilities in either the Greenland or Antarctic ice
sheets. Between half a million and a million additional square miles of
permafrost would thaw over several centuries. Risks to food security
would increase from medium-to-high for several lower-income regions in
the Sahel, southern Africa, the Mediterranean, central Europe, and the
Amazon. In addition to food security issues, this temperature increase
would have implications for human health in terms of increasing ozone
concentrations, heatwaves, and vector-borne diseases (for example,
expanding the range of the mosquitoes which carry dengue fever,
chikungunya, yellow fever, and the Zika virus, or the ticks which carry
Lyme, babesiosis, or Rocky Mountain Spotted Fever).\59\ Moreover, every
additional increment in warming leads to larger changes in extremes,
including the potential for events unprecedented in the observational
record. Every additional degree will intensify extreme precipitation
events by about 7 percent. The peak winds of the most intense tropical
cyclones (hurricanes) are projected to increase with warming. In
addition to a higher intensity, the IPCC found that precipitation and
frequency of rapid intensification of these storms has already
increased, the movement speed has decreased, and elevated sea levels
have increased coastal flooding, all of which make these tropical
cyclones more damaging.\60\
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\59\ IPCC, 2018.
\60\ IPCC, 2021.
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The NCA4 also evaluated a number of impacts specific to the U.S.
Severe drought and outbreaks of insects like the mountain pine beetle
have killed hundreds of millions of trees in the western U.S. Wildfires
have burned more than 3.7 million acres in 14 of the 17 years between
2000 and 2016, and Federal wildfire suppression costs were about a
billion dollars annually.\61\ The National Interagency Fire Center has
documented U.S. wildfires since 1983, and the 10 years with the largest
acreage burned have all occurred since 2004.\62\ Wildfire smoke
degrades air quality, increasing health risks, and more frequent and
severe wildfires due to climate change would further diminish air
quality, increase incidences of respiratory illness, impair visibility,
and disrupt outdoor activities, sometimes thousands of miles from the
location of the fire. Meanwhile, sea level rise has amplified coastal
flooding and erosion impacts, requiring the installation of costly pump
stations, flooding streets, and increasing storm surge damages. Tens of
billions of dollars of U.S. real estate could be below sea level by
2050 under some scenarios. Increased frequency and duration of drought
will reduce agricultural productivity in some regions, accelerate
depletion of water supplies for irrigation, and expand the distribution
and incidence of pests and diseases for crops and livestock. The NCA4
also recognized that climate change can increase risks to national
security, both through direct impacts on military infrastructure and by
affecting factors such as food and water availability that can
exacerbate conflict outside U.S. borders. Droughts, floods, storm
surges, wildfires, and other extreme events stress nations and people
through loss of life, displacement of populations, and impacts on
livelihoods.\63\
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\61\ USGCRP, 2018.
\62\ NIFC (National Interagency Fire Center). 2021. Total
wildland fires and acres (1983-2020). Accessed August 2021.
www.nifc.gov/fireInfo/fireInfo_stats_totalFires.html.
\63\ USGCRP, 2018.
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[[Page 16840]]
Ongoing EPA modeling efforts can shed further light on the
distribution of climate change damages expected to occur within the
U.S. Based on methods from over 30 peer-reviewed climate change impact
studies, the EPA's Framework for Evaluating Damages and Impacts (FrEDI)
model has developed estimates of the relationship between future
temperature changes and physical and economic climate-driven damages
occurring in specific U.S. regions for 20 specific impact
categories.\64\ Recent applications of FrEDI have advanced the
collective understanding about how future climate change impacts in
these 20 categories are expected to be substantial and distributed
unevenly across U.S. regions.\65\ Using this framework, the EPA
estimates that under a global emission scenario with no additional
mitigation, relative to a world with no additional warming since the
baseline period (1986-2005), damages accruing to these impact
categories in the contiguous U.S. occur mainly through increased deaths
due to increasing temperatures as well as climate-driven changes in air
quality, transportation impacts due to coastal flooding resulting from
sea level rise, increased mortality from wildfire emission exposure and
response costs for fire suppression, and reduced labor hours worked in
outdoor settings and buildings without air conditioning. The relative
damages from long-term climate driven changes in these sectors are also
projected to vary from region to region. For example, of the impact
categories examined in FrEDI, the largest source of modeled damages
differ from region to region, with wildfire impacts in the Northwest,
air quality impacts on the East Coast and the Southwest, labor
productivity impacts in the Midwest, transportation impacts from high
tide flooding in the Southern Plains, and damages to rail
infrastructure in the Northern Plains. While the FrEDI framework
currently quantifies damages for 20 impact categories within the
contiguous U.S., it is important to note that it is still a preliminary
and partial assessment of climate impacts relevant to U.S. interests in
a number of ways. For example, the FrEDI framework reflects some
important health damages from U.S. wildfires (i.e., mortality and
morbidity impacts from wildfire smoke) and suppression costs, but do
not yet account for other market and non-market welfare effects of
wildfires (e.g., property damage, impacts to ecosystem services,
climate feedback effects from wildfire CO2 emissions).
Similarly, FrEDI models several types of damages from SLR (e.g.,
traffic delays due to flooded coastal roadways) but do not reflect
others, such as the effect of groundwater intrusion, business
interruptions, debris removal costs, or critical infrastructure loss.
In addition, FrEDI does not reflect increased damages that occur due to
climate-mediated effects to ecosystem services, or national security,
interactions between different sectors impacted by climate change or
all the ways in which physical impacts of climate change occurring
abroad have spillover effects in different regions of the U.S. See the
FrEDI Technical Documentation \66\ for more details.
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\64\ EPA (2021). Technical Documentation on the Framework for
Evaluating Damages and Impacts (FrEDI). U.S. Environmental
Protection Agency, EPA 430-R-21-004, available at https://www.epa.gov/cira/fredi. Documentation has been subject to both a
public review comment period and an independent expert peer review,
following EPA peer-review guidelines.
\65\ (1) Sarofim, M.C., Martinich, J., Neumann, J.E., et al.
(2021). A temperature binning approach for multi-sector climate
impact analysis. Climatic Change 165. https://doi.org/10.1007/s10584-021-03048-6, (2) Supplementary Material for the Regulatory
Impact Analysis for the Supplemental Proposed Rulemaking,
``Standards of Performance for New, Reconstructed, and Modified
Sources and Emissions Guidelines for Existing Sources: Oil and
Natural Gas Sector Climate Review,'' Docket ID No. EPA-HQ-OAR-2021-
0317, September 2022, (3) The Long-Term Strategy of the United
States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050.
Published by the U.S. Department of State and the U.S. Executive
Office of the President, Washington DC. November 2021, (4) Climate
Risk Exposure: An Assessment of the Federal Government's Financial
Risks to Climate Change, White Paper, Office of Management and
Budget, April 2022.
\66\ EPA (2021). Technical Documentation on the Framework for
Evaluating Damages and Impacts (FrEDI). U.S. Environmental
Protection Agency, EPA 430-R-21-004, available at https://www.epa.gov/cira/fredi.
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Some GHGs also have impacts beyond those mediated through climate
change. For example, elevated concentrations of CO2
stimulate plant growth (which can be positive in the case of beneficial
species, but negative in terms of weeds and invasive species, and can
also lead to a reduction in plant micronutrients \67\) and cause ocean
acidification. Nitrous oxide depletes the levels of protective
stratospheric ozone.\68\
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\67\ Ziska, L., A. Crimmins, A. Auclair, S. DeGrasse, J.F.
Garofalo, A.S. Khan, I. Loladze, A.A. P[eacute]rez de Le[oacute]n,
A. Showler, J. Thurston, and I. Walls, 2016: Ch. 7: Food Safety,
Nutrition, and Distribution. The Impacts of Climate Change on Human
Health in the United States: A Scientific Assessment. U.S. Global
Change Research Program, Washington, DC, 189-216. https://health2016.globalchange.gov/low/ClimateHealth2016_07_Food_small.pdf.
\68\ WMO (World Meteorological Organization), Scientific
Assessment of Ozone Depletion: 2018, Global Ozone Research and
Monitoring Project--Report No. 58, 588 pp., Geneva, Switzerland,
2018.
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As methane is the primary GHG addressed in this rulemaking, it is
relevant to highlight some trends and impacts specific to methane.
Concentrations of methane reached 1,912 parts per billion (ppb) in
2022, more than two and a half times the preindustrial concentration of
722 ppb.\69\ Moreover, the 2022 concentration was an increase of almost
17 ppb over 2021--the largest annual increase in methane concentrations
in the dataset (starting in 1984), continuing a trend of rapid rise
since a temporary pause ended in 2007.\70\ Methane has a high radiative
efficiency--almost 30 times that of CO2 per ppb (and,
therefore, 80 times as much per unit mass).\71\ In addition, methane
contributes to climate change through chemical reactions in the
atmosphere that produce tropospheric ozone and stratospheric water
vapor. Human emissions of methane are responsible for about one-third
of the warming due to well-mixed GHGs, the second most important human
warming agent after CO2.\72\ Because of the substantial
emissions of methane, and its radiative efficiency, methane mitigation
is one of the best opportunities for reducing near-term warming.
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\69\ Blunden, et al., 2022.
\70\ NOAA, https://gml.noaa.gov/webdata/ccgg/trends/ch4/ch4_annmean_gl.txt, accessed August 3, 2023.
\71\ IPCC, 2021.
\72\ IPCC, 2021.
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The tropospheric ozone produced by the reaction of methane in the
atmosphere has harmful effects for human health and plant growth in
addition to its climate effects.\73\ In remote areas, methane is an
important precursor to tropospheric ozone formation.\74\ Approximately
50 percent of the global annual mean ozone increase since preindustrial
times is believed to be due to anthropogenic methane.\75\ Projections
of future
[[Page 16841]]
emissions also indicate that methane is likely to be a key contributor
to ozone concentrations in the future.\76\ Unlike NOX and
VOC, which affect ozone concentrations regionally and at hourly time
scales, methane emissions affect ozone concentrations globally and on
decadal time scales given methane's long atmospheric lifetime when
compared to these other ozone precursors.\77\ Reducing methane
emissions, therefore, will contribute to efforts to reduce global
background ozone concentrations that contribute to the incidence of
ozone-related health effects.\78\ The benefits of such reductions are
global and occur in both urban and rural areas.
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\73\ Nolte, C.G., P.D. Dolwick, N. Fann, L.W. Horowitz, V. Naik,
R.W. Pinder, T.L. Spero, D.A. Winner, and L.H. Ziska, 2018: Air
Quality. In Impacts, Risks, and Adaptation in the United States:
Fourth National Climate Assessment, Volume II [Reidmiller, D.R.,
C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, pp. 512-538. doi:10.7930/NCA4. 2018.
CH13.
\74\ U.S. EPA. 2013. ``Integrated Science Assessment for Ozone
and Related Photochemical Oxidants (Final Report).'' EPA/600-R-10-
076F. National Center for Environmental Assessment--RTP Division.
Available at https://www.epa.gov/ncea/isa/.
\75\ Myhre, G., D. Shindell, F.-M. Br[eacute]on, W. Collins, J.
Fuglestvedt, J. Huang, D. Koch, J.-F. Lamarque, D. Lee, B. Mendoza,
T. Nakajima, A. Robock, G. Stephens, T. Takemura and H. Zhang, 2013:
Anthropogenic and Natural Radiative Forcing. In: Climate Change
2013: The Physical Science Basis. Contribution of Working Group I to
the Fifth Assessment Report of the Intergovernmental Panel on
Climate Change [Stocker, T.F., D. Qin, G.-K. Plattner, M. Tignor,
S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley
(eds.)]. Cambridge University Press, Cambridge, United Kingdom and
New York, NY, USA. Pg. 680.
\76\ Ibid.
\77\ Ibid.
\78\ USGCRP, 2018.
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These scientific assessments, the EPA analyses, and documented
observed changes in the climate of the planet and of the U.S. present
clear support regarding the current and future dangers of climate
change and the importance of GHG emissions mitigation.
2. VOCs
Many VOCs can be classified as HAP (e.g., benzene \79\) and can
lead to a variety of health concerns such as cancer and noncancer
illnesses (e.g., respiratory, neurological). Further, VOCs are one of
the key precursors in the formation of ozone. Tropospheric, or ground-
level, ozone is formed through reactions of VOCs and NOX in
the presence of sunlight. Ozone formation can be controlled to some
extent through reductions in emissions of the ozone precursors VOC and
NOX. Recent observational and modeling studies have found
that VOC emissions from oil and natural gas operations can impact ozone
levels.80 81 82 83 A significantly expanded body of
scientific evidence shows that ozone can cause a number of harmful
effects on health and the environment. Exposure to ozone can cause
respiratory system effects such as difficulty breathing and airway
inflammation. For people with lung diseases such as asthma and chronic
obstructive pulmonary disease (COPD), these effects can lead to
emergency room visits and hospital admissions. Studies have also found
that ozone exposure is likely to cause premature death from lung or
heart diseases. In addition, evidence indicates that long-term exposure
to ozone is likely to result in harmful respiratory effects, including
respiratory symptoms and the development of asthma. People most at risk
from breathing air containing ozone include: children; people with
asthma and other respiratory diseases; older adults; and people who are
active outdoors, especially outdoor workers. An estimated 25.9 million
people have asthma in the U.S., including almost 7.1 million children.
Asthma disproportionately affects children, families with lower
incomes, and minorities, including Puerto Ricans, Native Americans/
Alaska Natives, and African Americans.\84\
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\79\ Benzene Integrated Risk Information System (IRIS)
Assessment: https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=276.
\80\ Benedict, K. B., Zhou, Y., Sive, B. C., Prenni, A. J.,
Gebhart, K. A., Fischer, E. V., . . . & Collett Jr, J. L. 2019.
Volatile organic compounds and ozone in Rocky Mountain National Park
during FRAPPE. Atmospheric Chemistry and Physics, 19(1), 499-521.
\81\ Lindaas, J., Farmer, D. K., Pollack, I. B., Abeleira, A.,
Flocke, F., & Fischer, E. V. 2019. Acyl peroxy nitrates link oil and
natural gas emissions to high ozone abundances in the Colorado Front
Range during summer 2015. Journal of Geophysical Research:
Atmospheres, 124(4), 2336-2350.
\82\ McDuffie, E. E., Edwards, P. M., Gilman, J. B., Lerner, B.
M., Dub[eacute], W. P., Trainer, M., . . . & Brown, S. S. 2016.
Influence of oil and gas emissions on summertime ozone in the
Colorado Northern Front Range. Journal of Geophysical Research:
Atmospheres, 121(14), 8712-8729.
\83\ Tzompa[hyphen]Sosa, Z. A., & Fischer, E. V. 2021. Impacts
of emissions of C2[hyphen]C5 alkanes from the US oil and gas sector
on ozone and other secondary species. Journal of Geophysical
Research: Atmospheres, 126(1), e2019JD031935.
\84\ National Health Interview Survey (NHIS) Data, 2011. https://www.cdc.gov/asthma/nhis/2011/data.htm.
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In the EPA's 2020 Integrated Science Assessment (ISA) for Ozone and
Related Photochemical Oxidants,\85\ the EPA estimated the incidence of
air pollution effects for those health endpoints above where the ISA
classified as either causal or likely-to-be-causal. In brief, the ISA
for ozone found short-term (less than one month) exposures to ozone to
be causally related to respiratory effects, a ``likely to be causal''
relationship with metabolic effects and a ``suggestive of, but not
sufficient to infer, a causal relationship'' for central nervous system
effects, cardiovascular effects, and total mortality. The ISA reported
that long-term exposures (one month or longer) to ozone are ``likely to
be causal'' for respiratory effects including respiratory mortality,
and a ``suggestive of, but not sufficient to infer, a causal
relationship'' for cardiovascular effects, reproductive effects,
central nervous system effects, metabolic effects, and total mortality.
An example of quantified incidence of ozone health effects can be found
in the Regulatory Impact Analysis for the Final Revised Cross-State Air
Pollution Rule (CSAPR) Update.\86\
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\85\ Integrated Science Assessment (ISA) for Ozone and Related
Photochemical Oxidants (Final Report). U.S. Environmental Protection
Agency, Washington, DC, EPA/600/R-20/012, 2020.
\86\ U.S. EPA. Technical Support Document (TSD) for the Final
Revised Cross-State Air Pollution Rule Update for the 2008 Ozone
Season NAAQS Estimating PM 2.5-and Ozone-Attributable Health
Benefits. 2021. Research Triangle Park, NC.
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Scientific evidence also shows that repeated exposure to ozone can
reduce growth and have other harmful effects on sensitive plants and
trees. These types of effects have the potential to impact ecosystems
and the benefits they provide.
3. SO2
Current scientific evidence links short-term exposures to
SO2, ranging from 5 minutes to 24 hours, with an array of
adverse respiratory effects including bronchoconstriction and increased
asthma symptoms. These effects are particularly important for
asthmatics at elevated ventilation rates (e.g., while exercising or
playing).
Studies also show an association between short-term exposure and
increased visits to emergency departments and hospital admissions for
respiratory illnesses, particularly in at-risk populations including
children, the elderly, and asthmatics.
SO2 in the air can also damage the leaves of plants,
decrease their ability to produce food (photosynthesis), and decrease
their growth. In addition to directly affecting plants, SO2,
when deposited on land and in estuaries, lakes, and streams, can
acidify sensitive ecosystems resulting in a range of harmful indirect
effects on plants, soils, water quality, and fish and wildlife (e.g.,
changes in biodiversity and loss of habitat, reduced tree growth, loss
of fish species). Sulfur deposition to waterways also plays a causal
role in the methylation of mercury.\87\
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\87\ U.S. EPA. Integrated Science Assessment (ISA) for Oxides of
Nitrogen and Sulfur Ecological Criteria (2008 Final Report). U.S.
Environmental Protection Agency, Washington, DC, EPA/600/R-08/082F,
2008.
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B. Profile of the Oil and Natural Gas Industry and Its Emissions
This section of the preamble generally describes: the structure of
the oil and natural gas industry; the interconnected production,
processing, transmission and storage, and distribution segments that
move product from well to market; and types of emissions sources in
each segment and the industry's emissions.
[[Page 16842]]
1. Structure of the Oil and Natural Gas Industry
The EPA characterizes the oil and natural gas industry's operations
as being generally composed of four segments: (1) Extraction and
production of crude oil and natural gas (``oil and natural gas
production''), (2) natural gas processing, (3) natural gas transmission
and storage, and (4) natural gas distribution.88 89 The EPA
regulates oil refineries as a separate source category; accordingly, as
with the previous oil and gas NSPS rulemakings, for purposes of this
rulemaking, the EPA's focus for crude oil is on operations from the
well to the point of custody transfer at a petroleum refinery while the
focus for natural gas is on all operations from the well to the local
distribution company custody transfer station, commonly referred to as
the ``city-gate.'' \90\
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\88\ The EPA previously described an overview of the sector in
section 2.0 of the 2011 Background TSD to 40 CFR part 60, subpart
OOOO, located at Document ID No. EPA-HQ-OAR-2010-0505-0045, and
section 2.0 of the 2016 Background TSD to 40 CFR part 60, subpart
OOOOa, located at Document ID No. EPA-HQ-OAR-2010-0505-7631.
\89\ While generally oil and natural gas production includes
both onshore and offshore operations, 40 CFR part 60, subpart OOOOa,
addresses onshore operations.
\90\ For regulatory purposes, the EPA defines the Crude Oil and
Natural Gas source category to mean (1) crude oil production, which
includes the well and extends to the point of custody transfer to
the crude oil transmission pipeline or any other forms of
transportation; and (2) natural gas production, processing,
transmission, and storage, which include the well and extend to, but
do not include, the local distribution company custody transfer
station. The distribution segment is not part of the defined source
category.
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a. Production Segment
The oil and natural gas production segment includes the wells and
all related processes used in the extraction, production, recovery,
lifting, stabilization, and separation or treatment of oil and/or
natural gas (including condensate). Although many wells produce a
combination of oil and natural gas, wells can generally be grouped into
two categories: oil wells and natural gas wells. Oil wells comprise two
types, oil wells that produce crude oil only and oil wells that produce
both crude oil and natural gas (commonly referred to as ``associated''
gas). Production equipment and components located on the well pad may
include, but are not limited to: wells and related casing heads; tubing
heads; ``Christmas tree'' piping, pumps, and compressors; heater
treaters; separators; storage vessels; process controllers; pumps; and
dehydrators. Production operations include well drilling, completion,
and recompletion processes, including all the portable non-self-
propelled apparatuses associated with those operations.
Other sites that are part of the production segment include
``centralized tank batteries,'' stand-alone sites where oil,
condensate, produced water, and natural gas from several wells may be
separated, stored, or treated. The production segment also includes
gathering pipelines, gathering and boosting compressor stations, and
related components that collect and transport the oil, natural gas, and
other materials and wastes from the wells to the refineries or natural
gas processing plants.
Crude oil and natural gas undergo successive, separate processing.
Crude oil is separated from water and other impurities and transported
to a refinery via truck, railcar, or pipeline. As noted above, the EPA
treats oil refineries as a separate source category; accordingly, for
present purposes, the oil component of the production segment ends at
the point of custody transfer at the refinery.\91\
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\91\ See 40 CFR part 60, subparts J and Ja, and 40 CFR part 63,
subparts CC and UUU.
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The separated, unprocessed natural gas is commonly referred to as
field gas and is composed of methane, natural gas liquids (NGL), and
other impurities such as water vapor, H2S, CO2,
helium, and nitrogen. Ethane, propane, butane, isobutane, and pentane
are all considered NGL and often are sold separately for a variety of
different uses. Natural gas with high methane content is referred to as
``dry gas,'' while natural gas with significant amounts of ethane,
propane, or butane is referred to as ``wet gas.'' Natural gas is
typically sent to gas processing plants in order to separate NGLs for
use as feedstock for petrochemical plants, fuel for space heating and
cooking, or a component for blending into vehicle fuel.
b. Processing Segment
The natural gas processing segment consists of separating certain
hydrocarbons (HC) and fluids from the natural gas to produce ``pipeline
quality'' dry natural gas. The degree and location of processing is
dependent on factors such as the type of natural gas (e.g., wet or dry
gas), market conditions, and company contract specifications.
Typically, processing of natural gas begins in the field and continues
as the gas is moved from the field through gathering and boosting
compressor stations to natural gas processing plants, where the
complete processing of natural gas takes place. Natural gas processing
operations separate and recover NGL or other non-methane gases and
liquids from field gas through one or more of the following processes:
oil and condensate separation, water removal, separation of NGL, sulfur
and CO2 removal, fractionation of NGL, and other processes,
such as the capture of CO2 separated from natural gas
streams for delivery outside the facility.
c. Transmission and Storage Segment
Once natural gas processing is complete, the resulting natural gas
exits the natural gas process plant and enters the transmission and
storage segment where it is transmitted to storage and/or distribution
to the end user.
Pipelines in the natural gas transmission and storage segment can
be interstate pipelines, which carry natural gas across state
boundaries, or intrastate pipelines, which transport the gas within a
single state. Basic components of the two types of pipelines are the
same, though interstate pipelines may be of a larger diameter and
operated at a higher pressure. To ensure that the natural gas continues
to flow through the pipeline, the natural gas must periodically be
compressed, thereby increasing its pressure. Compressor stations
perform this function and are usually placed at 40- to 100-mile
intervals along the pipeline. At a compressor station, the natural gas
enters the station, where it is compressed by reciprocating or
centrifugal compressors.
Another part of the transmission and storage segment are
aboveground and underground natural gas storage facilities. Storage
facilities hold natural gas for use during peak seasons. The main
difference between underground and aboveground storage sites is that
storage takes place in storage vessels constructed of non-earthen
materials in aboveground storage. Underground storage of natural gas
typically occurs in depleted natural gas or oil reservoirs and salt
dome caverns. One purpose of this storage is for load balancing
(equalizing the receipt and delivery of natural gas). At an underground
storage site, typically other processes occur, including compression,
dehydration, and flow measurement.
d. Distribution Segment
The distribution segment provides the final step in delivering
natural gas to customers.\92\ The natural gas enters the distribution
segment from delivery points located along interstate and
[[Page 16843]]
intrastate transmission pipelines to business and household customers.
The delivery point where the natural gas leaves the transmission and
storage segment and enters the distribution segment is a local
distribution company's custody transfer station, commonly referred to
as the ``city-gate.'' Natural gas distribution systems consist of over
2 million miles of piping, including mains and service pipelines to the
customers. If the distribution network is large, compressor stations
may be necessary to maintain flow. However, these stations are
typically smaller than transmission compressor stations. Distribution
systems include metering stations and regulating stations, which allow
distribution companies to monitor the natural gas as it flows through
the system.
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\92\ The distribution segment is not included in the definition
of the Crude Oil and Natural Gas source category in NSPS OOOO, NSPS
OOOOa, NSPS OOOOb, or EG OOOOc.
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2. Emissions From the Oil and Natural Gas Source Category
The oil and natural gas industry sector is the largest source of
industrial methane emissions in the U.S.\93\ Natural gas is composed
primarily of methane; every natural gas leak or intentional release
through venting or other industrial processes constitutes a release of
methane. Methane is a potent GHG; over a 100-year timeframe, it is
nearly 30 times more powerful at trapping climate warming heat than
CO2, and over a 20-year timeframe, it is 83 times more
powerful.\94\ Because methane is a powerful GHG and is emitted in large
quantities, reductions in methane emissions provide a significant
benefit in reducing near-term warming. Indeed, one-third of the warming
due to GHGs that we are experiencing today is due to human-caused
emissions of methane. Additionally, the Crude Oil and Natural Gas
sector emits, in varying concentrations and amounts, a wide range of
other health-harming pollutants, including VOCs, SO2,
NOX, H2S, CS2, and COS. The year 2016
modeling platform produced by the EPA estimated about 3 million tons of
VOC are emitted by oil and gas-related sources.\95\
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\93\ H.R. Rep. No. 117-64, 4 (2021) (Report by the House
Committee on Energy and Commerce concerning H.J. Res. 34, to
disapprove the 2020 Policy Rule) (House Report).
\94\ IPCC, 2021.
\95\ https://www.epa.gov/sites/default/files/2020-11/documents/2016v1_emismod_tsd_508.pdf.
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Emissions of methane and these co-pollutants occur in every segment
of the Crude Oil and Natural Gas source category, which comprises the
oil and natural gas production, natural gas processing, and natural gas
transmission and storage segments of the larger industry. Many of the
processes and equipment types that contribute to these emissions are
found in every segment of the source category and are highly similar
across segments. Emissions from the crude oil portion of the regulated
source category result primarily from field production operations, such
as venting of associated gas from oil wells, oil storage vessels, and
production-related equipment such as gas dehydrators, pig traps,
process controllers, and pumps. Emissions from the natural gas portion
of the industry can occur in all segments. As natural gas moves through
the system, emissions primarily result from intentional venting through
normal operations, routine maintenance, unintentional fugitive
emissions, flaring, malfunctions, and system upsets. Venting can occur
through equipment design or operational practices, such as the
continuous bleed and intermittent venting of gas from process
controllers (devices that control gas flows, levels, temperatures, and
pressures in the equipment). In addition to vented emissions, emissions
can occur from leaking equipment (also referred to as fugitive
emissions) in all parts of the infrastructure, including major
production and processing equipment (e.g., separators or storage
vessels) and individual components (e.g., valves or connectors). Flares
are commonly used throughout each segment in the oil and natural gas
industry as a control device--to provide pressure relief to prevent
risk of explosions; to destroy methane, which has a high global warming
potential, and convert it to CO2 which has a lower global
warming potential; and to control other air pollutants such as VOC.
``Super-emitting'' events, sites, or equipment, which refer to a
small proportion of particularly highly emitting sources that account
for a large proportion of overall emissions, can occur throughout the
oil and natural gas industry and have been observed in the equipment
types and activities covered by this final rulemaking. There are a
number of definitions for the term ``super-emitter.'' A 2018 National
Academies of Sciences, Engineering, and Medicine report \96\ on methane
discussed three categories of ``high-emitting'' sources:
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\96\ https://www.nap.edu/download/24987#.
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Routine or ``chronic'' high-emitting sources, which
regularly emit at higher rates relative to ``peers'' in a sample.
Examples include large facilities and large emissions at smaller
facilities caused by poor design or operational practices.
Episodic high-emitting sources, which are typically large
in nature and are generally intentional releases from known maintenance
events at a facility. Examples include gas well liquids unloading, well
workovers and maintenance activities, and compressor station or
pipeline blowdowns.
Malfunctioning high-emitting sources, which can be either
intermittent or prolonged in nature and result from malfunctions and
poor work practices. Examples include malfunctioning intermittent
process controllers and stuck open dump valves. Another example is well
blowout events. For example, a 2018 well blowout in Ohio was estimated
to have emitted over 60,000 tons of methane.\97\
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\97\ Pandey, et al. (2019). Satellite observations reveal
extreme methane leakage from a natural gas well blowout. PNAS
December 26, 2019. 116 (52) 26376-81.
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Super-emitters have been observed at many different scales, from
site-level to component-level, across many research studies.\98\
Studies will often develop a study-specific definition such as a top
percentile of emissions in a study population (e.g., top 10 percent),
emissions exceeding a certain threshold (e.g., 26 kg/day), emissions
over a certain detection threshold (e.g., 1-3 g/s) or as facilities
with the highest proportional emission rate.\99\ For certain equipment
types and activities, the EPA's GHG emission estimates include the full
range of conditions, including ``super-emitters.'' For other
situations, where data are available, emissions estimates for abnormal
events are
[[Page 16844]]
calculated separately and included in the Inventory of U.S. Greenhouse
Gas Emissions and Sinks (GHGI) (e.g., Aliso Canyon leak event).\100\
Given the variability of practices and technologies across oil and gas
systems and the occurrence of episodic events, it is possible that the
EPA's estimates do not include all methane emissions from abnormal
events. The EPA continues to engage with the research community and
expert stakeholders to review new data from the EPA's Greenhouse Gas
Reporting Program (GHGRP) petroleum and natural gas systems source
category (40 CFR part 98, subpart W, also referred to as ``GHGRP
subpart W''), as well as the peer-reviewed scientific literature and
research studies to assess how emissions estimates can be improved.
Because lost gas, whether through fugitive emissions, unintentional gas
carry-through, or intentional releases, represents lost earning
potential, the industry benefits from capturing and selling emissions
of natural gas (and methane). Limiting super-emitters through actions
included in this rulemaking such as reducing fugitive emissions, using
lower emitting equipment where feasible, and employing best management
practices will not only reduce emissions but reduce the loss of revenue
from this valuable commodity.
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\98\ See, for example, Brandt, A., Heath, G., Cooley, D. (2016)
Methane Leaks from Natural Gas Systems Follow Extreme Distributions.
Environ. Sci. Technol., doi:10.1021/acs.est.6b04303; Zavala-Araiza,
D., Alvarez, R.A., Lyon, D.R., Allen, D.T., Marchese, A.J.,
Zimmerle, D.J., & Hamburg, S.P. (2017). Super-emitters in natural
gas infrastructure are caused by abnormal process conditions. Nature
communications, 8, 14012; Mitchell, A., et al. (2015), Measurements
of Methane Emissions from Natural Gas Gathering Facilities and
Processing Plants: Measurement Results. Environmental Science &
Technology, 49(5), 3219-3227; Allen, D., et al. (2014), Methane
Emissions from Process Equipment at Natural Gas Production Sites in
the United States: Pneumatic Controllers. Environmental Science &
Technology.
\99\ Caulton, et al. (2019). Importance of Super-emitter Natural
Gas Well Pads in the Marcellus Shale. Environ. Sci. Technol. 2019,
53, 4747-4754; Zavala-Araiza, D., Alvarez, R., Lyon, D, et al.
(2016). Super-emitters in natural gas infrastructure are caused by
abnormal process conditions. Nat Commun 8, 14012 (2017). https://www.nature.com/articles/ncomms14012; Lyon, et al. (2016). Aerial
Surveys of Elevated Hydrocarbon Emissions from Oil and Gas
Production Sites. Environ. Sci. Technol. 2016, 50, 4877-4886.
https://pubs.acs.org/doi/10.1021/acs.est.6b00705; and Zavala-Araiza
D, et al. (2015). Toward a functional definition of methane
superemitters: Application to natural gas production sites. Environ.
Sci. Technol. 49, 8167-8174. https://pubs.acs.org/doi/10.1021/acs.est.5b00133.
\100\ The EPA's emission estimates in the GHGI are developed
with the best data available at the time of their development,
including data from the GHGRP in 40 CFR part 98, subpart W, and from
recent research studies. GHGRP subpart W emissions data used in the
GHGI are quantified by reporters using direct measurements,
engineering calculations, or emission factors, as specified by the
regulation. The EPA has a multi-step data verification process for
GHGRP subpart W data, including automatic checks during data entry,
statistical analyses on completed reports, and staff review of the
reported data. Based on the results of the verification process, the
EPA follows up with facilities to resolve mistakes that may have
occurred.
---------------------------------------------------------------------------
Below we provide estimated emissions of methane, VOC, and
SO2 from oil and natural gas industry operation sources.
a. Methane Emissions in the U.S. and From the Oil and Natural Gas
Industry
Official U.S. estimates of national-level GHG emissions and sinks
are developed by the EPA for the GHGI in fulfillment of commitments
under the United Nations Framework Convention on Climate Change. The
GHGI, which includes recent trends, is organized by industrial sector.
The oil and natural gas production, natural gas processing, and natural
gas transmission and storage sectors emit 28 percent of U.S.
anthropogenic methane. Table 7 presents total U.S. anthropogenic
methane emissions for the years 1990, 2010, and 2021.
In accordance with the practice of the EPA GHGI, the EPA GHGRP, and
international reporting standards under the U.N. Framework Convention
on Climate Change, the 2007 IPCC Fourth Assessment Report value of the
methane 100-year GWP is used for weighting emissions in the following
tables. The 100-year GWP value of 28 for methane indicates that 1 ton
of methane has approximately as much climate impact over a 100-year
period as 28 tons of CO2. The most recent IPCC AR6
assessment has calculated updated 100-year GWPs for methane of either
27.2 or 29.8 depending on whether the value includes the CO2
produced by the oxidation of methane in the atmosphere. As mentioned
earlier, because methane has a shorter lifetime than CO2,
the emissions of a ton of methane will have more impact earlier in the
100-year timespan and less impact later in the 100-year timespan
relative to the emissions of a 100-year GWP-equivalent quantity of
CO2: when using the AR6 20-year GWP of 81, which only looks
at impacts over the next 20 years, the total U.S. emissions of methane
in 2021 would be equivalent to about 2,140 MMT CO2.
---------------------------------------------------------------------------
\101\ Other sources include rice cultivation, stationary
combustion, abandoned coal mines, mobile combustion, composting, and
several sources emitting less than 1 MMT CO2 Eq. in 2021.
Table 7--U.S. Methane Emissions by Sector
[Million metric tons carbon dioxide equivalent (MMT CO2 Eq.)]
----------------------------------------------------------------------------------------------------------------
Sector 1990 2010 2021
----------------------------------------------------------------------------------------------------------------
Oil and Natural Gas Production, and Natural Gas Processing and 206 224 202
Transmission and Storage.......................................
Landfills....................................................... 198 139 123
Enteric Fermentation............................................ 183 191 195
Coal Mining..................................................... 108 92 45
Manure Management............................................... 39 59 66
Other Oil and Gas Sources....................................... 68 37 38
Wastewater Treatment............................................ 23 22 21
Other Methane Sources\101\...................................... 44 44 38
-----------------------------------------------
Total Methane Emissions..................................... 869 808 727
----------------------------------------------------------------------------------------------------------------
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2021 (published April 13,
2023), calculated using GWP of 28. Note: Totals may not sum due to rounding.
Table 8 presents total methane emissions from natural gas
production through transmission and storage and petroleum production,
for years 1990, 2010, and 2021, in MMT CO2 Eq. (or million
metric tons CO2 Eq.) of methane.
Table 8--U.S. Methane Emissions From Natural Gas and Petroleum Systems
[MMT CO2 Eq.]
----------------------------------------------------------------------------------------------------------------
Sector 1990 2010 2021
----------------------------------------------------------------------------------------------------------------
Natural Gas Production.......................................... 68 121 94
Natural Gas Processing.......................................... 24 11 14
Natural Gas Transmission and Storage............................ 64 39 45
[[Page 16845]]
Petroleum Production............................................ 50 54 49
----------------------------------------------------------------------------------------------------------------
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2021 (published April 13,
2023), calculated using GWP of 28. Note: Totals may not sum due to rounding.
b. Global GHG Emissions
For additional background information and context, we used 2018
World Resources Institute Climate Watch data to make comparisons
between U.S. oil and natural gas production and natural gas processing
and transmission and storage emissions and the emissions inventories of
entire countries and regions.\102\ The U.S. methane emissions from oil
and natural gas production and natural gas processing and transmission
and storage constitute 0.4 percent of total global emissions of all
GHGs (48,600 MMT CO2 Eq.) from all sources.\103\ Ranking
U.S. emissions of methane from oil and natural gas production and
natural gas processing and transmission and storage against total GHG
emissions for entire countries (using 2021 Climate Watch data) shows
that these emissions are comparatively large as they exceed the
national-level emissions totals for all GHGs and all anthropogenic
sources for Colombia, the Czech Republic, Chile, Belgium, and over 164
other countries. This means that the U.S. emits more of a single GHG--
methane--from a single sector--the oil and natural gas sector--than the
total combined GHGs emitted by 168 countries. Furthermore, U.S.
emissions of methane from oil and natural gas production and natural
gas processing and transmission and storage are greater than the sum of
total emissions of 63 of the lowest-emitting countries and territories
using the 2021 Climate Watch data set.
---------------------------------------------------------------------------
\102\ The Climate Watch figures presented here come from the PIK
dataset included on Climate Watch. The PIK dataset combines the
United Nations Framework Convention on Climate Change (UNFCCC)
reported data where available and fills gaps with other sources. It
does not include land use change and forestry but covers all other
sectors. https://www.climatewatchdata.org/ghg-emissions?end_year=2018&source=PIK&start_year=1990. The PIK data set
uses AR4 GWPs. For the comparisons presented here, the AR4 GWPs were
applied to the U.S. oil and gas methane values.
---------------------------------------------------------------------------
As illustrated by the domestic and global GHGs comparison data
summarized above, the collective GHG emissions from the Crude Oil and
Natural Gas source category are significant, whether the comparison is
domestic (where this sector is the largest source of methane emissions,
accounting for 28 percent of U.S. methane and 3 percent of total U.S.
emissions of all GHGs), global (where this sector, accounting for 0.4
percent of all global GHG emissions, emits more than the total national
emissions of over 160 countries, and combined emissions of over 60
countries), or when both the domestic and global GHG emissions
comparisons are viewed in combination. Consideration of the global
context is important. GHG emissions from U.S. oil and natural gas
production and natural gas processing and transmission and storage will
become globally well-mixed in the atmosphere and thus will have an
effect on both the U.S. regional and global climate for years and
indeed many decades to come. No single GHG source category dominates on
the global scale. While the Crude Oil and Natural Gas source category,
like many (if not all) individual GHG source categories, could appear
small in comparison to total emissions, in fact, it is a very important
contributor both in terms of absolute emissions and in comparison to
other source categories globally or within the U.S.
The IPCC AR6 assessment determined that ``[f]rom a physical science
perspective, limiting human-induced global warming to a specific level
requires limiting cumulative CO2 emissions, reaching at
least net zero CO2 emissions, along with strong reductions
in other GHG emissions.'' The report also singled out the importance of
``strong and sustained methane emission reductions'' in part due to the
short lifetime of methane leading to the near-term cooling from
reductions in methane emissions, which can offset the warming that will
result due to reductions in emissions of cooling aerosols such as
SO2. Therefore, reducing methane emissions globally is an
important facet in any strategy to limit warming. In the oil and gas
sector, methane reductions are highly achievable and cost-effective
using existing and well-known solutions and technologies that actually
result in recovery of saleable product.
c. VOC and SO2 Emissions in the U.S. and From the Oil and
Natural Gas Industry
Official U.S. estimates of national-level VOC and SO2
emissions are developed by the EPA for the National Emissions Inventory
(NEI), for which states are required to submit information under 40 CFR
part 51, subpart A. Data in the NEI may be organized by various data
categories, including sector, NAICS code, and Source Classification
Code. Tables 9 and 10 below present total U.S. VOC and SO2
emissions by sector, respectively, for the year 2020, in kilotons (kt)
(or thousand metric tons). The oil and natural gas sector represents
the top anthropogenic U.S. sector for VOC emissions after removing the
biogenics and wildfire sectors in table 9 (about 23 percent of the
total VOC emitting by anthropogenic sources). About 10 percent of the
total U.S. anthropogenic SO2 comes from the oil and natural
gas sector.
Table 9--U.S. VOC Emissions by Sector
[kt]
------------------------------------------------------------------------
Sector 2020 NEI
------------------------------------------------------------------------
Biogenics--Vegetation and Soil....................... 29,519
Fires--Wildfires..................................... 4,623
Oil and Natural Gas Production, and Natural Gas 2,761
Processing and Transmission.........................
Solvent--Consumer and Commercial Solvent Use......... 1,936
Fires--Prescribed Fires.............................. 1,936
[[Page 16846]]
Mobile--Non-Road Equipment--Gasoline................. 935
Mobile--On-Road non-Diesel Light Duty Vehicles....... 835
Other VOC Sources.................................... 3,642
------------------
Total VOC Emissions.................................. 46,188
------------------------------------------------------------------------
Emissions from the 2020 NEI (released March 2023). Note: Totals may not
sum due to rounding.
Table 10--U.S. SO2 Emissions by Sector
[kt]
------------------------------------------------------------------------
Sector 2020 NEI
------------------------------------------------------------------------
Fuel Combustion--Electric Generation--Coal........... 771
Industrial Processes--Not Elsewhere Classified....... 230
Oil and Natural Gas Production and Natural Gas 165
Processing and Transmission.........................
Fires--Wildfires..................................... 141
Fuel Combustion--Industrial Boilers, Internal 115
Combustion Engines--Coal............................
Industrial Processes--Chemical Manufacturing......... 91
Other SO2 Sources.................................... 313
------------------
Total SO2 Emissions.............................. 1,827
------------------------------------------------------------------------
Emissions from the 2020 NEI (released March 2023). Note: Totals may not
sum due to rounding.
Table 11 presents total VOC and SO2 emissions from oil
and natural gas production through transmission and storage, for the
year 2020, in kt. The contribution to the total anthropogenic VOC
emissions budget from the oil and gas sector has been increasing in
recent NEI cycles. In the 2020 NEI, the oil and gas sector makes up
about 23 percent of the total VOC emissions from anthropogenic sources.
The SO2 emissions have been declining in almost every
anthropogenic sector, but the oil and gas sector is an exception where
SO2 emissions have been increasing in recent years.
Table 11--U.S. VOC and SO2 Emissions from Natural Gas and Petroleum
Systems
[kt]
------------------------------------------------------------------------
Sector VOC SO2
------------------------------------------------------------------------
Oil and Natural Gas Production........................ 2,729 160
Natural Gas Processing................................ 8 3
Natural Gas Transmission and Storage.................. 24 2
------------------------------------------------------------------------
Emissions from the 2020 NEI, (published March 2023), in kt (or thousand
metric tons). Note: Totals may not sum due to rounding.
IV. Statutory Background and Regulatory History
A. Statutory Background of CAA Sections 111(b), 111(d), and General
Implementing Regulations
The EPA's authority for this rulemaking is CAA section 111, which
governs the establishment of standards of performance for stationary
sources. This CAA section requires the EPA to list source categories to
be regulated, establish standards of performance for air pollutants
emitted by new sources in that source category, and establish EG for
states to establish standards of performance for certain pollutants
emitted by existing sources in that source category.
Specifically, CAA section 111(b)(1)(A) requires that a source
category be included on the list for regulation if, ``in [the EPA
Administrator's] judgment it causes, or contributes significantly to,
air pollution which may reasonably be anticipated to endanger public
health or welfare.'' This determination is commonly referred to as an
``endangerment finding'' and that phrase encompasses both the ``causes
or contributes significantly to'' component and the ``endanger public
health or welfare'' component of the determination. Once a source
category is listed, CAA section 111(b)(1)(B) requires that the EPA
propose and then promulgate ``standards of performance'' for new
sources in such source category. CAA section 111(a)(1) defines a
``standard of performance'' as ``a standard for emissions of air
pollutants which reflects the degree of emission limitation achievable
through the application of the best system of emission reduction which
(taking into account the cost of achieving such reduction and any
nonair quality health and environmental impact and energy requirements)
the Administrator determines has been adequately demonstrated.'' As
long recognized by the D.C. Circuit, ``[b]ecause Congress did not
assign the specific weight the Administrator should accord each of
these factors, the Administrator is free to exercise his discretion in
this area.'' New York v. Reilly, 969 F.2d 1147, 1150 (D.C. Cir. 1992).
See also Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir.
1999) (``Lignite Energy Council'') (``Because section 111 does not set
forth the weight that be [sic] should assigned to each of these
factors, we have granted the Agency a great degree of discretion in
balancing them'').
[[Page 16847]]
In determining whether a given system of emission reduction
qualifies as ``the best system of emission reduction . . . adequately
demonstrated,'' or ``BSER,'' CAA section 111(a)(1) requires that the
EPA take into account, among other factors, ``the cost of achieving
such reduction.'' As described in the proposal \104\ for the 2016 Rule
and in the November 2021 Proposal for this rulemaking,\105\ the U.S.
Court of Appeals for the District of Columbia Circuit (the D.C.
Circuit) has stated that in light of this provision, the EPA may not
adopt a standard the cost of which would be ``exorbitant,'' \106\
``greater than the industry could bear and survive,'' \107\
``excessive,'' \108\ or ``unreasonable.'' \109\ These formulations
appear to be synonymous, and for convenience, in this rulemaking, as in
previous rulemakings, we will refer to this standard as reasonableness,
so that a control technology may be considered the ``best system of
emission reduction . . . adequately demonstrated'' if its costs are
reasonable, but cannot be considered the BSER if its costs are
unreasonable. See 80 FR 64662, 64720-21 (October 23, 2015).
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\104\ 80 FR 56593, 56616 (September 18, 2015).
\105\ 86 FR 63154 (December 6, 2022).
\106\ Lignite Energy Council, 198 F.3d at 933.
\107\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir.
1975).
\108\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
\109\ Id.
---------------------------------------------------------------------------
CAA section 111(a) does not provide specific direction regarding
what metric or metrics to use in considering costs, affording the EPA
considerable discretion in choosing a means of cost consideration.\110\
In this rulemaking, we evaluated whether a control cost is reasonable
under a number of approaches that we find appropriate for assessing the
types of controls at issue. For example, we evaluated costs at a sector
level by assessing the projected new capital expenditures required
under the final rulemaking (compared to overall new capital
expenditures by the sector) and the projected compliance costs
(compared to overall annual revenue for the sector) if the rule were to
require such controls. In evaluating controls for reducing VOC and
methane emissions from new sources, we also considered a control's cost
effectiveness under both a ``single-pollutant cost effectiveness''
approach and a ``multipollutant cost effectiveness'' approach, in order
to appropriately take into account that the systems of emission
reduction considered in this rule typically achieve reductions in
multiple pollutants at once and secure a multiplicity of climate and
public health benefits.\111\ For a detailed discussion of these cost
approaches, please see section VIII.B of the preamble as well as the
November 2021 Proposal and the December 2022 Supplemental Proposal.
---------------------------------------------------------------------------
\110\ See, e.g., Husqvarna AB v. EPA, 254 F.3d 195, 200 (D.C.
Cir. 2001) (where CAA section 213 does not mandate a specific method
of cost analysis, the EPA may make a reasoned choice as to how to
analyze costs).
\111\ We believe that both the single and multipollutant
approaches are appropriate for assessing the reasonableness of the
multipollutant controls considered in this action. The EPA has
considered similar approaches in the past when considering multiple
pollutants that are controlled by a given control option. See, e.g.,
80 FR 56616-17; 73 FR 64079-83; and EPA Document ID Nos. EPA-HQ-OAR-
2004-0022-0622, -0447, -0448.
---------------------------------------------------------------------------
Under CAA section 111(a)(1), an essential, although not sufficient,
condition for a ``system of emission reduction'' to serve as the basis
for an ``achievable'' emission limitation is that the Administrator
must determine that the system is ``adequately demonstrated.'' This
means, according to the D.C. Circuit, that the system is ``one which
has been shown to be reasonably reliable, reasonably efficient, and
which can reasonably be expected to serve the interests of pollution
control without becoming exorbitantly costly in an economic or
environmental way.'' \112\ It does not mean that the system ``must be
in actual routine use somewhere,'' \113\ though the technologies relied
upon in this final rulemaking are. Similarly, the EPA may ``hold the
industry to a standard of improved design and operational advances, so
long as there is substantial evidence that such improvements are
feasible.'' \114\ Ultimately, the analysis ``is partially dependent on
`lead time,''' that is, ``the time in which the technology will have to
be available.'' \115\ The caselaw is clear that the EPA may treat a set
of control measures as ``adequately demonstrated'' regardless of
whether the measures are in widespread commercial use. For example, the
D.C. Circuit upheld the EPA's determination that selective catalytic
reduction (SCR) was adequately demonstrated to reduce NOX
emissions from coal-fired industrial boilers, even though it was a
``new technology.'' The court explained that ``section 111 `looks
toward what may fairly be projected for the regulated future, rather
than the state of the art at present.' '' \116\ The court added that
the EPA may determine that control measures are ``adequately
demonstrated'' through a ``reasonable extrapolation of [the control
measures'] performance in other industries.'' \117\
---------------------------------------------------------------------------
\112\ Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C.
Cir. 1973), cert. denied, 416 U.S. 969 (1974).
\113\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973) (citations omitted) (``The Administrator may make a
projection based on existing technology, though that projection is
subject to the restraints of reasonableness and cannot be based on
`crystal ball' inquiry.''); ibid. (discussing the Senate and House
bills and reports from which the language in CAA section 111 grew).
\114\ Sierra Club v. Costle, 657 F.2d 298, 364 (D.C. Cir. 1981).
\115\ Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391
(D.C. Cir. 1973) (citations omitted).
\116\ Lignite Energy Council, 198 F.3d at 934 (citing Portland
Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 391 (D.C. Cir. 1973)).
\117\ Ibid.
---------------------------------------------------------------------------
As defined in CAA section 111(a), the ``standard of performance''
that the EPA develops, based on the BSER, is expressed as a performance
level (typically, a rate-based standard). CAA section 111(b)(5)
precludes the EPA from prescribing a particular technological system
that must be used to comply with a standard of performance. Rather,
sources can select any measure or combination of measures that will
achieve the standard.
CAA section 111(h)(1) authorizes the Administrator to promulgate
``a design, equipment, work practice, or operational standard, or
combination thereof'' if in his or her judgment, ``it is not feasible
to prescribe or enforce a standard of performance.'' CAA section
111(h)(2) provides the circumstances under which prescribing or
enforcing a standard of performance is ``not feasible,'' such as when
the pollutant cannot be emitted through a conveyance designed to emit
or capture the pollutant, or when there is no practicable measurement
methodology for the particular class of sources.\118\ CAA section
111(b)(1)(B) requires the EPA to ``at least every 8 years review and,
if appropriate, revise'' performance standards unless the
``Administrator determines that such review is not appropriate in light
of readily available information on the efficacy'' of the standard.
---------------------------------------------------------------------------
\118\ The EPA notes that design, equipment, work practice, or
operational standards established under CAA section 111(h) (commonly
referred to as ``work practice standards'') reflect the ``best
technological system of continuous emission reduction'' and that
this phrasing differs from the ``best system of emission reduction''
phrase in the definition of ``standard of performance'' in CAA
section 111(a)(1). Although the differences in these phrases may be
meaningful in other contexts, for purposes of evaluating the sources
and systems of emission reduction at issue in this rulemaking, the
EPA has applied these concepts in an essentially comparable manner
because the systems of emission reduction the EPA evaluated are all
technological.
---------------------------------------------------------------------------
As mentioned above, once the EPA lists a source category under CAA
section 111(b)(1)(A), CAA section 111(b)(1)(B) provides the EPA
discretion to determine the pollutants and sources to be regulated. In
addition, concurrent
[[Page 16848]]
with the 8-year review (and though not a mandatory part of the 8-year
review), the EPA may examine whether to add standards for pollutants or
emission sources not currently regulated for that source category.
Once the EPA establishes NSPS in a particular source category, the
EPA is required in certain circumstances to issue EG to reduce
emissions from existing sources in that same source category.
Specifically, CAA section 111(d) requires that the EPA prescribe
regulations to establish procedures under which states submit plans to
establish, implement, and enforce standards of performance for existing
sources for certain air pollutants to which a Federal NSPS would apply
if such existing source were a new source. The EPA addresses this CAA
requirement both through its promulgation of general implementing
regulations for CAA section 111(d) as well as through specific EG. The
EPA first published general implementing regulations in 1975, 40 FR
53340 (November 17, 1975) (codified at 40 CFR part 60, subpart B), and
has revised its CAA section 111(d) implementing regulations several
times. on the EPA published updated implementing regulations in 2019,
84 FR 32520 (codified at 40 CFR part 60, subpart Ba), which apply to EG
promulgated after July 8, 2019, 40 CFR 60.20a(a), including this EG,
and which were recently revised.\119\ In accordance with CAA section
111(d), states are required to submit plans pursuant to these
regulations to establish standards of performance for existing sources
for any air pollutant: (1) the emission of which is subject to a
Federal NSPS; and (2) which is neither a pollutant regulated under CAA
section 108(a) (i.e., criteria pollutants such as ground-level ozone
and particulate matter (PM), and their precursors, like VOC) \120\ nor
a HAP regulated under CAA section 112. See also definition of
``designated pollutant'' in 40 CFR 60.21a(a). The EPA's general
implementing regulations use the term ``designated facility'' to
identify those existing sources that may be subject to regulation under
the provision of CAA section 111(d). See 40 CFR 60.21a(b).
---------------------------------------------------------------------------
\119\ The D.C. Circuit vacated certain timing provisions within
subpart Ba. American Lung Ass'n, 985 F.3d 914. However, the court
did not vacate the applicability provision. Therefore, 40 CFR part
60, subpart Ba, applies to the final EG. On November 17, 2023, the
EPA issued final updates to the Agency's ``Implementing
Regulations'' under section 111(d) of the Clean Air Act (88 FR
80480). These final amendments address the provisions that were
vacated in 2021 and make other updates to the implementing
regulations applicable to this EG.
\120\ VOC are not listed as CAA section 108(a) pollutants, but
they are regulated precursors to photochemical oxidants (e.g.,
ozone), which is a listed CAA section 108(a) pollutant. Therefore,
VOC falls within the CAA 108(a) exclusion. Accordingly, promulgation
of NSPS for VOC does not trigger the application of CAA section
111(d).
---------------------------------------------------------------------------
While states are authorized to establish standards of performance
for designated facilities, there is a fundamental requirement under CAA
section 111(d) that a state's standards of performance in its state
plan submittal are no less stringent than the presumptive standard
determined by the EPA, which derives from the definition of ``standard
of performance'' in CAA section 111(a)(1). The EPA identifies the
degree of emission limitation achievable through application of the
BSER as part of its EG. See 40 CFR 60.22a(b)(5). While standards of
performance must generally reflect the degree of emission limitation
achievable through application of the BSER, CAA section 111(d)(1) also
requires that the EPA regulations permit the states, in applying a
standard of performance to a particular source, to take into account
the source's RULOF. States may apply less stringent standards of
performance to particular sources based on consideration of such
sources' remaining useful life and other factors.
After the EPA issues final EG per the requirements under CAA
section 111(d) and under 40 CFR part 60, subpart Ba, states are
required to submit to the EPA plans that establish standards of
performance for the designated facilities as defined in the EPA's
guidelines and that contain other measures to implement and enforce
those standards. The EPA's final EG issued under CAA section 111(d) do
not impose binding requirements directly on sources but instead provide
requirements for states in developing their plans and criteria for
assisting the EPA when judging the adequacy of such plans. Under CAA
section 111(d), and the EPA's implementing regulations, a state must
submit its plan to the EPA for approval; the EPA will evaluate the plan
for completeness in accordance with enumerated criteria and then will
act on that plan via a rulemaking process to either approve or
disapprove the plan in whole or in part. If a state does not submit a
plan, or if the EPA does not approve a state's plan because it is not
``satisfactory,'' then the EPA must establish a Federal plan for
designated facilities in that state.\121\ If the EPA approves a state's
plan, the provisions in the state plan become federally enforceable
against the designated facility responsible for compliance in the same
manner as the provisions of an approved State Implementation Plan (SIP)
under CAA section 110. If no designated facility is located within a
state, the state must submit to the EPA a letter certifying to that
effect in lieu of submitting a state plan. See 40 CFR 60.23a(b).
---------------------------------------------------------------------------
\121\ CAA section 111(d)(2)(A).
---------------------------------------------------------------------------
Designated facilities located in Indian country would not be
addressed by a state's CAA section 111(d) plan. Instead, an eligible
Tribe that has one or more designated facilities located in its area of
Indian country \122\ would have the opportunity, but not the
obligation, to seek authority and submit a plan that establishes
standards of performance for those facilities on its Tribal lands.\123\
If a Tribe does not submit a plan, or if the EPA does not approve a
Tribe's plan, then the EPA has the authority to establish a Federal
plan for the designated facilities located on its Tribal land.\124\
---------------------------------------------------------------------------
\122\ The EPA is aware of many oil and natural gas operations
located in Indian country.
\123\ See 40 CFR part 49, subpart A.
\124\ CAA section 111(d)(2)(A).
---------------------------------------------------------------------------
B. What is the regulatory history and litigation background of NSPS and
EG for the oil and natural gas industry?
1. 1979 Listing of Source Category
Subsequent to the enactment of the CAA of 1970, the EPA took action
to develop standards of performance for new stationary sources as
directed by Congress in CAA section 111. By 1977, the EPA had
promulgated NSPS for a total of 27 source categories, while NSPS for an
additional 25 source categories were then under development.\125\
However, in amending the CAA that year, Congress expressed
dissatisfaction that the EPA's pace was too slow. Accordingly, the 1977
CAA Amendments included a new subsection (f) in section 111, which
specified a schedule for the EPA to list additional source categories
under CAA section 111(b)(1)(A) and prioritize them for regulation under
CAA section 111(b)(1)(B).
---------------------------------------------------------------------------
\125\ See 44 FR 49222 (August 21, 1979).
---------------------------------------------------------------------------
In 1979, as required by CAA section 111(f), the EPA published a
list of source categories, which included ``Crude Oil and Natural Gas
Production,'' for which the EPA would promulgate standards of
performance under CAA section 111(b). See ``Priority List and Additions
to the List of Categories of Stationary Sources,'' 44 FR 49222 (August
21, 1979) (``1979 Priority List''). That list included, in the order of
priority for promulgating standards, source categories that the EPA
Administrator had determined, pursuant to CAA section 111(b)(1)(A),
[[Page 16849]]
contribute significantly to air pollution that may reasonably be
anticipated to endanger public health or welfare. See 44 FR 49223
(August 21, 1979); see also 49 FR 2636-37 (January 20, 1984).
2. 1985 NSPS for VOC and SO2 Emissions From Natural Gas
Processing Plants
On June 24, 1985 (50 FR 26122), the EPA promulgated NSPS for the
Crude Oil and Natural Gas source category that addressed VOC emissions
from equipment leaks at onshore natural gas processing plants (40 CFR
part 60, subpart KKK). On October 1, 1985 (50 FR 40158), the EPA
promulgated additional NSPS for the source category to regulate
SO2 emissions from onshore natural gas processing plants (40
CFR part 60, subpart LLL).
3. 2012 NSPS OOOO Rule and Related Amendments
In 2012, pursuant to its duty under CAA section 111(b)(1)(B) to
review and, if appropriate, revise the 1985 NSPS, the EPA published the
final rule, ``Standards of Performance for Crude Oil and Natural Gas
Production, Transmission and Distribution,'' 77 FR 49490 (August 16,
2012) (40 CFR part 60, subpart OOOO) (``2012 NSPS OOOO''). The 2012
rule updated the SO2 standards for sweetening units and the
VOC standards for equipment leaks at onshore natural gas processing
plants. In addition, it established VOC standards for several oil and
natural gas-related operations emission sources not covered by 40 CFR
part 60, subparts KKK and LLL, including natural gas well completions,
centrifugal and reciprocating compressors, certain natural gas-driven
process controllers in the production and processing segments of the
industry, and storage vessels in the production, processing, and
transmission and storage segments.
In 2013, 2014, and 2015 the EPA amended the 2012 NSPS OOOO rule in
order to address implementation of the standards. ``Oil and Natural Gas
Sector: Reconsideration of Certain Provisions of New Source Performance
Standards,'' 78 FR 58416 (September 23, 2013) (``2013 NSPS OOOO'')
(concerning storage vessel implementation); ``Oil and Natural Gas
Sector: Reconsideration of Additional Provisions of New Source
Performance Standards,'' 79 FR 79018 (December 31, 2014) (``2014 NSPS
OOOO'') (concerning well completion); ``Oil and Natural Gas Sector:
Definitions of Low Pressure Gas Well and Storage Vessel,'' 80 FR 48262
(August 12, 2015) (``2015 NSPS OOOO'') (concerning low-pressure gas
wells and storage vessels).
The EPA received petitions for both judicial review and
administrative reconsiderations for the 2012, 2013, and 2014 NSPS OOOO
rules. The EPA denied reconsideration for some issues, see
``Reconsideration of the Oil and Natural Gas Sector: New Source
Performance Standards; Final Action,'' 81 FR 52778 (August 10, 2016),
and, as noted below, granted reconsideration for other issues. As
explained below, all litigation related to NSPS OOOO is currently in
abeyance.
4. 2016 NSPS OOOOa Rule and Related Amendments
a. Regulatory Action
On June 3, 2016, the EPA published a final rule titled, ``Oil and
Natural Gas Sector: Emission Standards for New, Reconstructed, and
Modified Sources; Final Rule,'' at 81 FR 35824 (40 CFR part 60, subpart
OOOOa) (``2016 Rule'' or ``2016 NSPS OOOOa'').126 127 The
2016 NSPS OOOOa rule established NSPS for sources of GHGs and VOC
emissions for certain equipment, processes, and operations across the
oil and natural gas industry, including in the transmission and storage
segment (81 FR 35832). The EPA explained that the 1979 listing
identified the source category broadly enough to include that segment
and, in the alternative, if the listing had limited the source category
to the production and processing segments, the EPA affirmatively
expanded the source category to include the transmission and storage
segment on grounds that operations in those segments are a sequence of
functions that are interrelated and necessary for getting the recovered
gas ready for distribution (81 FR 35832). In addition, because the 2016
rule represented the first time that the EPA had promulgated NSPS for
GHG emissions from the Crude Oil and Natural Gas source category, the
EPA predicated those NSPS on a determination that it had a rational
basis on which to regulate GHG emissions from the source category (81
FR 35843). In response to comments, the EPA explained that it was not
required to make an additional pollutant-specific finding that GHG
emissions from the source category contribute significantly to
dangerous air pollution, but in the alternative, the EPA did make such
a finding, relying on the same information that it relied on when
determining that it had a rational basis on which to promulgate a GHG
NSPS (81 FR 35843).
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\126\ The June 3, 2016, rulemaking also included certain final
amendments to 40 CFR part 60, subpart OOOO, to address issues on
which the EPA had granted reconsideration.
\127\ The EPA review which resulted in the 2016 NSPS OOOOa rule
was instigated by a series of directives from then-President Obama
targeted at reducing GHGs, including methane: the President's
Climate Action Plan (June 2013); the President's Climate Action
Plan: Strategy to Reduce Methane Emissions (``Methane Strategy'')
(March 2014); and the President's goal to address, propose and set
standards for methane and ozone-forming emissions from new and
modified sources in the sector (January 2015, https://obamawhitehouse.archives.gov/the-press-office/2015/01/14/fact-sheet-Administration-takes-steps-forward-climate-action-plan-anno-1).
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Specifically, the 2016 NSPS OOOOa addresses the following emission
sources:
Sources that were unregulated under the 2012 NSPS OOOO
(hydraulically fractured oil well completions, pneumatic pumps, and
fugitive emissions from well sites and compressor stations);
Sources that were regulated under the 2012 NSPS OOOO for
VOC emissions, but not for GHG emissions (hydraulically fractured gas
well completions and equipment leaks at natural gas processing plants);
and
Certain equipment that is used across the source category,
of which the 2012 NSPS OOOO regulated emissions of VOC from only a
subset (process controllers, centrifugal compressors, and reciprocating
compressors, with the exception of those compressors located at well
sites).
On March 12, 2018 (83 FR 10628), the EPA finalized amendments to
certain aspects of the 2016 NSPS OOOOa requirements for the collection
of fugitive emissions components at well sites and compressor stations,
specifically (1) the requirement that components on a delay of repair
must conduct repairs during unscheduled or emergency vent blowdowns,
and (2) the monitoring survey requirements for well sites located on
the Alaska North Slope.
b. Petitions for Judicial Review and To Reconsider
Following promulgation of the 2016 NSPS OOOOa rule, several states
and industry associations challenged the final rule in the D.C.
Circuit. The Administrator also received five petitions for
reconsideration of several provisions of the final rule. Copies of the
petitions are posted in Docket ID No. EPA-HQ-OAR-2010-0505.\128\ As
noted below, the EPA granted reconsideration as to several issues
raised with respect to the 2016 NSPS OOOOa rule and finalized certain
modifications discussed in the next section of this document. As
explained in the next section, all litigation challenging the
[[Page 16850]]
2016 NSPS OOOOa rule is currently stayed.
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\128\ See Document ID Nos. EPA-HQ-OAR-2010-0505-7682, -7683, -
7684, -7685, -7686.
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5. 2020 Policy and Technical Rules
a. Regulatory Action
In September 2020, the EPA published two final rules to amend 2012
NSPS OOOO and 2016 NSPS OOOOa. The first is titled, ``Oil and Natural
Gas Sector: Emission Standards for New, Reconstructed, and Modified
Sources Review.'' 85 FR 57018 (September 14, 2020). Commonly referred
to as the 2020 Policy Rule, it first rescinded the regulations
applicable to the transmission and storage segment on the basis that
the 1979 listing limited the source category to the production and
processing segments and that the transmission and storage segment is
not ``sufficiently related'' to the production and processing segments
and therefore cannot be part of the same source category (85 FR 57027,
57029). In addition, the 2020 Policy Rule rescinded methane
requirements for the industry's production and processing segments on
two separate bases. The first was that such standards are redundant to
VOC standards for these segments (85 FR 57030). The second was that the
rule interpreted CAA section 111 to require, or at least authorize the
Administrator to require, a pollutant-specific ``significant
contribution finding'' (SCF) as a prerequisite to a NSPS for a
pollutant, and to require that such finding be supported by some
identified standard or established set of criteria for determining
which contributions are ``significant'' (85 FR 57034). The 2020 Policy
Rule went on to conclude that the alternative significant-contribution
finding that the EPA made in the 2016 Rule for GHG emissions was flawed
because it accounted for emissions from the transmission and storage
segment and because it was not supported by criteria or a threshold (85
FR 57038).\129\
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\129\ Following the promulgation of the 2020 Policy Rule, the
EPA promulgated a final rule that identified a standard or criteria
for determining which contributions are ``significant,'' which the
D.C. Circuit vacated. ``Pollutant-Specific Significant Contribution
Finding for Greenhouse Gas Emissions From New, Modified, and
Reconstructed Stationary Sources: Electric Utility Generating Units,
and Process for Determining Significance of Other New Source
Performance Standards Source Categories.'' 86 FR 2542 (January 13,
2021), vacated by California v. EPA, No. 21-1035 (D.C. Cir.) (Order,
April 5, 2021, Doc. #1893155).
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Published on September 15, 2020, the second of the two rules is
titled, ``Oil and Natural Gas Sector: Emission Standards for New,
Reconstructed, and Modified Sources Reconsideration.'' Commonly
referred to as the 2020 Technical Rule, this second rule made further
amendments to the 2016 NSPS OOOOa following the 2020 Policy Rule to
eliminate or reduce certain monitoring obligations and to address a
range of issues in response to administrative petitions for
reconsideration and other technical and implementation issues brought
to the EPA's attention since the 2016 NSPS OOOOa rulemaking.
Specifically, the 2020 Technical Rule exempted low production well
sites from fugitives monitoring (previously required semiannually),
required semiannual monitoring at gathering and boosting compressor
stations (previously quarterly), streamlined recordkeeping and
reporting requirements, allowed compliance with certain equivalent
state requirements as an alternative to NSPS fugitive requirements,
streamlined the application process to request the use of new
technologies to monitor for fugitive emissions, addressed storage tank
batteries for applicability determination purposes and finalized
several technical corrections. Because the 2020 Technical Rule was
issued the day after the EPA's rescission of methane regulations in the
2020 Policy Rule, the amendments made in the 2020 Technical Rule
applied only to the requirements to regulate VOC emissions from this
source category. The 2020 Policy Rule amended 40 CFR part 60, subparts
OOOO and OOOOa, as finalized in 2016. The 2020 Technical Rule amended
the 40 CFR part 60, subpart OOOOa, as amended by the 2020 Policy Rule.
b. Petitions To Reconsider
The EPA received three petitions for reconsideration of the 2020
rulemakings. Two of the petitions sought reconsideration of the 2020
Policy Rule. As discussed below, on June 30, 2021, the President signed
into law S.J. Res. 14, a joint resolution under the CRA disapproving
the 2020 Policy Rule, and as a result, the petitions for
reconsideration on the 2020 Policy Rule are now moot. All three
petitions sought reconsideration of certain elements of the 2020
Technical Rule.
c. Litigation
Several states and non-governmental organizations (NGOs) challenged
the 2020 Policy Rule as well as the 2020 Technical Rule. All petitions
for review regarding the 2020 Policy Rule were consolidated into one
case in the D.C. Circuit. State of California, et al. v. EPA, No. 20-
1357. On August 25, 2021, after the enactment of the joint resolution
of Congress disapproving the 2020 Policy Rule (explained in section
VIII of this preamble), the U.S. Court of Appeals for the District of
Columbia Circuit (i.e., the court) granted petitioners' motion to
voluntarily dismiss their cases. Id. ECF Docket #1911437. All petitions
for review regarding the 2020 Technical Rule were consolidated into a
different case in the D.C. Circuit. Environmental Defense Fund (EDF),
et al. v. EPA, No. 20-1360 (D.C. Cir.). On February 19, 2021, the court
issued an order granting a motion by the EPA to hold in abeyance the
consolidated litigation over the 2020 Technical Rule pending the EPA's
rulemaking actions in response to E.O. 13990 and pending the conclusion
of the EPA's potential reconsideration of the 2020 Technical Rule. Id.
ECF Docket #1886335.
As mentioned above, the EPA received petitions for judicial review
regarding the 2012, 2013, and 2014 NSPS OOOO rules as well as the 2016
NSPS OOOOa rule. The challenges to the 2012 NSPS OOOO rule (as amended
by the 2013 NSPS OOOO and 2014 NSPS OOOO rules) were consolidated.
American Petroleum Institute v. EPA, No. 13-1108 (D.C. Cir.). The
majority of those cases were further consolidated with the consolidated
challenges to the 2016 NSPS OOOOa rule. West Virginia v. EPA, No. 16-
1264 (D.C. Cir.), see specifically ECF Docket #1654072. As such, West
Virginia v. EPA includes challenges to the 2012 NSPS OOOO rule (as
amended by the 2013 NSPS OOOO and 2014 NSPS OOOO rules) as well as
challenges to the 2016 NSPS OOOOa rule.\130\ On December 10, 2020, the
court granted a joint motion of the parties in West Virginia v. EPA to
hold that case in abeyance until after the mandate has issued in the
case regarding challenges to the 2020 Technical Rule. West Virginia v.
EPA, ECF Docket #1875192.
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\130\ When the EPA issued the 2016 NSPS OOOOa rule, a challenge
to the 2012 NSPS OOOO rule for failing to regulate methane was
severed and assigned to a separate case, NRDC v. EPA, No. 16-1425
(D.C. Cir.), pending judicial review of the 2016 NSPS OOOOa in
American Petroleum Institute v. EPA, No. 13-1108 (D.C. Cir.).
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C. Congressional Review Act (CRA) Joint Resolution of Disapproval
On June 30, 2021, the President signed into law a joint resolution
of Congress, S.J. Res. 14, adopted under the CRA,\131\ disapproving the
2020 Policy Rule.\132\ By the terms of the CRA, the signing into law of
the CRA joint resolution of disapproval means that the
[[Page 16851]]
2020 Policy Rule is ``treated as though [it] had never taken effect.''
5 U.S.C. 801(f). As a result, the VOC and methane standards for the
transmission and storage segment, as well as the methane standards for
the production and processing segments--all of which had been rescinded
in the 2020 Policy Rule--remain in effect. In addition, the EPA's
authority and obligation to require the states to regulate existing
sources of methane in the Crude Oil and Natural Gas source category
under section 111(d) of the CAA also remains in effect.
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\131\ The Congressional Review Act was adopted in Subtitle E of
the Small Business Regulatory Enforcement Fairness Act of 1996.
\132\ ``Oil and Natural Gas Sector: Emission Standards for New,
Reconstructed, and Modified Sources Review,'' 85 FR 57018 (September
14, 2020) (``2020 Policy Rule'').
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The CRA resolution did not address the 2020 Technical Rule.
Therefore, those amendments remain in effect with respect to the VOC
standards for the production and processing segments in effect at the
time of its enactment. As part of this rulemaking, in section XII of
this document the EPA discusses the impact of the CRA resolution and
identifies and finalizes appropriate changes to reinstate the
regulatory text that had been rescinded by the 2020 Policy Rule and to
resolve any discrepancies in the regulatory text between the 2016 NSPS
OOOOa Rule and 2020 Technical Rule.\133\
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\133\ The EPA understands that a limited number of affected
facilities may have obtained, renewed, or revised a title V permit
to reflect the 2020 Policy Rule, and that such permits no longer
include certain applicable requirements from the 2012 NSPS OOOO and
2016 NSPS OOOOa regulations that were reinstated by the CRA. The EPA
strongly encourages states to reopen Title V permits that currently
reflect the 2020 Policy Rule, and to follow all appropriate
requirements of 40 CFR 70.7(f) governing the reopening of Title V
permits.
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V. Legal Basis for Final Rule Scope
A. Introduction
The EPA finalizes this rulemaking to revise certain NSPS, to
promulgate additional NSPS for both methane and VOC emissions from new
oil and gas sources in the production, processing, and transmission and
storage segments of the industry; and to promulgate EG to require
states to regulate methane emissions from existing sources in those
segments. The large amount of methane emissions from the oil and
natural gas industry--by far, the largest methane-emitting industry in
the nation--coupled with the adverse effects of methane on the global
climate compel expeditious regulatory action to mitigate those
emissions. This section explains the EPA's legal authority for
proceeding with this final action, including regulating methane and
VOCs from sources in all segments of the source category, and in so
doing, responds to the principal comments received.
In the November 2021 Proposal and the December 2022 Supplemental
Proposal, the EPA discussed the history of our regulatory actions for
oil and gas sources in the 2016 NSPS OOOOa and the 2020 Policy Rule.
See 85 FR 63147-53, 86 FR74719-20. These discussions explained the key
statutory interpretations and determinations, which we sometimes refer
to as the key positions, taken in the 2016 rule that serve as the basis
for this action, as well as Congress's endorsement of those positions
in adopting the 2021 CRA joint resolution to disapprove the 2020 rule
and thereby reinstate the 2016 rule. These discussions further
explained that the EPA was not reopening those positions in this
rulemaking, but added, for the purpose of informing the public, that
the EPA would continue to take the same positions even if Congress had
not adopted the joint resolution. The EPA includes those discussions by
reference here, and the rest of this section assumes familiarity with
them. For convenience, the EPA summarizes them immediately below. The
EPA then summarizes the principal comments received and responds to the
most significant adverse comments. For the purpose of providing more
information to the public, and without reopening the positions in the
2016 rule, the EPA explains why we would take the same positions as in
the 2016 rule even if Congress had not adopted the joint resolution as
well as the implications of the joint resolution and its legislative
history in foreclosing commenters' objections.
B. Overview
This section summarizes why the statutory interpretations the EPA
took in the 2016 Rule were correct and why the contrary interpretations
taken in the congressionally-voided 2020 Policy Rule were
incorrect.\134\ These views are confirmed by Congress's reasoning in
the legislative history of the CRA resolution and so, for convenience,
this section refers to that legislative history as well.
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\134\ Under F.C.C. v. Fox Television Stations, Inc., 556 U.S.
502 (2009), an agency may revise its policy, but must demonstrate
that the new policy is permissible under the statute and is
supported by good reasons, taking into account the record of the
previous rule. To the extent that this standard applies in this
action--where Congress has disapproved the 2020 Policy Rule--the EPA
believes the explanations provided here satisfy the standard.
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The 2016 NSPS OOOOa established the EPA's authority to regulate GHG
emissions from the Crude Oil and Natural Gas source category, in the
form of limits on methane emissions. In that rule, the EPA explained
that the source category, as the EPA listed it in 1979 for regulation
under CAA section 111(b)(1)(A), included the production and processing
as well as transmission and storage segments. The EPA also explained
that it was justified in promulgating standards of performance for GHG
emissions from new sources in the source category because it had a
rational basis for doing so. In response to comments, the EPA further
explained that once it had listed a source category, it was not
required to make, as a predicate to regulating GHG emissions from the
source category, an additional pollutant-specific finding that those
GHG emissions contribute significantly to dangerous air pollution
(termed, a pollutant-specific significant contribution finding).
In addition to providing those explanations, the EPA made two
determinations in the 2016 NSPS OOOOa that established alternative
legal bases for the GHG NSPS. The first was that the EPA re-listed the
source category under CAA section 111(b)(1)(A). To do so, the EPA
determined the following: (i) In case the source category did not
already include the transmission and storage segment, the EPA revised
the source category to include that segment, along with the production
and processing segments. The EPA explained that all the segments are
interrelated because they comprise parts of a single process of
extracting natural gas and preparing it for commercial sale, and that
many of the same types of equipment are used in the various segments.
(ii) By dint of its emissions of VOC, SO2, and GHG, the
source category thus defined ``causes or contributes significantly to
air pollution which may reasonably be anticipated to endanger public
health or welfare,'' under CAA section 111(b)(1)(A). 81 FR 25833-40.
For convenience, we refer to this as the endangerment finding, and
treat it as having two components: the significant contribution finding
and the finding of dangerous air pollution. The second determination
was that, in the alternative, if it were necessary to make a pollutant-
specific significant contribution finding for GHG emissions as a
predicate to promulgating NSPS for GHG from the source category, then
the 2016 rule made such a finding. To do so, the rule relied on
information concerning the large amounts of methane emissions from the
source category. 81 FR 35843.
The 2020 Policy Rule rescinded the above statutory interpretations
and determinations. 85 FR 57018. The rule asserted that the
transmission and storage segment was not properly included as part of
the same source
[[Page 16852]]
category as the production and processing segments, and was therefore
not subject to regulation under CAA section 111. The rule took the
position that the transmission and storage segment had not been
included in the source category when it was originally listed in 1979,
and the 2016 rule's alternative determination to revise the source
category was flawed because that segment was not interrelated with the
production and processing segments. The rule further asserted that the
EPA did not have authority to promulgate NSPS for methane emissions
from sources in the production and processing segments because those
NSPS were redundant to NSPS for VOC emissions from those sources. The
rule further asserted, in the alternative, that the EPA did not have
such authority because it was required to make, or was at least
authorized to require, a pollutant-specific significant contribution
finding for GHG emissions from production and processing sources as a
predicate for promulgating NSPS for methane emissions. The rule
explained that such a finding was necessary because the EPA had not
considered GHG emissions when it listed the source category in 1979.
The rule further asserted that the pollutant-specific significant
contribution finding in the 2016 NSPS OOOOa was flawed because it had
been based in part on emissions from the transmission and storage
segment, which, in the rule's view, were not part of the oil and gas
source category, and because the EPA had not first established a
standard or criteria for determining when emissions contribute
significantly, as opposed to simply contribute, to dangerous air
pollution. 85 FR 57024-40.
The CRA joint resolution, signed into law by President Biden on
June 30, 2021, disapproved the 2020 Policy Rule, and thereby reinstated
the 2016 NSPS OOOOa regulation of sources in the transmission and
storage segment and regulation of methane emissions from the entire oil
and gas source category. 86 FR 63135-36. The legislative history of the
CRA resolution--the House Report and a floor statement from Senate
sponsors, 167 Cong. Rec. S2282-83 (April 28, 2021) (statement by Sen.
Heinrich) (Senate Statement)--made clear Congress's intent that the EPA
must regulate methane from the source category under CAA section 111,
due to the large amount and impact of those emissions. The legislative
history went on to make clear that Congress's basis for disapproving
the 2020 rule was that Congress rejected each of the legal
interpretations, described above, that underlay the rule. Specifically,
the legislative history stated that: the rule was incorrect in removing
the transmission and storage segment from the source category;
promulgation of NSPS for methane was not redundant with promulgation of
NSPS for VOCs, in light of the fact that the former, but not the
latter, triggers the requirement to promulgate emission guidelines for
existing sources under CAA section 111(d); the EPA is required to
promulgate NSPS for a pollutant from a source category when the EPA has
a rational basis for doing so, and the EPA cannot decline to promulgate
a NSPS on grounds that it is required, or authorized to require, a
pollutant-specific significant contribution finding; and the EPA's past
approach of relying on a facts-and-circumstances approach to determine
significance is acceptable, and an established standard or criteria are
not necessary.
In the November 2021 Proposal, the EPA confirmed that it agreed
with those interpretations. 86 FR 63151. In the December 2022
Supplemental Proposal, the EPA added that if it were required to make a
pollutant-specific significant contribution finding, it would not be
required to specify a standard or criterion for determining
significance, and that if it were so required, methane emissions from
the source category are so large that they would be significant under
any reasonable standard or criterion. 87 FR 74719-20 (explaining that
the ``massive quantities of methane emissions'' from the source
category, combined with the ``potency of methane'' are significant in
light of, among other things, the fact that the oil and gas sector
accounts for 28 percent of U.S. methane emissions or more than the
total national emissions of over 160 countries).\135\
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\135\ As noted above, to the extent that the standard of Fox
Television applies in this action--where Congress has disapproved
the 2020 Policy Rule--the EPA believes the explanations provided
here satisfy the standard.
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C. Comments
Some stakeholders commented adversely. They assert that the
November 2021 Proposal and the December 2022 Supplemental Proposal
contain what they see as the same flaws as the 2016 NSPS OOOOa. One of
these flaws, these commenters assert, is that the EPA is precluded from
promulgating requirements for sources in the transmission and storage
segment without first listing that segment as a separate source
category and making an endangerment finding for GHG emissions from it.
According to this view, the source category as listed in 1979 did not
include that segment, and that segment must be treated as a separate
source category because otherwise, the agency could expand a
preexisting source category incrementally, and thereby avoid the CAA
section 111 requirements to undertake an endangerment finding before
promulgating regulation. A second flaw, according to these commenters,
is that regulation of methane is redundant to regulation of VOC. In
addition, the commenters assert that CAA section 111 precludes the EPA
from promulgating requirements for GHG emissions from the source
category without first making a pollutant-specific endangerment
finding, including a pollutant-specific significant contribution
finding. Moreover, according to the commenters, such a finding must be
for methane. In addition, it must be based on an established standard
or criteria for determining significance; otherwise, such a finding
would be arbitrary and capricious. According to these commenters, CAA
section 111 does not authorize the EPA to regulate air pollutants from
a listed source category on the grounds that it has a rational basis
for such regulation. These commenters further assert that although the
CRA resolution disapproved the 2020 Policy Rule, it did not change the
underlying requirements of CAA section 111, so that these flaws in the
EPA's regulatory approach remained. They argue that only the
legislative language of the joint resolution, and not the accompanying
legislative history, is relevant.
Other commenters supported the November 2021 Proposal and December
2022 Supplemental Proposal. They state that the 2016 NSPS OOOOa
established an appropriate basis for promulgating regulations to
control methane emissions from the oil and gas industry. They state
that the 1979 source category listing included the transmission and
storage segment, and that in any event, the 2016 rule correctly
determined that the transmission and storage segment was interrelated
with the other segments and thus merited inclusion in the revised
source category. They also state that regulation of methane from this
source category is not redundant to regulation of VOCs. They add that
because the EPA previously determined that the oil and gas source
category causes or contributes significantly to dangerous air
pollution, the EPA is authorized to promulgate a NSPS for methane
because it is rational to do so in light of the large amount of methane
emissions from the source category. For
[[Page 16853]]
this reason, commenters assert, it would be arbitrary and capricious
for the EPA to decline to regulate methane emissions from the source
category. Commenters add that a pollutant-specific significant
contribution or endangerment finding for methane is neither necessary
nor authorized by CAA section 111; that any such findings under CAA
section 111 should be made on the basis of the facts and circumstances,
and not a predetermined standard or threshold; and that in any event,
the large amounts of methane emissions from the source category must be
considered to be significant under any reasonable definition.
Commenters also note that the 2016 rule made an appropriate significant
finding contribution for GHG from the source category in the
alternative. Commenters also assert that Congress's disapproval of the
2020 Policy Rule through the CRA joint resolution reaffirmed the 2016
rule's positions.
D. Response to Comments and Discussion
The adverse arguments by commenters described above concern the
positions in the 2016 NSPS OOOOa, which also provide the basis for this
rulemaking, and the significance of the CRA joint resolution and its
legislative history. The commenters' arguments concerning the positions
in the 2016 rule were rejected in the 2016 rule itself, adopted in the
2020 Policy Rule, and then rejected in the legislative history of the
joint resolution. The EPA stated in the November 2021 Proposal and
December 2022 Supplemental Proposal that it was not reopening these
positions, and we maintain that decision here. However, again, solely
for the purpose of informing the public, we provide responses to the
commenters' arguments immediately below and in the response to comment
document. Our decision not to reopen the positions in the 2016 rule
does not apply to issues concerning the joint resolution, which post-
dated the 2016 rule. Accordingly, the EPA responds in more detail
further below to the commenters' arguments concerning the joint
resolution.
1. Commenters' Arguments Concerning the Key Positions in the 2016 NSPS
OOOOa
Stakeholders submitted adverse comments on key positions, including
statutory interpretations and determinations, that the EPA made in the
2016 NSPS OOOOa and that serve as the foundation for the present
action. These adverse comments generally mirrored those made in the
course of the 2016 NSPS OOOOa rulemaking and the rationale for the 2020
Policy Rule, and did not raise significant new points not addressed in
the 2016 NSPS OOOOa or the November 2021 Proposal and December 2022
Supplemental Proposal. The EPA continues to disagree with those
comments.
a. Scope of the Oil and Gas Source Category as Listed in 1979
i. Scope of the Source Category as Listed in 1979
The 2016 NSPS OOOOa stated that the Crude Oil and Natural Gas
Production source category, as the EPA listed it for regulation under
CAA section 111(b)(1)(A) in 1979, included the transmission and storage
segment, along with the other two major segments of the industry, the
production and processing segments. Based on this understanding, the
EPA continued to promulgate NSPS for sources in that segment, after it
had begun to do so in the 2012 NSPS OOOO. Adverse commenters on the
November 2021 Proposal took the contrary view, reiterating adverse
comments on the 2016 rule. However, the 2016 rule was correct--the
EPA's 1979 listing of the source category should be considered to have
included the transmission and storage segment.
The commenters' argument stems from the fact that the 1979 listing,
44 FR 49222 (Aug. 21, 1979) (1979 Listing Rule), identified the source
category as ``Crude Oil and Natural Gas Production,'' and did not
specifically identify the transmission and storage segment as part of
the source category. See 44 FR 49222 (citing Priorities for New Source
Performance Standards Under the Clean Air Act Amendments of 1977, EPA-
450/3-78-019 (April 1978) (``1978 Priority List'')). This argument
fails to recognize the comprehensive approach that the EPA undertook in
the 1979 Listing Rule, which strongly indicates that the oil and gas
source category included the transmission and storage segment. In the
1979 Listing Rule, the EPA determined that numerous source categories
met the CAA section 111(b)(1)(B) requirements to be listed for
regulation. The EPA based that determination on a study it had
undertaken in 1978, the 1978 Priorities List, that comprehensively
identified all source categories in the United States--203 in number--
and indicated which ones should and should not be listed. That study
identified the oil and gas source category as the ``Crude Oil and
Natural Gas Production Plants,'' a name that referenced only the
production segment of the oil and gas industry. However, the study, and
the 1979 Listing Rule, which identified the source category as ``Crude
Oil and Natural Gas Production,'' clearly intended the source category
to be broader than just that segment, consistent with the fact that the
1978 Priorities List was designed to be comprehensive. This is evident
because in 1985, the EPA promulgated the first set of NSPS for the
source category, which concerned sources in the processing segment, not
the production segment. 50 FR 26122 (June 24, 1985) (VOC emissions from
equipment leaks), 50 FR 40158 (Oct. 1, 1985) (SO2
emissions). It is evident that the source category, as listed in 1979,
also included the third major segment of the industry, the transmission
and storage segment. Otherwise, the 1978 Priorities List, which was
designed to be comprehensive, would have completely overlooked this
major segment, which is not plausible.
ii. Alternative Determination in 2016 NSPS OOOOa To Include
Transmission and Storage Segment in Source Category
In addition, in the 2016 NSPS OOOOa, in the alternative, and on the
assumption that the source category as listed in 1979 did not include
the transmission and storage segment, the EPA revised the source
category to include that segment, and relisted that source category--
which it termed the Crude Oil and Natural Gas source category--under
CAA section 111(b)(1)(A). 81 FR 35832-40. This alternative
determination further addresses commenters' objections.
The EPA has broad discretion in determining the scope of the source
category, which is reviewable under the arbitrary and capricious
standard of CAA section 307(d)(9). In the 2016 NSPS OOOOa, the EPA
determined that the transmission and storage segment was
``interrelated'' with the production and processing segments and
therefore should be included in the same source category, the EPA
provided sound reasons for doing so. 81 FR 35832. This reasoning is
consistent with the ordinary understanding of the term, ``category.''
Merriam-Webster defines ``category'' as ``any of several fundamental
and distinct classes to which entities or concepts belong,'' \136\ and
it defines a ``class [ ]'' as ``a group, set, or kind sharing common
attributes.'' \137\ Treating all those
[[Page 16854]]
segments as part of the source category meets this definition because,
as the EPA explained in the 2016 NSPS OOOOa, the segments all included
operations that were a sequence of functions in a multi-step process
that is necessary to achieve the common goal of preparing recovered gas
for distribution. Moreover, the segments had common equipment and
control technology. 81 FR 35832. In the 2016 rule, the EPA went on to
assess the air pollutants emitted from the source category, including
VOC, SO2, and GHG; as well as the associated air pollution,
including hazardous air pollution, tropospheric ozone, SO2,
and atmospheric GHG; and determined that the source category causes or
contributes significantly to air pollution which may reasonably be
anticipated to endanger public health or welfare. Id. 35840. The EPA
has not reopened that endangerment finding.
---------------------------------------------------------------------------
\136\ ``Category.'' Merriam-Webster.com Dictionary, Merriam-
Webster, https://www.merriamwebster.com/dictionary/category.
Accessed Sept. 25, 2023.
\137\ ``Class.'' Merriam-Webster.com Dictionary, Merriam-
Webster, https://www.merriamwebster.com/dictionary/class. Accessed
Sept. 25, 2023.
---------------------------------------------------------------------------
This re-listing addresses the commenters' objections concerning the
regulation of sources in the transmission and storage segment. By
properly including the segment in a source category and listing that
source category under CAA section 111(b)(1)(A), the EPA established the
predicate for such regulation.
b. Reliance on Rational Basis Test, and Rejection of Pollutant-Specific
Significant Contribution Finding, for Regulating GHG From the Source
Category
In the 2016 NSPS OOOOa, the EPA interpreted CAA section 111 to
authorize regulation of methane emissions from the oil and gas source
category because the large amount of those emissions provided a
rational basis for such regulation. 81 FR 35842. The EPA went on to
determine that it had a rational basis to regulate methane emissions
from the source category on grounds that, among other things, the oil
and gas industry is the largest industrial emitter of methane in the
U.S. Id. 35842-43. As stated in section III, human emissions of
methane, a potent GHG, are responsible for about one third of the
warming due to well-mixed GHGs, which makes methane the second most
important human warming agent after carbon dioxide.\138\ The EPA has
not reopened that determination in the present rulemaking.
---------------------------------------------------------------------------
\138\ See preamble section III.A. for further discussion on the
Crude Oil and Natural Gas Emissions and Climate Change, including
discussion of the GHGs, VOCs and SO2 Emissions on Public
Health and Welfare.
---------------------------------------------------------------------------
However, commenters asserted that under CAA section 111, a rational
basis determination is insufficient as a predicate for regulation, and,
instead, the EPA was required to determine that methane emissions from
the oil and gas source category cause or contribute significantly to
air pollution that is reasonably anticipated to endanger public health
or welfare. Commenters took this same position in the 2016 NSPS OOOOa.
For the reasons discussed immediately below, we disagree with
commenters and we confirm the position in the 2016 rule. As we discuss
further below, the 2016 rule also addressed commenters' objections by
making a finding that the GHG emissions from the oil and gas source
category contribute significantly to dangerous air pollution.
CAA section 111 is clear in authorizing the EPA to regulate air
pollutants from a listed source category if it has a rational basis for
doing so, and does not require, or authorize the EPA to require, a
pollutant-specific significant contribution finding or endangerment
finding as a predicate for such regulation. CAA section 111(b)(1)(A)
requires the EPA to ``publish . . . a list of categories of stationary
sources'' for regulation, and to ``include a source category in such
list if . . . it causes, or contributes significantly to, air pollution
which may reasonably be anticipated to endanger public health or
welfare.'' CAA section 111(b)(1)(B) provides that within a specified
time after listing the source category, the EPA shall promulgate
``standards of performance for new sources within such category.'' CAA
section 111(a)(1) defines ``standard of performance'' (in the singular)
as ``a standard for emissions of air pollutants'' that is determined in
a particular manner. CAA section 307(d)(1)(C) provides that the EPA's
promulgation of standards of performance under CAA section 111 are
subject to the requirements of CAA section 307(d). Those requirements
include the judicial review provisions of CAA section 307(d)(9)(A),
which provide that a court may reverse standards of performance ``found
to be arbitrary, capricious, an abuse of discretion, or otherwise not
in accordance with law.''
By their terms, these provisions require the EPA to make an
endangerment finding, including a significant contribution finding, for
a source category as a predicate to promulgating standards of
performance, and they establish detailed requirements that standards of
performance must meet. However, by their terms, they do not require, or
authorize the EPA to require, any significant contribution or
endangerment findings for particular air pollutants as a predicate to
promulgating such standards. Instead, the EPA's promulgation of such
standards is subject to the CAA section 307(d)(9)(A) arbitrary and
capricious standard for judicial review. See American Electric Power
Co. v. Connecticut, 564 U.S. 410, 424, 427 (2011). In contrast,
numerous other provisions explicitly require a pollutant-specific
contribution or endangerment finding. See, e.g., CAA section
183(f)(1)(A), 202(a)(1), 211(c)(1)(A), 213(a)(1)-(3), 231(a)(2). The
inclusion of clear requirements for pollutant-specific findings in
other CAA provisions confirms that the absence of such a requirement in
CAA section 111 indicates Congress' intention not to include such a
requirement there. See United States v. Gonzales, 520 U.S. 1, 5 (1997)
(``Where Congress includes particular language in one section of a
statute but omits it in another section of the same Act, it is
generally presumed that Congress acts intentionally and purposely in
the disparate inclusion or exclusion.'') (internal quotations omitted).
Importantly, the arbitrary and capricious standard is tantamount to
a standard of reasonableness or rationality. See Motor Vehicle Mfrs.
Ass'n of U.S., Inc. v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 42-
43 (1983) (Motor Vehicle Mfrs. Ass'n) (``[t]he scope of review under
the `arbitrary and capricious' standard'' means that a court ``may not
set aside an agency rule that is [, among other things,] rational'').
In the 2016 NSPS OOOOa, the EPA termed this standard the rational basis
test, and applied it to the promulgation of GHG standards of
performance for the oil and gas source category. This standard of
review is well established, and courts routinely review rules under it,
as noted in the House Report at 11.
On the other hand, requiring a pollutant-specific significant
contribution finding as a predicate for promulgating NSPS would disrupt
the scheme Congress set out because it would render the significant
contribution and endangerment findings for the source category
superfluous. This is because a finding that any particular air
pollutant emitted from a source category contributes significantly to
dangerous air pollution necessarily means that the source category
itself contributes significantly to dangerous air pollution. See TRW
Inc. v. Andrews, 534 U.S. 19, 31 (2001) (``It is a cardinal principle
of statutory construction that a statute ought, upon the whole, to be
so construed that, if it can be prevented, no clause, sentence, or word
shall be superfluous. . . .'').
[[Page 16855]]
The EPA's more than half-century long regulatory history of CAA
section 111 is consistent with the rational basis test and provides no
precedent for requiring or authorizing the EPA to require a pollutant-
specific significant contribution finding. The EPA first listed source
categories and promulgated standards of performance for them in 1971,
36 FR 5931 (Mar. 31, 1971) (listing initial source categories); 36 FR
24876 (Dec. 23, 1971) (promulgating initial standards of performance),
and since then, has listed dozens more source categories and
promulgated hundreds of standards. 40 CFR part 60. The EPA has always
listed source categories by determining that they contribute
significantly to dangerous air pollution, and then has proceeded to
promulgate NSPS for particular air pollutants from the source
categories, without making comparable significant contribution or
endangerment findings for those air pollutants.\139\ The EPA has
followed this approach when it has promulgated standards of performance
for particular air pollutants at approximately the same time that it
listed the source category, see, e.g., 36 FR 5931 (Mar. 31, 1971)
(listing five source categories); 36 FR 24876 (Dec. 23, 1971)
(promulgating standards of performance for same five source
categories), and when it has promulgated standards of performance for
particular air pollutants for the first time many years after it listed
the source category, and which it did not address when it listed the
source category. See 38 FR 15380 (June 11, 1973) (listing the petroleum
refineries source category), 39 FR 9310 (Mar. 8, 1974) (promulgating
standards of performance for PM, CO, SO2, and opacity from
the source category), 73 FR 35838 (June 24, 2008) (promulgating
standards of performance for NOX and VOC from the source
category).
---------------------------------------------------------------------------
\139\ The only exceptions have been two rules in which the EPA
made pollutant-specific significant contribution findings in the
alternative. 80 FR 64510, 64531 (Oct. 23, 2015) (GHG NSPS for
electric power plants); 2016 NSPS OOOOa, 81 FR 35843.
---------------------------------------------------------------------------
In other rulemakings, the EPA declined to promulgate NSPS for
certain air pollutants, on the basis of what amounted to a rational
basis test, although the EPA did not use that specific terminology. See
42 FR 22056, 22507 (May 3, 1977) (declining to promulgate NSPS for
NOX, CO, and SO2 from lime manufacturing plants
due to limited amounts of emissions of pollutants or limited reductions
that controls would achieve); National Lime Assoc. v. EPA, 627 F.2d
416, 426 & n.27 (D.C. Cir. 1980). On the other hand, in rulemakings
since 2009, the EPA has rejected comments that it was required to make
a pollutant-specific significant contribution finding. See 74 FR 51950,
51957 (Oct. 8, 2009) (NSPS for coal preparation and processing plant
source category); 80 FR 64510, 64530 (Oct. 23, 2015) (NSPS for GHG from
electric utility generation source category); 2016 NSPS OOOOa, 81 FR
35843.
It is clear that interpreting CAA section 111 to require, or
authorize the EPA to require, a pollutant-specific significant
contribution finding as a predicate for regulation is novel and departs
from the EPA's lengthy history of promulgating standards of
performance.\140\ This ``consistent and longstanding interpretation of
the agency charged with administering the statute'' further supports
interpreting CAA section 111 to base the promulgation of standards of
performance on a rational basis standard, consistent with CAA section
307(d)(9)(A), and not to require a pollutant-specific significant
contribution finding. See Entergy Corp. v. Riverkeeper, Inc., 556 U.S.
208, 235 (2009). Indeed, interpreting CAA section 111 to require, or
authorize the EPA to require, a pollutant-specific significant
contribution finding as a predicate for regulation would undermine the
EPA's implementation of CAA section 111 to date, including, in
particular, virtually all of the standards of performance the EPA has
promulgated to date.
---------------------------------------------------------------------------
\140\ The only actions in which CAA section 111 has been
interpreted to require or authorize the EPA to require a pollutant-
specific significant contribution finding as a predicate for
regulation are the 2020 Policy Rule, which was disapproved by the
CRA joint resolution, and a January 2021 rule that purported to
establish a significance threshold for GHG emissions from source
categories, but that was adopted without notice-and-comment, and was
vacated by the D.C. Circuit in April 2021. See ``Pollutant-Specific
Significant Contribution Finding for Greenhouse Gas Emissions From
New, Modified, and Reconstructed Stationary Sources: Electric
Utility Generating Units, and Process for Determining Significance
of Other New Source Performance Standards Source Categories--Final
Rule,'' 86 FR 2542 (Jan. 13, 2021); California v. EPA, No. 21-1035
(D.C. Cir. April 5, 2021) Doc. #1893155 (order granting motion for
voluntary vacatur and remand).
---------------------------------------------------------------------------
In addition, even if commenters are correct that CAA section 111
requires a pollutant-specific finding, that finding should be simply a
contribution, not a significant contribution. A contribution finding
would be consistent with Congress's approach in other CAA provisions.
See, e.g., CAA section 183(f)(1)(A), 202(a)(1), 211(c)(1), 231(a)(2). A
significant contribution finding is illogical because it would render
the source category significant contribution finding under CAA section
111(b)(1)(A) superfluous, as noted above. By analogy, CAA section
213(a)(4) explicitly requires the EPA make two findings, but
differentiates them: (1) emissions from new nonroad engines or vehicles
contribute significantly to an air pollution problem, and (2) emissions
from classes or categories of new nonroad engines or vehicles cause or
contribute to the air pollution problem. Accordingly, if CAA section
111 were interpreted to require, or at least authorize, the EPA to
require a pollutant-specific finding as a predicate for regulation,
that finding should be that the source category's emissions of the
pollutant cause or contribute to dangerous air pollution.
c. Lack of Redundancy of Regulation of Methane
Commenters also argued that the GHG NSPS in the oil and gas source
category are redundant to the VOC NSPS. Adverse commenters had made
this objection during the 2016 NSPS OOOOa. We rejected it there and
reject it here as well.
In the 2016 rule, the EPA structured the requirements of the VOC
and GHG NSPS to mirror each other, and it is that structure that forms
the basis for commenters' argument that the GHG NSPS should be
considered to be redundant. Because the EPA had listed the oil and gas
source category for regulation, it was required to promulgate NSPS for
GHG emissions under CAA section 111(b)(1)(B) (as long as doing so was
rational), and that requirement is not eliminated by the fact that the
GHG NSPS could be structured to mirror the VOC NSPS. Moreover, the fact
that the 2016 rule structured the requirements as it did does not mean
they are redundant, only that the EPA sought to allow sources to comply
with them as efficiently as possible. Had the EPA not been careful to
structure the two sets of NSPS to mirror each other, no argument would
have arisen that the GHG NSPS were redundant, but that would have been
an inefficient regulatory scheme.
Most importantly, the GHG NSPS are not redundant because only they,
and not the VOC NSPS, trigger the requirement that existing sources are
subject to GHG emission guidelines under CAA section 111(d). The large
contribution of methane emissions from the source category to dangerous
air pollution driving the grave and growing threat of climate change
means that, in the agency's judgment, it would be arbitrary and
capricious under CAA section 307(d)(9)(A)--as well as highly
irresponsible--for the EPA to decline to promulgate NSPS for methane
emissions from the source category. See
[[Page 16856]]
American Electric Power, 564 U.S. at 426-27.
d. Alternative Determination in the 2016 NSPS OOOOa for a Pollutant-
Specific Endangerment Finding
The 2016 NSPS OOOOa re-listing of the source category, described
above, included another alternative determination that provided an
additional basis for the regulation of GHG emissions, which was that
the EPA explicitly determined that GHG emissions from the Crude Oil and
Natural Gas source category cause or contribute significantly to
dangerous air pollution. 81 FR 35833-40. This determination--which, to
be clear, the EPA is not required to do, but nevertheless did so in the
alternative--further addressed commenters' objections that the EPA was
required to make such a pollutant-specific determination as a predicate
for regulating methane emissions. The EPA has not reopened this
determination.
As noted above, this type of determination entails two findings, a
significant contribution finding and a finding of dangerous air
pollution. In this case, those findings were for GHG emissions. We
refer to the former as the pollutant-specific significant contribution
finding. In the 2016 rule, the EPA based the pollutant-specific
significant contribution finding on the same facts concerning the large
amount of methane emissions from the oil and gas source category that
it relied on in making the rational basis determination, as noted
above. Id. 35842-43. It made the finding of dangerous air pollution
based on the endangerment finding for GHG that the EPA made under CAA
section 202(a) in 2009 \141\ (the 2009 Endangerment Finding) and the
2010 denial of petitions to reconsider,\142\ updated with more recent
information. See Coalition for Responsible Regulation v. EPA, 684 F.3d
102, 117-123 (D.C. Cir. 2012) (upholding the 2009 Endangerment Finding
and 2010 denial of petitions to reconsider, and noting, among other
things, the ``substantial . . . body of scientific evidence marshaled
by EPA in support'').
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\141\ ``Endangerment and Cause or Contribute Findings for
Greenhouse Gases Under Section 202(a) of the Clean Air Act,'' 74 FR
66496 (Dec. 15, 2009).
\142\ See ``EPA's Denial of the Petitions To Reconsider the
Endangerment and Cause or Contribute Findings for Greenhouse Gases
Under Section 202(a) of the Clean Air Act,'' 75 FR 49556 (August 13,
2010).
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This pollutant-specific determination for GHG from the oil and gas
source category addresses the commenters' arguments that the EPA cannot
regulate GHG from the source category without making such a finding.
See American Lung Ass'n v. EPA, 985 F.3d 914, 974-77 (D.C. Cir. 2021)
(American Lung Ass'n) (the pollutant-specific significant-contribution
finding that the EPA made in the alternative for GHG emissions from
electric power plants provided a sufficient basis for regulation and
addressed petitioners' arguments that the NSPS for GHG emissions from
those sources was invalid due to lack of such a finding), rev'd in part
sub nom West Virginia v. EPA, 142 S.Ct. 2587 (2022) (West
Virginia).\143\
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\143\ It should be noted that the part of the D.C. Circuit's
opinion in American Lung Ass'n concerning the pollutant-specific
significant contribution finding was not affected by the Supreme
Court's decision in West Virginia.
---------------------------------------------------------------------------
Commenters also argued that an endangerment finding specifically
for methane emissions--that is, a determination that methane emissions
from the oil and gas source category cause or contribute significantly
to atmospheric levels of methane, and that those levels may reasonably
be anticipated to endanger public health or welfare--is necessary as a
predicate for regulation of methane emissions from the source category.
The EPA responded to the same comment in the 2016 NSPS OOOOa. 81 FR
35841-42, 35877. The EPA is not reopening this issue, but for the
purpose of providing information to the public, will explain why,
assuming that a pollutant-specific determination is necessary as a
predicate for CAA section 111 regulation, it is appropriate for the EPA
to make the significant contribution finding on the basis of GHG
emissions and for the EPA to rely on the finding of dangerous air
pollution that it made for GHG, and it is not necessary for the EPA to
make comparable determinations for methane emissions.
The EPA's approach in the 2016 NSPS OOOOa to make the findings for
GHG is fully consistent with other rulemakings in which this issue
arose. The first was the 2009 Endangerment Finding. 74 FR 66496. CAA
section 202(a)(1) requires the EPA to establish ``standards applicable
to the emission of any air pollutant from any class or classes of new
motor vehicles or new motor vehicle engines'' that ``in his judgment
cause, or contribute to, air pollution which may reasonably be
anticipated to endanger public health or welfare.'' The EPA explained
that this provision sets forth a two-part test for regulatory action:
first, whether the relevant air pollution may reasonably be anticipated
to endanger public health or welfare, and second, whether emissions of
any air pollutant from the class or classes of the sources in question
(there, new motor vehicles) cause or contribute to this air pollution.
74 FR 66505, 66516, 66536. The EPA explained that ``the air pollution
can be thought of as the total, cumulative stock in the atmosphere,
while the air pollutant can be thought of as the flow that changes the
size of the total stock.'' 74 FR 66536 (emphasis omitted). The EPA went
on to explain that the ``air pollution'' that it was determining
endangered public health and welfare is the elevated atmospheric
concentrations of ``the combined mix of six key directly-emitted, long-
lived and well-mixed greenhouse gases''--carbon dioxide, methane,
nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur
hexafluorides. Id. 66516-23. The EPA supported this conclusion by
explaining, among other things, that these six gases have the common
attributes regarding their climate effects. Id. 66517. For the same
reasons, in the 2009 Endangerment Finding, the EPA also defined the air
pollutant as GHG--a single air pollutant made up of the same six gases
in an aggregate group for purposes of determining whether the air
pollutant causes or contributes to the endangering air pollution. Id.
66537. The EPA explained that ``they are all greenhouse gases that are
directly emitted . . .; they are sufficiently long-lived in the
atmosphere such that, once emitted, concentrations of each gas become
well mixed throughout the entire global atmosphere; and they exert a
climate warming effect by trapping outgoing, infrared heat that would
otherwise escape to space. Moreover, the radiative forcing effect of
these six greenhouse gases is well understood.'' Id. The EPA further
explained that this definition of the GHG air pollutant was reasonable,
even if emissions from the source category did not include all six
gases. Id. In fact, in the 2009 Endangerment Finding, the EPA noted
that the emissions from the relevant class or classes of new motor
vehicles or new motor vehicle engines included only four of the gases.
Id. 66538, 66541. As noted in section III.A.1 above, the oil and gas
source category emits methane and CO2, although the limits
established in this action focus on regulating GHG through requirements
that are expressed in the form of limits on methane, as a constituent
of the GHG air pollutant.
In subsequent actions that entailed or referenced GHG endangerment
findings, the EPA has taken the same position that the air pollution
consists of the elevated atmospheric concentrations of these six
greenhouse gases and the air pollutant consists of the mix of the same
six gases. 81 FR 54422 (2016 GHG
[[Page 16857]]
endangerment and cause or contribute finding for certain aircraft under
CAA section 231(a)(2)(A)). The EPA took this same position in the 2016
NSPS OOOOa, as mentioned at the beginning of this section. 81 FR 35833,
35877. For the same reasons that the EPA has consistently articulated
in the 2009 Endangerment Finding and afterwards, it is appropriate to
base that determination on the contribution of GHG emitted from the
source category to atmospheric GHG levels. This is because, as noted
above, the 2016 rule identifies the air pollutant as GHG, even though
it expresses the requirements in the form of limits on methane. 40 CFR
60.5360a. Any significant contribution finding must address the
pollutant being regulated, in this case, GHG. In addition, for the
finding of dangerous air pollution, the air pollution of concern is the
elevated concentration of the six well-mixed greenhouse gases, and not
only concentrations of methane.
e. Standards or Criteria for Determining Significance
Commenters argued that when the EPA makes a significant
contribution determination for the pollutant and the source category as
a predicate for regulation, the EPA must first establish a standard or
criteria for when a contribution is significant.\144\ They stated that
such a standard or criteria is necessary to allow the EPA to
distinguish between a contribution and a significant contribution, and
that without it, the significant contribution finding is arbitrary. The
EPA disagrees with this comment. Rather, it is fully appropriate for
the EPA to exercise its discretion to employ a facts-and-circumstances
approach, particularly in light of the wide range of source categories
and the air pollutants they emit that the EPA must regulate under CAA
section 111.
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\144\ Comments of Permian Basin Petroleum Ass'n, Document ID No.
EPA-HQ-OAR-2021-0317-0793 at 3-4 (citing 85 FR 57018, 57038
(September 14, 2020)).
---------------------------------------------------------------------------
With respect to the significant contribution finding for a source
category, CAA section 111(b)(1)(A) by its terms does not require that
such a finding be based on established criteria or a standard or
threshold. In fact, during the 50 years that it has listed dozens of
source categories,\145\ the EPA has never identified a standard or
criteria for determining significance, and instead, has always relied
on the particular facts and circumstances. This approach is appropriate
because Congress intended that CAA section 111 apply to a wide range of
source categories and pollutants, from wood heaters to emergency backup
engines to petroleum refineries. In that context, it is reasonable to
interpret CAA section 111 to allow the EPA the discretion to determine
how best to assess significant contribution and endangerment based on
the individual circumstances of each pollutant and each source
category. For example, among the six well-mixed gases that comprise
GHG, CO2 is emitted in the greatest quantities while methane
emissions have a greater impact than CO2 emissions on a per-
ton basis. In addition, source categories that emit the same air
pollutant may differ from each other in several ways that may be
relevant for purposes of a significance finding, including whether new
sources are expected to be constructed.
---------------------------------------------------------------------------
\145\ List of Categories of Stationary Sources, 36 FR 5931
(March 31, 1971); see 40 CFR part 60.
---------------------------------------------------------------------------
With respect to any significant contribution finding for an air
pollutant--and as noted above, CAA section 111 does not require one as
a predicate for regulation--established criteria or standards are also
not required. The D.C. Circuit adopted this position in American Lung
Ass'n, 985 F.3d at 976-77, when it upheld the EPA's pollutant-specific
significant-contribution finding for GHG emissions from electric power
plants even though the EPA did not ``articulate a specific threshold
measurement for significance.'' The court relied on the same reasoning
that it used when, in upholding the 2009 Endangerment Finding, it
rejected an argument that the EPA must establish criteria in order to
determine that an air pollutant endangers public health and welfare.
Coal. for Responsible Regulation, Inc. v. EPA, 684 F.3d 102 (D.C. Cir.
2012). The court stated that ``EPA need not establish a minimum
threshold of risk or harm before determining whether an air pollutant
endangers'' because ``the inquiry necessarily entails a case-by-case,
sliding-scale approach.'' Id. at 122-23. Although there, the court was
discussing whether an air pollutant endangers public health or welfare,
the court later, in American Lung Ass'n, made clear that the same
principle applies to whether an air pollutant contributes significantly
to dangerous air pollution. On this point, as well, the EPA is in full
agreement with the statements in the House Report stating that the EPA
is not required to base a significance finding on an established
standard or criteria. House Report at 9-10.
Commenters who interpret CAA section 111 to require a pollutant-
specific significant contribution finding rely on the requirement in
CAA section 111(b)(1)(A) for a source-category significant endangerment
finding. By that logic, the facts-and-circumstances method by which the
EPA has always determined the source category significant-contribution
finding should also apply to any pollutant-specific significant
contribution finding. See Alaska Dep't of Envtl. Conservation, 540 U.S.
461, 487 (2004) (explaining, in a case under the CAA, ``[w]e normally
accord particular deference to an agency interpretation of longstanding
duration'' (internal quotation marks omitted) (citing Barnhart v.
Walton, 535 U.S. 212, 220 (2002)). In fact, in each of the first two
rules in which the EPA made a pollutant-specific significant
contribution finding as an alternative basis for regulating GHG from
the relevant source category, the EPA relied on a facts-and-
circumstances test for determining significance. 80 FR 64531 (NSPS for
GHG from electric power plants); 2016 NSPS OOOOa, 81 FR 35843.\146\ The
EPA's long track record for basing CAA section 111 significance
findings on an examination of facts and circumstances, and not relying
on established criteria or other standards or thresholds, coupled with
the importance of allowing the EPA the flexibility to take into account
the particular circumstances of the pollutant and the source category,
makes clear that a lack of such criteria or standards does not render
the significance determinations arbitrary and capricious. The courts
have long reviewed agency actions under the arbitrary-and-capricious
standard without requiring quantitative or numerical standards. See
Motor Vehicle Mfrs. Ass'n, 463 U.S. 42-43 (stating that the court ``may
not set aside an agency rule that is rational, based on consideration
of the relevant factors and within the scope of the authority delegated
to the agency by the statute'').
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\146\ As noted above, a January 2021 rule, promulgated without
notice and comment and vacated by the D.C. Circuit, took the
position that standards or criteria for a pollutant-specific
significant contribution finding are necessary. 86 FR 2542;
California v. EPA, No. 21-1035 (D.C. Cir. April 5, 2021) Doc.
#1893155 (order granting motion for voluntary vacatur and remand).
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Other CAA provisions require the EPA to make a pollutant-specific
determination, and the EPA's actions under these provisions are
informative here as well. The EPA has implemented some of these
provisions through a facts and circumstances test, see 59 FR 31308
(June 17, 1994) (under CAA section 213, in determining whether
emissions from nonroad engines and vehicles contribute significantly to
dangerous air pollution, the EPA made a qualitative assessment, and
rejected assertions by commenters
[[Page 16858]]
that it was required to determine a specific numerical standard for
significance); and has implemented some of these provisions through
both a facts and circumstances test and criteria or standards. See 84
FR 50268 (Sept. 24, 2019) (proposal for 2020 Policy Rule; discusses EPA
action under CAA section 189(e), which requires the EPA to regulate
sources of precursors to PM10 except where EPA determines
such sources do not contribute significantly to PM10 levels
that exceed the NAAQS; EPA has determined significance through a
combination of a facts-and-circumstances test and criteria); compare
id. at 50267-68 (discussing EPA's implementation of CAA section
110(a)(2)(D)(i), the Good Neighbor Provision, which requires states to
prohibit emissions ``in amounts which will contribute significantly to
nonattainment'' of the NAAQS in any other state; in rules concerning
ozone and PM2.5, the EPA has identified a numerical
criterion for determining significant contribution) with 84 FR 54498,
54499 (October 10, 2019) (in rules under the Good Neighbor Provision
concerning the SO2 NAAQS, EPA has applied a weight of
evidence (that is, evaluating all available facts and circumstances)
test for determining whether there is significant contribution). The
fact that the EPA has sometimes relied on a facts-and-circumstances
test for determining significance in these CAA provisions supports its
view that such a test is reasonable under CAA section 111.
If the EPA were required to develop a standard or criteria to
determine significance, any reasonable standard or criteria would
necessarily focus on the amount of emissions from the source category
and the harmfulness of the pollutant emitted. In the case of the oil
and gas source category, the ``massive quantities of methane
emissions'' contributed by the sector to the levels of well-mixed GHG
in the atmosphere, as described in the November 2021 Proposal, 86 FR
63148, coupled with the potency of methane (with a global warming
potential (GWP) of almost 30 or more than 80, depending on the time
period of the impacts, id. 63130), demonstrate that the source
category's GHG emissions would be significant under any reasonable
criteria-based approach. See 86 FR 63131.
In particular, the fact that the oil and gas source category has
the largest amount of methane emissions in the United States, in the
context of a problem such as climate change that is caused by the
collective contribution of many different sources, confirms that those
emissions would meet any reasonable standard or criteria for
significance.\147\ See American Lung Ass'n, 985 F.3d at 977 (``The
global nature of the air pollution problem means that `[a] country or a
source may be a large contributor, in comparison to other countries or
sources, even though its percentage contribution may appear relatively
small' in the context of total emissions worldwide.'' (quoting 2009
Endangerment Findings). In fact, as noted above and discussed at
further length in the December 2022 Supplemental Proposal, 87 FR 74719-
20, the oil and gas source category's position as the largest methane-
emitting source category in the U.S. would itself qualify as a
criterion that supports treating it as a significant contributor of
methane, if such a criterion were necessary.
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\147\ The EPA acknowledges that the collective nature of the
climate change problem means that other source categories of methane
emissions that are not necessarily as large as the oil and gas
source category may also require regulation, cf. EPA v. EME Homer
City, 572 U.S. 489, 514 (2014) (affirming framework to address ``the
collective and interwoven contributions of multiple upwind States''
to ozone nonattainment), as indicated by the fact that the EPA has
long regulated landfill gas, which consists of methane in 50 percent
part. ``Emission Guidelines and Compliance Times for Municipal Solid
Waste Landfills; Final Rule,'' 81 FR 59276, 59281 (August 29, 2016).
But this does not necessarily mean that it would be appropriate to
regulate all other types of sources, even ones with few emissions.
In the past, the EPA has declined to regulate air pollutants emitted
from source categories in quantities too small to be of concern and
when regulation would have produced little environmental benefit for
other reasons. See Nat'l Lime Ass'n. v. EPA, 627 F.2d 416, 426 &
n.27 (D.C. Cir. 1980) (small amounts of emissions of nitrogen oxides
and carbon monoxide from lime kilns was a key factor in EPA decision
not to promulgate new source performance standards for those
pollutants; citing Standards of Performance for New Stationary
Sources Lime Manufacturing Plants--Proposed Rule, 42 FR 22506, 22507
(May 3, 1977)).
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2. Commenters' Arguments Concerning the CRA Joint Resolution and its
Legislative History
Commenters dismiss the significance of the CRA joint resolution
that disapproved the 2020 Policy Rule by arguing that although the
joint resolution had the effect of reinstating the 2016 NSPS OOOOa, it
did not change the underlying requirements of CAA section 111, so that
the flaws the commenters perceived in the 2016 rule's positions
remained. The commenters further argue that the legislative history of
the joint resolution that supported the 2016 rule's positions is
irrelevant. We disagree with these commenters. Under the CRA, the
enactment of the joint resolution not only disapproved the 2020 Policy
Rule and had the effect of reinstating the 2016 rule, it also
prohibited the EPA from promulgating another rule that is
``substantially the same'' as the 2020 Policy Rule. CRA section
801(b)(2). The joint resolution, confirmed by its legislative history,
made clear what rules would and would not be prohibited. The
commenters' arguments, if accepted, would lead to the adoption of a
rule that would be considered substantially the same as the 2020 rule,
and for that reason, their arguments must be rejected. In this section,
we provide background information concerning the CRA and the role of
legislative history, we summarize the discussion in the joint
resolution's legislative history, and then we explain why commenters'
arguments must be rejected.
a. The CRA Joint Resolution of Disapproval
Congress enacted the CRA in 1996 to facilitate Congressional
oversight of agency action by streamlining the process for adopting
legislation to disapprove agency rules.\148\ The CRA provides the
specific wording for a joint resolution of disapproval for an agency
action, which is a sentence that states (including the standard
prefatory phrase for a joint resolution): ``Resolved by the Senate and
House of Representatives of the United States of America in Congress
assembled, That Congress disapproves the rule submitted by the __
relating to __, and such rule shall have no force or effect.'' 5 U.S.C.
802(a). The blank spaces are for the name of the agency and the rule.
The CRA further provides that after Congress adopts a joint resolution
of disapproval of an agency rule, the agency is precluded from
promulgating a new rule that is ``substantially the same'' as the
disapproved rule, absent a new act of Congress authorizing such a rule.
CRA section 801(b)(2).
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\148\ Congressional Research Service, ``The Congressional Review
Act (CRA): Frequently Asked Questions (Jan. 14, 2020) at 1-2.
---------------------------------------------------------------------------
Notwithstanding this constraint, the affected agency may still have
the discretion to, and in fact may still be required to, promulgate
further rulemaking in accordance with the underlying statute that
authorized the disapproved rule. The legislative history of the joint
resolution may clarify the parts of the disapproved rule that Congress
objected to, and thereby clarify what subsequent rules would or would
not be substantially the same as the disapproved rule. The potential
importance of legislative history that accompanies a joint resolution
and that explains Congress's objections to the rule, is highlighted by
the fact that the legislative language of the joint resolution is, by
the terms of the CRA,
[[Page 16859]]
simply a one-sentence disapproval of the agency action, as noted above.
b. CRA Joint Resolution of Disapproval of the 2020 Policy Rule
The joint resolution of disapproval of the 2020 Policy Rule
provided, consistent with the form mandated under the CRA, ``Resolved
by the Senate and House of Representatives of the United States of
America in Congress assembled, That Congress disapproves the rule
submitted by the Administrator of the Environmental Protection Agency
relating to ``Oil and Natural Gas Sector: Emission Standards for New,
Reconstructed, and Modified Sources Review'' (85 FR 57018 (September
14, 2020)), and such rule shall have no force or effect.'' \149\ In
adopting it, Congress explained its understanding of CAA section 111
and, based on that, its reasons why the 2020 Policy Rule was
inconsistent with CAA section 111 and must be disapproved.
Specifically, as discussed in the November 2021 Proposal and summarized
above, the Senate floor debate over the joint resolution and the House
Report made clear Congress's views concerning the relevant provisions
of CAA section 111 and the statutory interpretations contained in the
2016 NSPS OOOOa and the 2020 Policy Rule, and its intention that the
EPA take further rulemaking action consistent with those views. Thus,
the legislative history made clear that Congress (i) intended the EPA
to treat the transmission and storage segment as part of the Crude Oil
and Natural Gas Production source category and to promulgate NSPS and
emission guidelines for GHG from the source category, (ii) viewed the
2016 rule's statutory interpretations of CAA section 111 to be correct
and to serve as the basis for these regulatory actions, and (iii)
viewed the contrary statutory interpretations contained in the 2020
rule to be incorrect. The statutory interpretations that Congress
viewed to be correct include that the EPA is not authorized to
promulgate a pollutant-specific significant contribution finding as a
predicate for regulation, and that a facts and circumstances test for
determining significant contribution for the source category listing is
appropriate.
---------------------------------------------------------------------------
\149\ S.J. Res.14--117th Congress, Public Law 117-23.
---------------------------------------------------------------------------
c. Commenters' Arguments and the EPA's Responses
Commenters assert that while the CRA joint resolution disapproved
the 2020 Policy Rule, that action did not extend to the legal rationale
and policy positions in the 2020 rule, and did not endorse the legal
rationale and policy positions in the 2016 rule. They also assert that
only the text of the joint resolution--again, a single sentence, quoted
above, stating that Congress disapproves the 2020 rule and it shall
have no force or effect--is relevant, and that the legislative history
is not relevant. The commenters then assert that the joint resolution
did not change the requirements of CAA section 111. From there, they
assert that CAA section 111 requires the interpretations and
determinations that the 2020 Policy Rule made, including that in order
for the EPA to promulgate NSPS for sources in the transmission and
storage segment, the EPA must first list that segment as a separate
source category, including making significant contribution and
endangerment findings for it; and in order for the EPA to promulgate
NSPS for GHG emissions from oil and gas sources, the EPA must first
make a pollutant-specific significant contribution finding, including
specifying a standard or criterion for significance.
The EPA rejects the commenters' arguments. In essence, commenters
seek to minimize the importance of the joint resolution in order to
argue that the EPA must rescind most of the 2016 NSPS OOOOa on grounds
that it is inconsistent with CAA section 111's requirements, as the
commenters see them. However, such a rescission rule would be
substantially the same as the 2020 Policy Rule, and is therefore
precluded by the joint resolution.
The central features of the disapproved 2020 Policy Rule were its
position that the transmission and storage segment is separate from the
production and processing segments; its position that a GHG-specific
significant contribution finding, supported by standards or criteria
for determining significance, was a necessary predicate for regulating
GHG emissions; and the statutory interpretations that underlay those
positions. In addition, the legislative history of the CRA resolution
made clear that Congress disapproved the 2020 Policy Rule because it
rejected those positions and the underlying legal interpretations.
Thus, a rule that adopted the same positions and interpretations as the
2020 Policy Rule would be precluded by the joint resolution as
substantially the same as the 2020 Policy Rule.
Looked at another way, the commenters' in essence argue that the
EPA should withdraw the November 2021 Proposal and the December 2022
Supplemental Proposal and instead propose and promulgate a rule stating
that the EPA is not authorized to further regulate oil and gas sources,
including promulgating emission guidelines, unless it lists the
transmission and storage segment as a separate source category and
makes a pollutant-specific significant contribution finding for
GHGs,\150\ based on standards or criteria for determining significance.
However, such a rule would also be precluded by the joint resolution as
substantially the same as the key aspects of the 2020 Policy Rule
because it would be based on the same statutory interpretations as that
rule. Indeed, it is difficult to see what effect the disapproval would
have if not to preclude the EPA from re-instating the positions and
underlying legal interpretations included in the 2020 Policy Rule.
---------------------------------------------------------------------------
\150\ As noted above, commenters' argument that the EPA must
make a pollutant-specific significant contribution finding for GHG
emissions from the source category has been addressed because the
2016 NSPS OOOOA made such a finding in the alternative.
---------------------------------------------------------------------------
These commenters also err in asserting that the legislative history
is irrelevant. Agencies and courts regularly look to legislative
history to inform their actions and decisions. This makes particular
sense in the case of a CRA joint resolution given the very limited
language Congress may use in the joint resolution itself. Commenters
also argue that the EPA's position that the joint resolution of
disapproval applies to the legal and policy positions in the 2020
Policy Rule would call into question the interpretations of CAA section
111 that the rule included that are noncontroversial and necessary to
proper implementation of the provision. There is no reason to think
that Congress would have objected to those interpretations, but in any
event, this argument by commenters makes clear that the joint
resolution's legislative history is useful because it clarifies which
interpretations and positions in the rule that Congress did object to.
After reviewing the text of the disapproval and, separately, the
disapproval resolution's legislative history, the EPA is proceeding
with further rulemaking under CAA section 111 for sources in the Crude
Oil and Natural Gas source category. With the 2016 Rule reinstated by
the operation of the CRA resolution, the EPA is revising and adding
certain NSPS and is promulgating emission guidelines for existing
sources. These actions apply to sources in the transmission and storage
segment, and apply to methane emissions. This rule is fully consistent
with the CRA joint resolution.
[[Page 16860]]
VI. Other Actions and Related Efforts
This section of this preamble describes related state actions and
other Federal actions regulating oil and natural gas emissions sources;
industry and voluntary efforts to reduce methane emissions from this
sector; and other EPA programs to reduce methane emissions, including
the Methane Emissions Reduction Program that was signed into law as
part of the Inflation Reduction of 2022. The final NSPS OOOOb and EG
OOOOc include specific measures that build on the experience and
knowledge the Agency and industry have gained through voluntary
programs and previous regulatory efforts, as well as the leadership of
the states in developing their own regulatory programs. The final NSPS
OOOOb and EG OOOOc consists of reasonable, proven, cost-effective
technologies and practices that reflect the evolutionary nature of the
oil and natural gas industry and these proactive regulatory and
voluntary efforts.
At the same time, the final NSPS OOOOb and EG OOOOc reflect the
EPA's unique authority and responsibility under the CAA to ensure that
new and existing sources throughout the nation are subject to
appropriate standards of performance through NSPS and approved state
plans. By requiring all owners and operators of the sources regulated
in this final rulemaking to limit methane emissions, the EPA intends to
achieve methane emission reductions on a more consistent and
comprehensive basis than has been achieved through current programs and
efforts. Direct Federal regulation of methane and VOCs from new
sources, combined with approved state plans that are consistent with
the EPA's EG for methane from existing sources, will bring national
consistency to the regulatory landscape, help promote technological
innovation, and reduce both climate- and other health-harming pollution
from a large number of sources that are either currently unregulated or
where additional cost-effective reductions are available.
A. Related State Actions and Other Federal Actions Regulating Oil and
Natural Gas Sources
The EPA recognizes that several states currently regulate emissions
from the oil and natural gas industry.\151\ The EPA also recognizes
that some of these state programs have been expanded and strengthened
since the EPA began implementing its 2012 NSPS and subsequent 2016
NSPS. These state-level efforts have been important in spurring the
deployment of emission control technologies and practices, and
developing a broad base of experience that has informed the final rule.
At the same time, the EPA recognizes that state-level regulatory
efforts cannot, alone, address the increasingly dangerous impacts of
methane emissions on public health and welfare. State agencies regulate
in accordance with their own authorities and within their own
respective jurisdictions; as a result, there is considerable variation
in the scope and stringency of such programs. Collectively, these
programs do not fully address the range of sources and emission
reduction measures contained in this rulemaking. The EPA is committed
to working within its authority to provide opportunities to align its
programs with these existing state programs in order to reduce
regulatory redundancy where appropriate.
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\151\ The EPA summarized examples of state programs in the
November 2021 Proposal and November 2021 TSD. See 86 FR 63137 and
Document ID No. EPA-HQ-OAR-2021-0317-0166.
---------------------------------------------------------------------------
In addition to states, certain Federal agencies also regulate
aspects of the oil and natural gas industry pursuant to their own
authorities. The EPA has maintained an ongoing dialogue with its
Federal partners during the development of this final rulemaking in
order to avoid potential regulatory conflicts and unnecessary
regulatory obligations on the part of owners and operators as each
agency responds to its particular statutory charge.
The below description summarizes other Federal regulations and
programs related to air emissions from the oil and natural gas
industry. The U.S. Department of the Interior (DOI) regulates the
extraction of oil and gas from Federal and Indian lands. DOI bureaus
that are responsible for administering natural resources conservation
and safety related to onshore and offshore energy development include
the Bureau of Land Management (BLM) (Federal onshore fossil fuel
related activities), the Bureau of Safety and Environmental Enforcement
(Federal offshore safety and environmental protection of oil and gas
development), and the Bureau of Ocean Energy Management (BOEM) (Federal
offshore oil and gas related activities). The BLM manages the Federal
Government's onshore subsurface mineral estate--about 700 million acres
(30 percent of the U.S.)--for the benefit of the American public. The
BLM maintains the Federal onshore oil and gas leasing program pursuant
to the Mineral Leasing Act, the Mineral Leasing Act for Acquired Lands,
the Federal Land Management and Policy Act, and the Federal Oil and Gas
Royalty Management Act. The BLM's oil and gas operating regulations are
found in 43 CFR part 3160. An oil and gas operator's general
environmental and safety obligations for onshore activities are found
at 43 CFR 3162.5. Pursuant to a delegation of Secretarial authority,
the BLM also oversees oil and gas operations on many Indian/Tribal
leases.
The BLM has the express authority and responsibility to regulate
both for the prevention of waste and the protection of the environment
for operations on Federal and Indian lands. This responsibility
includes promulgating regulations to reduce the waste of natural gas
from oil and gas leases administered by the BLM. This gas is lost
during oil and gas exploration and production activities through
venting, flaring, and leaks. More detailed information can be found at
the BLM's website: https://www.blm.gov/programs/energy-and-minerals/oil-and-gas/operations-and-production/methane-and-waste-prevention-rule.
BOEM manages the development of U.S. Outer Continental Shelf
(offshore) energy and mineral resources. BOEM has air quality
jurisdiction in the Gulf of Mexico \152\ and the North Slope Borough of
Alaska.\153\ BOEM also has air jurisdiction in Federal waters on the
Outer Continental Shelf 3-9 miles offshore (depending on the state) and
beyond. The Outer Continental Shelf Lands Act (OCSLA), section 5(a)(8)
states, ``The Secretary of the Interior is authorized to prescribe
regulations `for compliance with the national ambient air quality
standards pursuant to the CAA . . . to the extent that activities
authorized under [the Outer Continental Shelf Lands Act] significantly
affect the air quality of any state.' '' The EPA and states have the
air jurisdiction onshore and in state waters, and the EPA has air
jurisdiction offshore in certain areas. More detailed information can
be found at BOEM's website: https://www.boem.gov/.
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\152\ The CAA gave BOEM air jurisdiction west of 87.5 degrees
longitude in the Gulf of Mexico region.
\153\ The Consolidated Appropriations Act of 2012 gave BOEM air
jurisdiction in the North Slope Borough of Alaska.
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The U.S. Department of Transportation (DOT) manages the U.S.
transportation system. Within DOT, the Pipeline and Hazardous Materials
Safety Administration (PHMSA) is responsible for regulating and
ensuring the safe and secure transport of energy and other hazardous
materials to industry and consumers by all modes of transportation,
including pipelines.
[[Page 16861]]
While PHMSA regulatory requirements for gas pipeline facilities have
focused on human safety, which has attendant environmental co-benefits,
the ``Protecting our Infrastructure of Pipelines and Enhancing Safety
Act of 2020'' (Pub. L. 116-260, Division R; ``PIPES Act of 2020''),
which was signed into law on December 27, 2020, revised PHMSA organic
statutes to emphasize the centrality of environmental safety and
protection of the environment in PHMSA decision making. For example,
the PHMSA's Office of Pipeline Safety ensures safety in the design,
construction, operation, maintenance, and incident response of the
U.S.' approximately 3.3 million miles of natural gas and hazardous
liquid transportation pipelines. When pipelines are maintained, the
likelihood of environmental releases like leaks are reduced.\154\ In
addition, the PIPES Act of 2020 contains several provisions that
specifically address the minimization of releases of natural gas from
pipeline facilities, such as a mandate that the Secretary of
Transportation promulgate regulations related to gas pipeline LDAR
programs. More detailed information can be found at PHMSA's website:
https://www.phmsa.dot.gov/.
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\154\ See Final Report on Leak Detection Study to PHMSA.
December 10, 2012. https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/docs/technical-resources/pipeline/16691/leak-detection-study.pdf.
---------------------------------------------------------------------------
The U.S. Department of Energy (DOE) develops oil and natural gas
policies and funds research on advanced fuels and monitoring and
measurement technologies. Specifically, the Advanced Research Projects
Agency-Energy (ARPA-E) program advances high-potential, high-impact
energy technologies that are too early for private-sector investment.
APRA-E awardees are unique because they are developing entirely new
technologies. More detailed information can be found at ARPA-E's
website: https://arpa-e.energy.gov/. Also, the U.S. Energy Information
Administration (EIA) compiles data on energy consumption, prices,
including natural gas, and coal. More detailed information can be found
at the EIA's website: https://www.eia.gov/.
The U.S. Federal Energy Regulatory Commission (FERC) is an
independent agency that regulates the interstate transmission of
electricity, natural gas,\155\ and oil.\156\ FERC also reviews
proposals to build liquefied natural gas terminals and interstate
natural gas pipelines, and licenses hydropower projects. FERC's
responsibilities for the crude oil industry include the following:
regulation of rates and practices of oil pipeline companies engaged in
interstate transportation; establishment of equal service conditions to
provide shippers with equal access to pipeline transportation; and
establishment of reasonable rates for transporting petroleum and
petroleum products by pipeline. FERC's responsibilities for the natural
gas industry include the following: regulation of pipeline, storage,
and liquefied natural gas facility construction; regulation of natural
gas transportation in interstate commerce; issuance of certificates of
public convenience and necessity to prospective companies providing
energy services or constructing and operating interstate pipelines and
storage facilities; regulation of facility abandonment, establishment
of rates for services; regulation of the transportation of natural gas
as authorized by the Natural Gas Policy Act and OCSLA; and oversight of
the construction and operation of pipeline facilities at U.S. points of
entry for the import or export of natural gas. FERC has no jurisdiction
over construction or maintenance of production wells, oil pipelines,
refineries, or storage facilities. More detailed information can be
found at FERC's website: https://www.ferc.gov/.
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\155\ https://www.ferc.gov/industries-data/natural-gas.
\156\ https://www.ferc.gov/industries-data/oil.
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B. Industry and Voluntary Actions To Address Climate Change
Separate from regulatory requirements, some owners or operators of
facilities in the oil and natural gas industry choose to participate in
voluntary initiatives to reduce methane emissions from their
operations. Over 100 oil and natural gas companies have participated in
the EPA Natural Gas STAR Program and Methane Challenge partnership over
the past several decades. Owners or operators also participate in a
growing number of voluntary programs unaffiliated with the EPA
voluntary programs; the EPA is aware of at least 19 such
initiatives.\157\ Firms participate in voluntary environmental programs
for a variety of reasons, including attracting customers, employees,
and investors who value more environmentally-responsible goods and
services; finding approaches to improve efficiency and reduce costs;
and preparing for or helping inform future
regulations.158 159
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\157\ Highwood Emissions Management (2021). ``Voluntary
Emissions Reduction Initiatives for Responsibly Sourced Oil and
Gas.'' Available for download at: https://highwoodemissions.com/research/.
\158\ Borck, J.C. and C. Coglianese (2009). ``Voluntary
Environmental Programs: Assessing Their Effectiveness.'' Annual
Review of Environment and Resources 34(1): 305-324.
\159\ Brouhle, K., C. Griffiths, and A. Wolverton. (2009).
``Evaluating the role of EPA policy levers: An examination of a
voluntary program and regulatory threat in the metal-finishing
industry.'' Journal of Environmental Economics and Management.
57(2): 166-181.
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The EPA's Natural Gas STAR Program started in 1993 with the
objective of achieving methane emission reductions through
implementation of cost-effective best practices and technologies.
Through the program, partner companies documented their voluntary
emission reduction activities and reported their accomplishments to the
EPA annually. Over the course of the Natural Gas STAR Partnership from
1993 to 2022, the EPA collaborated with over 100 companies across the
natural gas value chain. Through the partnership, the EPA tracked more
than 150 different methane-reducing activities and technologies which
it then shared among partners and through the program website. Between
1993 and 2020, partner companies reported cumulative methane emissions
reductions of nearly 1.7 trillion cubic feet.
The EPA's Methane Challenge Program was launched in 2016 to expand
upon the Natural Gas STAR Program by providing partner companies the
opportunity to make ambitious, quantifiable emissions reduction
commitments, provide detailed, transparent reporting, and receive
partner recognition. Annually, Methane Challenge Partners submit
facility-level reports that characterize methane emission sources at
their facilities and detail voluntary actions taken to reduce methane
emissions. The EPA emphasizes the importance of transparency by
publishing these facility-level data. Since its inception, the Methane
Challenge Program has included nearly 70 companies and currently has 54
active partners, primarily from the transmission and distribution
segments.
Other voluntary programs for the oil and natural gas industry are
administered by numerous organizations, including trade associations
and non-profits. These voluntary efforts have helped reduce methane
emissions beyond what is required by current regulations, as well as to
significantly expand the understanding of methane mitigation measures
within the industry and among Federal and state regulators. Although
the EPA recognizes and commends the value of these programs, such
voluntary efforts are not legally
[[Page 16862]]
binding and do not alter the EPA's own statutory responsibility to
regulate methane emissions from this sector under the CAA. Moreover, as
the information and analysis reflected in this final rulemaking make
clear, there is still considerable need and opportunity to further
reduce methane emissions from the industry.
C. Methane Emissions Reduction Program
In August 2022, Congress passed, and President Biden signed, the
Inflation Reduction Act of 2022 into law. Section 60113 of the
Inflation Reduction Act of 2022 amended the CAA by adding section 136,
``Methane Emissions and Waste Reduction Incentive Program for Petroleum
and Natural Gas Systems'' (also referred to as the ``Methane Emissions
Reduction Program'').
Subsections (a) and (b) of CAA section 136 provide $1.55 billion
for the Methane Emissions Reduction Program, including for incentives
for methane mitigation and monitoring. The EPA is partnering with the
DOE and National Energy Technology Laboratory to provide financial
assistance for monitoring and reducing methane emissions from the oil
and gas sector, as well as technical assistance to help implement
solutions for monitoring and reducing methane emissions. As designed by
Congress, these incentives were intended to complement the regulatory
programs and to help facilitate the transition to a more efficient
petroleum and natural gas industry.
On August 1, 2023, the EPA proposed revisions to GHGRP subpart W
consistent with the authority and directives set forth in CAA section
136(h), as well as the EPA's authority under CAA section 114 (88 FR
50282). In that rulemaking, the EPA proposed revisions to require
reporting of additional emissions or emissions sources to address
potential gaps in the total methane emissions reported by facilities to
GHGRP subpart W. For example, these proposed revisions would add a new
emissions source, referred to as ``other large release events,'' to
capture large emissions events that are not accurately accounted for
using existing methods in GHGRP subpart W. The EPA also proposed
revisions to add or revise existing calculation methodologies to
improve the accuracy of reported emissions, incorporate additional
empirical data, and allow owners and operators of applicable facilities
to submit empirical emissions data that could appropriately demonstrate
the extent to which a charge is owed in implementation of CAA section
136, as directed by CAA section 136(h). The EPA also proposed revisions
to existing reporting requirements to collect data that would improve
verification of reported data, ensure accurate reporting of emissions,
and improve the transparency of reported data. Additionally, the EPA
proposed revisions that would align GHGRP subpart W with other EPA
programs and regulations, including proposing revisions to certain
requirements in GHGRP subpart W relative to the requirements proposed
for NSPS OOOOb and the presumptive standards proposed in EG OOOOc (such
that, as applicable, facilities would use a consistent method to
demonstrate compliance with multiple EPA programs once their emission
sources are required to comply with either the final NSPS OOOOb or an
approved state plan or applicable Federal plan in 40 CFR part 62).
CAA section 136(c) directs the Administrator of the EPA to ``impose
and collect a charge on methane emissions that exceed an applicable
waste emissions threshold under subsection (f) from an owner or
operator of an applicable facility that reports more than 25,000 metric
tons of carbon dioxide equivalent (CO2 Eq.) of GHG emitted
per year pursuant to subpart W of part 98 of title 40 (40 CFR part 98),
regardless of the reporting threshold under that subpart''
(hereinafter, waste emissions charge). An ``applicable facility'' is
defined under CAA section 136(d) to include nine specific industry
segments as defined in GHGRP subpart W. Pursuant to CAA section 136(g),
the waste emissions charge ``shall be imposed and collected beginning
with respect to emissions reported for calendar year 2024 and for each
year thereafter.''
CAA section 136(f) includes specific exemption from the waste
emissions charge for certain applicable facilities that meet certain
criteria, including what the EPA refers to as a ``regulatory compliance
exemption.'' Specifically, CAA section 136(f)(6)(A) states that
``charges shall not be imposed pursuant to subsection (c) on an
applicable facility that is subject to and in compliance with methane
emissions requirements pursuant to subsections (b) and (d) of section
111 upon a determination by the Administrator that: (i) Methane
emissions standards and plans pursuant to subsections (b) and (d) of
section 111 have been approved and are in effect in all states with
respect to the applicable facilities; and (ii) compliance with the
requirements described in clause (i) will result in equivalent or
greater emissions reductions as would be achieved by the proposed rule
of the Administrator entitled `Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review' (86 FR
63110; (November 15, 2021), if such rule had been finalized and
implemented.'' Per CAA section 136(f)(6)(B), ``if the conditions in
clause (i) or (ii) of subparagraph (A) cease to apply after the
Administrator has made the determination in that subparagraph, the
applicable facility will again be subject to the charge under
subsection (c) beginning in the first calendar year in which the
conditions in either clause (i) or (ii) of that subparagraph are no
longer met.''
In the preamble to the December 2022 Supplemental Proposal, the EPA
noted that implementation of CAA section 136 was outside the scope of
the present rulemaking, and that the EPA intended to take one or more
separate actions in the future to implement CAA section 136. However,
the EPA requested comment on the criteria and approaches that the
Administrator should consider in making the CAA section
136(f)(6)(A)(ii) ``equivalency determination'' in such separate future
action. Consistent with our statements in the December 2022
Supplemental Proposal, the EPA is not taking any final actions to
implement CAA section 136 in this action and these comments are
therefore outside the scope of this final rule.
VII. Summary of Engagement With Pertinent Stakeholders
As part of the regulatory development process for this rulemaking,
the EPA conducted extensive outreach with the public, states, Tribal
nations, and a broad range of pertinent stakeholders in order to gather
information from a variety of viewpoints. This engagement allowed the
EPA to provide stakeholders with overviews of the November 2021
Proposal and the December 2022 Supplemental Proposal, and to explain to
the public and pertinent stakeholders how to effectively engage in the
regulatory process. Such outreach is consistent with several E.O.s that
encourage the Federal government to have a robust public participation
process in regulatory development, particularly for communities with EJ
concerns. The EPA specifically identified a long list of stakeholders
with which to engage throughout the rulemaking process--including, but
not limited to, industry, small businesses, Tribal nations, and
[[Page 16863]]
communities most affected by, and vulnerable to, the impacts of the
rule.\160\
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\160\ For a list of the EPA's engagement with pertinent
stakeholders, please see Memorandum in EPA-HQ-OAR-2021-0317.
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Prior to the November 2021 Proposal, the EPA opened a public docket
for pre-proposal input.\161\ Throughout the rulemaking, the EPA engaged
with pertinent stakeholders likely to be interested in this rulemaking
in several ways, including through meetings, training webinars, round
tables, public listening sessions, and a technical workshop. For
example, the EPA hosted a two-part webinar training specifically
targeted toward both communities with EJ concerns and Tribal nations on
November 16 and 17, 2021. The purpose of this training event was for
the EPA to facilitate stakeholder panel discussions and to provide
background information and an overview of the November 2021 Proposal,
as well as information on how to effectively engage in the regulatory
process. Subsequently, on November 14, 2022, the EPA hosted a call for
environmental groups and EJ communities; on November 17, 2022, the EPA
held a webinar for both members of Tribal nations and communities; and
on November 30, 2022, the EPA held a training for Tribal Environmental
Professionals. In a second example, the EPA held a training for small
businesses on May 25, 2021, November 18, 2021, and November 30, 2022,
that provided an overview of how the oil and natural gas industry is
regulated and offered information on how to participate in the
rulemaking process. In a third example, the EPA held calls with the
Association of Air Pollution Control Agencies and the National
Association of Clean Air Agencies on December 6, 2022, and December 14,
2022. In addition, on November 14, 2022, the EPA held a meeting with
industry and labor groups to provide an overview of the proposed
supplemental changes to the rulemaking. Throughout the rulemaking
process the EPA has met individually with hundreds of industry
representatives, NGOs, technology vendors, academics, data companies,
and others.\162\ The EPA held 3-day virtual public hearings for all
stakeholders on both the November 2021 Proposal and the December 2022
Supplemental Proposal.
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\161\ EPA Document ID No. EPA-HQ-OAR-2021-0317-0295.
\162\ See various stakeholder meeting memoranda reflected in
EPA's Docket ID No. EPA-HQ-OAR-2021-0317.
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The EPA notes that the implementing regulations (40 CFR part 60,
subpart Ba) require states to include a description of how they have
engaged with pertinent stakeholders in the development of their state
plans implementing the EG in their state plan submission to the EPA (to
implement EG OOOOc). The EPA has led by example and demonstrated
various examples of engagement with pertinent stakeholders so that
states--while not limited by the EPA's outreach examples--will have a
model for how they can structure their own outreach. For additional
discussion on meaningful engagement as related to the development of
state plans implementing the EG, please see section XIII.C.6 of this
preamble.\163\
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\163\ To better inform this final rulemaking, the EPA analyzed
the characteristics of communities with EJ concerns. Please see the
discussion in section XVI.F of this preamble and the RIA for
additional information.
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VIII. Overview of Control and Control Costs
A. Control of Methane and VOC Emissions in the Crude Oil and Natural
Gas Source Category--Overview
As described in the November 2021 Proposal and the December 2022
Supplemental Proposal, the EPA reviewed the standards in the 2012 NSPS
OOOO and 2016 NSPS OOOOa pursuant to CAA section 111(b)(1)(B). Based on
this review, the EPA is finalizing revisions to the standards for a
number of affected facilities to reflect the updated BSER for those
affected facilities. Where our analyses show that the BSER for an
affected facility remains the same, the EPA is finalizing to retain the
current standard for that affected facility. In addition to the review
of the existing standards, the EPA is finalizing new standards for GHGs
(in the form of limitation on methane) and VOCs for some sources that
were previously unregulated under NSPS OOOO and NSPS OOOOa. The NSPS
OOOOb would apply to new, modified, and reconstructed emission sources
across the Crude Oil and Natural Gas source category for which
construction, reconstruction, or modification is commenced after
December 6, 2022.
Further, pursuant to CAA section 111(d), the EPA is finalizing EG,
which include presumptive standards for GHGs (in the form of
limitations on methane) (designated pollutant), for certain existing
emission sources across the Crude Oil and Natural Gas source category
in EG OOOOc. While the requirements in NSPS OOOOb would apply directly
to new sources, the requirements in EG OOOOc are for states to use in
the development of plans that establish standards of performance that
will apply to existing sources (designated facilities).
B. How does the EPA evaluate control costs in this final action?
Section 111 of the CAA requires the EPA to consider a number of
factors, including cost, in determining ``the best system of emission
reduction . . . adequately demonstrated.'' CAA section 111(a)(1). The
D.C. Circuit has long recognized that ``[CAA] section 111 does not set
forth the weight that [ ] should [be] assigned to each of these
factors;'' therefore, ``[the court has] granted the agency a great
degree of discretion in balancing them.'' Lignite Energy Council v.
EPA, 198 F.3d 930, 933 (D.C. Cir. 1999). The courts have recognized
that the EPA has ``considerable discretion under [CAA] section 111,''
id., on how it considers cost under CAA section 111(a)(1). As the
Supreme Court has more recently noted, ``[i]t will be up to the Agency
to decide (as always, within the limits of reasonable interpretation)
how to account for cost.'' Michigan v. EPA, 576 U.S. 743, 759 (2015). A
more detailed description of relevant case law guiding the EPA's
consideration of costs is set forth in section IV.A of this document
and in the November 2021 Proposal. See 86 FR at 63133, 63154 (November
15, 2021). For the purposes of this final rule, we use the term
``reasonable'' to describe costs which, based on our evaluation, are
considered to be well within the boundaries of our discretion granted
by Congress and recognized by the courts.
As explained in further detail below, the EPA has determined that
the costs of controls associated with the BSER for the final NSPS OOOOb
and EG OOOOc are reasonable. In reaching this determination, the EPA
conducted numerous cost analyses, described in detail in section XII of
the November 2021 Proposal, Section IV of the December 2022
Supplemental Proposal, and section XI of this preamble--all of which
discuss the BSER determinations for each of the regulated emissions
sources--and in the final rule TSD in the docket for this rulemaking.
In evaluating whether the cost of a control is reasonable, the EPA
considers various associated costs, including capital costs and
operating costs, when evaluating the BSER for each emission source. In
addition, as discussed further below, the Agency considered the costs
of the collective standards for the final NSPS OOOOb and EG OOOOc in
the context of the industry's overall capital expenditures and
revenues. As discussed in more detail below, the capital expenditures
in pollution control estimated to result from this
[[Page 16864]]
rulemaking represent 2-3 percent of the industry's annual capital
expenditures. The estimated total annual expenditures represent less
than one percent of the industry's annual revenue. Neither estimate
includes increased industry revenue from the sales of captured gas
resulting from pollution controls, which offsets some of these costs.
At the same time, this rulemaking is estimated to reduce 58 million
short tons of methane from 2024 to 2038--representing a 79 percent
reduction in projected emissions from the sources covered in this
rulemaking.\164\
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\164\ The percent reduction is calculated as the ratio of the
sum of estimated emissions reductions for the NSPS from 2024-2038
and for the EG from 2028-2038 to the sum of estimated baseline
emissions for the NSPS from 2024-2038 and for the EG from 2028-2038.
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As discussed in more detail in the November 2021 Proposal, see 86
FR 63154-7 (November 15, 2021), the EPA also considers a cost
effectiveness analysis to be a useful metric, as it provides a means of
evaluating whether a given control achieves emissions reduction at a
reasonable cost and allows comparisons of relative costs and outcomes
(effects) of two or more options. Cost effectiveness also provides a
means of assessing consistency across rules regulating, and sectors
regulated for, the same pollutant. In the context of an air pollution
control option, cost effectiveness typically refers to the annualized
cost of implementing an air pollution control measure divided by the
amount of pollutant reductions realized annually. Notably, a cost
effectiveness analysis is not intended to constitute or approximate a
benefit-cost analysis in which monetized benefits are compared to
costs, but rather is intended to provide a metric to compare the
relative cost of emissions reductions. As explained in further detail
in the November 2021 Proposal and the December 2022 Supplemental
Proposal, the EPA estimated the cost effectiveness values of the
various control options assessed for this rulemaking using the best
information available to the Agency. The sources upon which the EPA
relied in assessing cost effectiveness are described in detail in the
TSDs and include studies by academia, non-governmental organizations,
and state and Federal agencies. The EPA also relied upon costs and
emissions data, as well as information related to technical
limitations, submitted by members of the affected industry, including
oil and gas production companies, and control device vendors and
numerous other stakeholders,\165\ in the form of public comments in
this rulemaking and previous rulemakings. The EPA also relied upon
financial information provided by industry organizations that represent
small businesses, such as the Michigan Oil & Gas Association
(MOGA).\166\
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\165\ For a more detailed summary of engagement and pertinent
stakeholders that the EPA has engaged with, please see section VII
of this preamble.
\166\ See section XVII.C. of this preamble for summary of the
EPA's final regulatory flexibility analysis (FRFA) for this action.
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The EPA used two approaches to determine cost effectiveness in this
rulemaking. The first approach--the ``single-pollutant cost
effectiveness approach''--assigns all costs to the emission reduction
of one pollutant and zero costs to all other concurrent reductions;
where the cost of the control is reasonable for reducing any of the
targeted pollutants alone, the cost is reasonable for all concurrent
emissions reductions (because these additional pollutants are reduced
at no additional cost). The second approach--the ``multipollutant cost
effectiveness approach''--apportions annualized cost of all pollutant
reductions achieved by the control option in proportion to the relative
percentage reduction of each pollutant controlled. A more detailed
explanation of these approaches is set forth at 86 FR 63154-56
(November 15, 2021) and 87 FR 74718-19 (December 6, 2022).
As such, in the individual BSER analyses set forth in further
detail section XII of the November 2021 Proposal, Section IV of the
December 2022 Supplemental Proposal, and section XI of this preamble,
for each control required in the final NSPS OOOOb, if a device is cost-
effective under either of these two approaches, it is considered cost-
effective. For EG OOOOc, which regulates only methane, a control is
considered reasonable if it is cost-effective under the single-
pollutant cost effectiveness approach. In addition to evaluating the
annual average cost effectiveness of a control option, the EPA also
considered the incremental costs associated with increasing the
stringency of emissions standards in determining the appropriate level
of stringency. See 86 FR 63156 (November 15, 2021) and 87 FR 74718-19
(December 6, 2022) for further details on incremental cost
effectiveness analysis.
The EPA provides the cost effectiveness estimates for reducing VOC
and methane emissions for various control options considered in the
November 2021 Proposal and the December 2022 Supplemental Proposal, as
well as in section XI of this preamble and associated TSDs. With
respect to VOC emissions, the EPA finds that cost effectiveness values
up to $5,540/ton of VOC reduction are reasonable for controls that we
have identified as BSER in the final NSPS OOOOb and EG OOOOc. These VOC
values are within the range of what the EPA has historically considered
to represent cost-effective controls for the reduction of VOC
emissions, including in the 2016 NSPS, based on the Agency's long
history of regulating a wide range of industries.\167\
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\167\ The EPA has never established a bright line value with
respect to cost effectiveness of VOC reductions under CAA section
111, because the cost effectiveness conclusions in individual
rulemakings can be influenced by a variety of factors. Nonetheless,
the cost effectiveness values determined to be reasonable for VOC
reductions in this action are consistent with values the EPA has
determined to be reasonable in actions for other industries. See,
e.g., 88 FR 29978 (May 9, 2023) (finding control measures available
at $6,800/ton of VOC reduced reasonable for Automobile and Light
Duty Truck Surface Coating Operations); 87 FR 35608 (June 10, 2022)
(proposing to find control measures available for Bulk Gasoline
Terminals with incremental cost effectiveness reasonable at $4,020/
ton of VOC reduced and unreasonable at $8,300/ton of VOC reduced).
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For methane, the 2016 NSPS OOOOa was the first national standard
for reducing methane emissions. Accordingly, at that time, the EPA
considered a variety of information in evaluating whether the costs of
control that would be imposed by the final NSPS and presumptive EG
standards in this action are reasonable. As discussed in the November
2021 Proposal, the EPA previously determined that methane cost
effectiveness values for the controls identified as BSER for the 2016
NSPS OOOOa, which ranged up to $2,185/ton of methane reduction,
represent reasonable costs for the industry as a whole to bear to
reduce pollution. 86 FR 63155 (November 15, 2021). The reasonableness
of the methane value selected in that rulemaking is reinforced by the
fact that sources have been complying with the 2016 NSPS OOOOa for
years without deleterious effect on the industry as a whole, which
indicates that the NSPS OOOOa standards are not unduly burdensome from
a cost perspective. The final standards in this rulemaking similarly
reflect control mechanisms and measures that many companies and sources
around the country are already implementing--again, without deleterious
effect on industry as a whole--which shows not only that such controls
are ``adequately demonstrated'' but also underscores their
reasonableness from a cost perspective.
[[Page 16865]]
For methane, the controls that we have identified as BSER in the final
NSPS OOOOb and EG OOOOc to be reasonable at cost-effectiveness values
up to $2,048/ton of methane reduction. The fact that the cost
effectiveness estimates for the final standards in this action are
comparable to (and in many individual instances, lower than) the cost
effectiveness values estimated for the controls that served as the
basis (i.e., BSER) for the standards in the 2016 NSPS OOOOa, which have
been in place for years, reinforces the conclusion that the final NSPS
and presumptive standards in this rule are also cost-effective and
reasonable.
As explained in further detail in the November 2021 Proposal, when
determining the overall costs of implementation of the control
technology and the associated cost effectiveness, the EPA takes into
account cost savings from any natural gas recovered instead of vented
as a result of the emissions controls. In our analysis, we consider any
natural gas that is either recovered or not emitted as a result of a
control option as being ``saved;'' we then apply the monetary value of
the saved natural gas (estimated at $3.13 per Mcf),\168\ as an offset
to the control cost. Notably, this offset does not apply where the
owner or operator does not own the gas and would not likely realize the
monetary value of the natural gas saved (e.g., transmission stations
and storage facilities). Detailed discussions of this approach are
presented in section 2 of the RIA and at 86 FR 63156 (November 15,
2021).
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\168\ This value reflects the forecasted Henry Hub price for
2022 from: U.S. Energy Information Administration. Short-Term Energy
Outlook. https://www.eia.gov/outlooks/steo/archives/may21.pdf.
Release Date: May 11, 2021.
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We also updated the two additional analyses that the EPA performed
for both the November 2021 Proposal and the December 2022 Supplemental
Proposal to further inform our determination of whether the cost of
control of the collection of standards would be reasonable, similar to
compliance cost analyses we have completed for other NSPS.\169\ The two
additional analyses include: (1) a comparison of the capital costs
incurred by compliance with the rulemaking to the industry's estimated
new annual capital expenditures, and (2) a comparison of the annualized
costs that would be incurred by compliance with the final NSPS and
presumptive EG standards to the industry's estimated annual revenues.
In this section, the EPA provides updated information regarding these
cost analyses based on the standards described in this document. See 86
FR 63156-7 (November 15, 2021) and 87 FR 74718-19 (December 6, 2022)
for additional discussion on these two analyses. The results of both
analyses, described in more detail in the following paragraphs, each
independently demonstrate the reasonableness of the cost-effectiveness
values applied in this final NSPS OOOOb and EG OOOOc, as well as
demonstrate that the collective costs of the suite of final standards
are reasonable in the context of the industry as a whole.
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\169\ For example, see our compliance cost analysis in
``Regulatory Impact Analysis (RIA) for Residential Wood Heaters NSPS
Revision. Final Report.'' U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards. EPA-452/R-15-001,
February 2015.
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First, for the capital expenditures analysis, the EPA divided the
nationwide capital expenditures projected to be spent to comply with
the standards finalized in this rulemaking by an estimate of the total
sector-level new capital expenditures for a representative year; this
calculation shows the percentage that the nationwide capital cost
requirements under the final standards represent of the total capital
expenditures by the sector. The EPA combined the compliance-related
capital costs under the final standards for NSPS OOOOb and for the
presumptive standards in the final EG OOOOc in order to analyze the
potential aggregate impact of the rulemaking. The equivalent annualized
value (EAV) of the projected compliance-related capital expenditures
over the 2024 to 2038 period is projected to be about $2.5 billion in
2019 dollars. We obtained new capital expenditure data for relevant
NAICS codes for 2018-2021 from the 2019, 2020, and 2021 editions of the
U.S. Census Annual Capital Expenditures Survey.\170\ According to these
data, new capital expenditures for the sector ranged from $79 billion
in 2021 to $156 billion in 2019 w in 2019 dollars.\171\ The wide range
of annual expenditures across years are likely due to COVID-19-related
impacts that dampened spending in 2020 and 2021. As such, while we
conducted the analysis for all years from 2018 to 2021, we view the
results for 2018 and 2019 as more representative of expected industry
outlays going forward. Note that new capital expenditures in 2019 for
pipeline transportation of natural gas (NAICS 4862) includes only
expenditures on structures because data on equipment expenditures are
withheld to avoid disclosing data for individual enterprises. As a
result, the 2019 capital expenditures used here represent an
underestimate of the sector's expenditures. Comparing the EAV of the
projected compliance-related capital expenditures under this rule with
the 2019 total sector-level new capital expenditures yields a
percentage of about 1.6 percent, which is well below the percentage
increase previously upheld by the courts as reasonable under CAA
section 111. See detailed discussion at 86 FR 63156-7 (November 15,
2021) (citing Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 437-40
(D.C. Cir. 1973); Portland Cement Ass'n v. Train, 513 F.2d 506, 508
(D.C. Cir. 1975)). The same comparison for 2021 total sector-level new
capital expenditures yields a percentage of about 3.2 percent.
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\170\ U.S. Census Bureau, 2020 Annual Capital Expenditures
Survey, table 4b. Capital Expenditures for Structures and Equipment
for Companies with Employees by Industry: 2019 Revised, https://www.census.gov/data/tables/2020/econ/aces/2020-aces-summary.html,
accessed July 12, 2022.
\171\ The total capital expenditures for the same NAICS codes
during 2018 and 2020 were about $154 billion and $90 billion,
respectively, in 2019 dollars.
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Second, for the comparison of compliance costs to revenues, we used
the EAV of the projected compliance costs both with and without
projected revenues from product recovery under the rule for the 2024 to
2038 period, then divided the nationwide annualized costs by the annual
revenues for the appropriate NAICS code(s) for a representative year in
order to determine the percentage that the nationwide annualized costs
represent of annual revenues. Like we do for capital expenditures, we
combine the costs projected to be expended to comply with the standards
for NSPS and the presumptive standards in the EG in order to analyze
the potential aggregate impact of the rule. The EAV of the associated
increase in compliance cost over the 2024 to 2038 period is projected
to be about $2.7 billion without revenues from product recovery and
about $1.7 billion with revenues from product recovery (in 2019
dollars). Revenue data for relevant NAICS codes were obtained from the
U.S. Census 2017 County Business Patterns and Economic Census, the most
recent revenue figures available.\172\ According to these data, 2017
receipts for the sector were about $357 billion in 2019 dollars.
Comparing the EAV of the projected compliance costs under the
rulemaking with the sector-level
[[Page 16866]]
receipts figure yields a percentage of about 0.8 percent without
revenues from product recovery and about 0.5 percent with revenues from
product recovery. More data and analysis supporting the comparison of
capital expenditures and annualized costs projected to be incurred
under the rule and the sector-level capital expenditures and receipts
is presented in the TSD for this action, which is in the public docket.
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\172\ 2017 County Business Patterns and Economic Census. The
Number of Firms and Establishments, Employment, Annual Payroll, and
Receipts by Industry and Enterprise Receipts Size: 2017, https://www.census.gov/programs-surveys/susb/data/tables.2017.html, accessed
October 16. 2023.
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Based on all of the cost-related information, data, and analyses
described above, and as explained in further detail in the individual
sections describing the BSER for each control in this preamble, the
November 2021 Proposal, and the December 2022 Supplemental Proposal,
the EPA concludes that the costs of the controls that serve as the
basis the final NSPS OOOOb and EG OOOOc are reasonable.
Some commenters have argued that the EPA was required to perform a
cost-benefit analysis of this rulemaking demonstrating that the costs
outweigh the benefits, and have cited the Supreme Court's decision in
Michigan v. EPA, 576 U.S. 743 (2015) in support of this contention. One
commenter \173\ contends that the EPA's proposal is not reasonable if
the climate benefits are illusory, and questions ``[w]hat benefit-cost
calculation makes the proposed regulatory surge a smart investment of
public and private resources.'' The commenter also takes issue with the
EPA's statement in the Supplemental Proposal that our ``monetized
benefits analysis is entirely distinct from the statutory BSER
determinations proposed herein and is presented solely for the purposes
of complying with E.O. 12866,'' 87 FR 74843. The commenter cites one
excerpt from the Supreme Court's decision Michigan in support of its
argument: ``One would not say that it is even rational, never mind
`appropriate,' to impose billions of dollars in economic costs in
return for a few dollars in health or environmental benefits . . . No
regulation is `appropriate' if it does significantly more harm than
good.'' 576 U.S. at 752. Another group of commenters \174\ quotes the
same language from the case and asserts that the EPA must ``balance the
costs associated with government regulation against compliance costs,''
and that the November 2021 Proposed Rule ``fails the cost-benefits
test.''
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\173\ Document ID No. EPA-HQ-OAR-2021-0317-2359.
\174\ Document ID No. EPA-HQ-OAR-2021-0317-0790.
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The EPA is mindful of the Supreme Court's holding in Michigan and
has carefully considered how it applies to this rulemaking. The EPA
disagrees with the commenters insofar as they suggest that the EPA was
required--under Michigan or any other authority--to undertake a formal
cost-benefit analysis in this rulemaking. In Michigan, the Supreme
Court concluded that the EPA erred when it concluded it could not
consider costs when deciding whether it is ``appropriate and
necessary'' under CAA section 112(n)(1)(A) to regulate hazardous air
pollutants from electric utility steam generating units (power plants),
despite the relevant statutory provision containing no specific
reference to cost. 576 U.S. at 751. In doing so, the Court held that
the EPA ``must consider cost--including, most importantly, cost of
compliance--before deciding whether regulation is appropriate and
necessary'' under CAA section 112. Id. at 759. In examining the
language of CAA section 112(n)(1)(A), the Court concluded that the
phrase ``appropriate and necessary'' was ``capacious'' and held that
``[r]ead naturally in the present context, the phrase `appropriate and
necessary' requires at least some attention to cost.'' Id. at 752. This
capaciousness was relevant in the context of section 112(n)(1)(A)
because that section directs the EPA to determine ``whether to
regulate'' the emission source, which is a context in which
``[a]gencies have long treated cost as a centrally relevant factor.''
Id. at 753 (emphasis added).
The Supreme Court added in Michigan that it ``need not and [does]
not hold that the law unambiguously required the Agency, when making
this preliminary estimate [of costs under the `appropriate and
necessary' standard of CAA 112(n)(a)(1)], to conduct a formal cost-
benefit analysis in which each advantage and disadvantage is assigned a
monetary value. It will be up to the Agency to decide (as always,
within the limits of reasonable interpretation) how to account for
cost.'' Id. at 759.
Section 111 differs in material respects from the provision the
Supreme Court interpreted in Michigan. Unlike the circumstances at
issue in Michigan, the predicate decision whether to regulate the
emission source has already been made here. CAA section 111(b)(1)(A)
requires the Administrator to list a source category ``if, in his
judgment, it causes or contributes significantly to, air pollution
which may reasonably be anticipated to endanger public health or
welfare.'' Notably, this provision does not hinge on a determination,
like that under consideration in Michigan with respect to CAA section
112, that such listing is ``appropriate and necessary.'' Indeed, the
EPA has long regulated emissions from the oil and gas source category,
having first listed the source category in 1979. And once the EPA has
listed a source category, CAA section 111(b)(1)(B) and (d)(1) require
the EPA to promulgate new source performance standards and, for certain
pollutants, emission guidelines for regulation of existing sources.
Pursuant to this authority, the EPA has regulated VOC emissions since
1985 and GHG emissions (in the form of limitations on methane) since
2016. See section IV.B for further explanation of the regulatory
history for the source category; and section V for further discussion
of the EPA's authority to promulgate methane regulations.
Importantly, unlike the statutory provision at issue in Michigan,
CAA section 111 already requires the EPA to consider costs when
determining the appropriate level of control. Specifically, the
``standards of performance'' for new and existing sources finalized in
this rule are ``standard[s] for emissions of air pollutants which
reflect[] the degree of emission limitation achievable through the
application of the best system of emission reduction which (taking into
account the cost of achieving such reduction and any nonair quality
health and environmental impact and energy requirements) the
Administrator determines has been adequately demonstrated.'' CAA
section 111(a)(1) (emphasis added). Thus, even if the Court's
examination of CAA 112(n)(a)(1) in Michigan did apply to CAA section
111--which the EPA disputes--the EPA's decision here, unlike in the
rule reviewed in Michigan, is not blind to costs. Rather, the EPA has
satisfied the Court's directive to consider costs, both in the context
of the individual BSER analyses for individual emissions source (as
directed by the language of the statute) and in the context of the rule
as a whole. Moreover, while the EPA is not required to undertake a
``formal cost-benefit analysis in which each advantage and disadvantage
[of a regulation] is assigned a monetary value,'' Michigan, 576 U.S. at
759,\175\ the EPA has contemplated and carefully considered both the
advantages and disadvantages of the final NSPS OOOOb and EG OOOOc,
including the qualitative and quantitative benefits of
[[Page 16867]]
the regulation and the costs of compliance.
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\175\ Accordingly, the EPA disagrees with the commenters that
the EPA was required to demonstrate that the monetized benefits of
the regulations outweigh the costs, and the EPA does not rely on the
analysis of costs and benefits conducted to comply with E.O. 12866
for this purpose.
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The primary disadvantage that the EPA has weighed in finalizing the
NSPS OOOOb and EG OOOOc is the cost of compliance and the effects of
those costs on industry. Notably, neither CAA section 111 nor Michigan
directs that costs be considered in any particular way, and in this
action, the EPA has considered costs using the same cost metrics that
the EPA has historically used in numerous rulemakings under CAA section
111 for decades. As explained above, the EPA has used cost
effectiveness as a metric to evaluate whether the costs associated with
emissions reductions from a given technology are reasonable. This
metric (widely used in environmental regulation) provides a way for the
EPA to specifically consider the cost associated with each ton of
reduction achieved by a particular control measure, and thereby
determine whether the emission reductions achieved by the control
measure are worthwhile, both as to the individual control measure in
comparison to other available control measures, and in comparison to
the regulation of the same pollutant in other industries. As explained
in detail in section XI of this preamble, section XII of the November
2021 Proposal, and Section IV of the December 2022 Supplemental
Proposal discussing the BSER determinations for each of the regulated
emissions sources, the EPA has also considered costs in various other
ways, including capital costs and operating costs, when evaluating the
reasonableness of various control measures to determine the BSER.
In addition, the EPA conducted two cost analyses specifically for
purposes of this action in order to evaluate the costs of compliance
with the collective standards in the final NSPS OOOOb and EG OOOOc at a
sector level and consider them in the context of the industry's overall
capital expenditures and revenues. As explained in detail above, the
EPA estimates that the capital costs expected to be incurred by
compliance with the final NSPS OOOOb and EG OOOOc are about two to
three percent of the industry's estimated new annual capital
expenditures, and that the annualized compliance costs are less than
one percent of the industry's estimated annual revenues. Notably,
neither value includes increased industry revenue from the sales of
captured gas resulting from pollution controls. Thus, while the
industry will bear some costs to comply with the final NSPS OOOOb and
EG OOOOc, each of these analyses supports the EPA's determination that
the costs associated with compliance with the final standards are
reasonable and consistent with costs of control that the source
category has expended for years to comply with existing state and
Federal standards, and on voluntary actions to reduce emissions.
In terms of advantages, the final NSPS OOOOb and EG OOOOc will have
numerous benefits to the climate, the natural environment, and human
health through their projected reductions in methane and VOC emissions.
Regarding methane, the oil and natural gas sector is the largest source
of industrial methane emissions in the U.S. As described in greater
detail in section III.B.2, it represents 28 percent of U.S.
anthropogenic methane emissions and three percent of overall U.S. GHG
emissions. Moreover, methane is a powerful and potent GHG--over a 100-
year timeframe, it is nearly 30 times more powerful at trapping climate
warming heat than CO2, and over a 20-year timeframe, it is
83 times more powerful. Because it is particularly potent and emitted
in large quantities, methane mitigation provides one of the best
opportunities to reduce near-term warming and offers important climate
benefits.
The projected methane emissions reductions from the final NSPS
OOOOb and EG OOOOc standards, for each regulated emission source and
taken together as a whole, will contribute to avoided climate and human
health impacts, which are described in greater detail in section
III.A.1 of this preamble, as well as in section III.A of the November
2021 Proposal. Warming temperatures in the atmosphere, ocean, and land
have led to, for example: increased numbers of heat waves, wildfires,
and other severe weather events; reduced air quality; more intense
hurricanes and rainfall events; and sea level rise. These environmental
changes, along with future projected changes, endanger the physical
survival, health, economic well-being, and quality of life of people
living in the U.S., particularly those in the most vulnerable
communities. As discussed in greater detail in section III.A.1, impacts
from climate change driven by GHG emissions are wide-ranging in type
and scope, and present serious threats to human life and the natural
environment. For example, severe weather events and natural disasters
exacerbated by climate change--such as droughts, floods, storm surges,
wildfires, and heat waves--affect food security, air quality and
respiratory health, availability of fresh drinking water, population
stability, national security, participation in the workforce, and
infrastructure and property, among many others. Other environmental
impacts of climate change such as ocean acidification, altered plant
growth, and increased concentrations of ozone also affect human health
and well-being, in addition to that of the natural environment.
The final NSPS OOOOb and EG OOOOc standards are projected to reduce
58 million short tons of methane emissions from 2024 to 2038, which
represents a 79 percent reduction in projected emissions from the
sources covered in NSPS OOOOb and EG OOOOc. Accordingly, significantly
reducing emissions of methane from the largest U.S. industrial source
of this highly potent GHG will have meaningful climate benefits and
environmental impacts, which will in turn have beneficial impacts on
human health.
As described in more detail in section III.A.2, reducing VOC
emissions will also benefit human health and the environment. The oil
and natural gas sector represents the top anthropogenic U.S. sector for
VOC emissions (after removing the biogenics and wildfire sectors),
which is about 23 percent of total VOCs emitted by U.S. anthropogenic
sources. See section III.B.2. VOCs can cause a variety of health
concerns, including cancerous and noncancerous illnesses, particularly
respiratory and neurological ones. VOCs are also one of the key
precursors in the formation of ozone. Tropospheric, or ground-level,
ozone is formed through reactions of VOC and NOx in the presence of
sunlight; ozone formation can be controlled to some extent through
reductions in emissions of the ozone precursors VOC and NOx. Health
effects of ozone exposure include premature death from lung or heart
diseases, as well as harmful symptoms and the development of asthma.
Repeated exposure to ozone can also have harmful effects on sensitive
plants and trees, which have the potential to impact ecosystems and the
services they provide. The final NSPS OOOOb and EG OOOOc standards are
projected to reduce 16 million short tons of VOC emissions from 2024-
2038, which represent a 47 percent reduction in projected emissions
from the sources covered in NSPS OOOOb and EG OOOOc.\176\ Significant
reductions in
[[Page 16868]]
VOCs, like methane reductions, will have significant benefits to human
health and the environment.
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\176\ The percent reduction is calculated as the ratio of the
sum of estimated emissions reductions for the NSPS from 2024-2038
and for the EG from 2028-2038 to the sum of estimated baseline
emissions for the NSPS from 2024-2038 and for the EG from 2028-2038.
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In consideration of all of this information, the EPA has concluded
that, based on the totality of circumstances, the advantages that the
rule provides--namely in the form of a substantial and meaningful
reduction in methane and VOC pollution, and the associated positive
impacts on public health and the natural environment (as discussed in
detail in Section III.A)--outweigh its disadvantages, namely cost of
industry compliance in the context of the industry's revenue and
expenditures.
IX. Interaction of the Rules and Response to Significant Comments
Thereon
A. What date defines a new, modified, or reconstructed source for
purposes of the final NSPS OOOOb?
NSPS OOOOb would apply to all emissions sources (``affected
facilities'') identified in the final 40 CFR 60.5365b that commenced
construction, reconstruction, or modification after December 6, 2022.
Pursuant to CAA section 111(b), the EPA proposed NSPS for a wide
range of emissions sources in the Crude Oil and Natural Gas source
category in November 2021. Some of the proposed standards resulted from
the EPA's review of the current NSPS codified at 40 CFR part 60 subpart
OOOOa, while others were proposed standards for additional emissions
sources that are currently unregulated. The emissions sources for which
the EPA proposed standards in the November 2021 Proposal are as
follows:
Well completions
Gas well liquids unloading operations
Associated gas from oil wells
Wet seal centrifugal compressors
Reciprocating compressors
Process controllers
Pumps
Storage vessels
Collection of fugitive emissions components at well sites,
centralized production facilities, and compressor stations
Equipment leaks at natural gas processing plants
Sweetening units
The EPA proposed standards for an additional emissions source,
specifically dry seal centrifugal compressors, in the December 2022
Supplemental Proposal, while also providing numerous significant
updates to the standards previously proposed in the November 2021
Proposal.
These final standards of performance apply to ``new sources.'' CAA
section 111(a)(2) defines a ``new source'' as ``any stationary source,
the construction or modification of which is commenced after the
publication of regulations (or, if earlier, proposed regulations)
prescribing a standard of performance under this section which will be
applicable to such source.'' While the initial rulemaking proposing the
standards for these emission sources was published November 15, 2021,
due to many significant updates included in the December 2022
Supplemental Proposal, and the addition of dry seal centrifugal
compressor proposed standards, the EPA is specifying that the ``new
sources'' to which the final standards in NSPS OOOOb apply are those
that commenced construction, reconstruction, or modification after
December 6, 2022 (the date the supplemental proposal published in the
Federal Register).
We received comments on the November 2021 Proposal that the
proposal lacked regulatory text and therefore should not be used to
define new sources for purposes of NSPS OOOOb.\177\ The EPA disagrees
that absence of a regulatory text in a proposal necessarily means that
sources constructed after the date of the proposal cannot be ``new
sources'' for purposes of an NSPS. Regardless, based on the unique
facts and circumstances here, the EPA has concluded that only sources
constructed, modified, or reconstructed after the date of the
supplemental proposal should be considered new sources for the purposes
of NSPS OOOOb.
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\177\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0424, -0539, -
0579, -0598, -0599, -0815, and -0929.
---------------------------------------------------------------------------
On the unique facts and circumstances here, defining new sources
based on the date of the supplemental proposal is consistent with CAA
section 111(a)(2). That provision does not require the EPA to define
new sources based on the date of the first proposal. Instead, CAA
section 111(a)(2) states that a new source is ``any stationary source,
the construction or modification of which is commenced after the
publication of regulations (or, if earlier, proposed regulations)
prescribing a standard of performance under this section which will be
applicable to such source.'' The statute's general reference to
``proposed regulations'' gives the EPA discretion to determine which
proposal (either an initial proposal or a supplemental proposal) should
be used to define the universe of new sources in appropriate
circumstances. For the reasons stated above, it is reasonable based on
the facts and circumstances of this rule to define the date for NSPS
OOOOb based on the date of the supplemental proposal. These facts and
circumstances include that the supplemental proposal included several
updates to the proposed standards and rationale supporting those
standards for many different sources, and that the supplemental
proposal included new standards for a new source of emissions not
addressed by the initial proposal. For example, in the December 2022
Supplemental Proposal, the EPA proposed changes to the proposed
standards for fugitives at well sites, the use of alternative
monitoring approaches for fugitives, pumps, and standards for dry seal
centrifugal compressors. Having potentially differing dates for various
new sources (e.g., one date for sources that the EPA did not propose
changes in the December 2022 Supplemental Proposal and another date for
sources that the EPA did propose changes to in the December 2022
Supplemental Proposal) that could be within the same facility would
complicate the due dates for annual reporting. Having the same date for
all sources at a facility will reduce burden on owners and operators to
be able to have all annual reporting due simultaneously. Taken
together, these facts support establishing the definition of new
sources for purposes of NSPS OOOOb as those sources for which
construction, modification, or reconstruction commenced after the date
of the supplemental proposal.
Moreover, defining new sources as the EPA has described allows the
EPA to establish a single new source definition for all NSPS OOOOb,
which will streamline administration of the program for states and for
the EPA. Because the supplemental proposal included proposed standards
for certain sources not addressed in the initial proposal, if the EPA
set the definition for new sources for NSPS OOOOb based on the dates
upon which each of the standards were first proposed for each emissions
source, the new source definition would run from the date of initial
proposal for some sources of emissions, and the date of the
supplemental proposal for others. Put another way, under that scenario,
NSPS OOOOb would contain multiple definitions of ``new source'' which
would differ from standard to standard. This complexity could make
administration of the NSPS OOOOb unnecessarily cumbersome. Moreover,
the time between the original November
[[Page 16869]]
2021 Proposal and the December 2022 Supplemental Proposal was not vast.
Within this single year, the EPA believes that a relatively modest
number of sources commenced construction. While moving the
applicability date for NSPS OOOOb does mean that these sources which
commenced construction between the November 2021 Proposal and the
December 2022 Supplemental Proposal will be considered ``existing
sources'' for purposes of EG OOOOc instead of ``new sources'' under
NSPS OOOOb, the EPA believes that this is an acceptable and preferred
outcome when compared to the complexities associated with the
alternative which are explained above. Notably, the EPA is also
finalizing existing source EG in this action, which will ultimately
require these sources to comply with standards of performance adopted
in state plans under EG OOOOc.
B. What date defines an existing source for purposes of the final EG
OOOOc?
The November 2021 Proposal and December 2022 Supplemental Proposal
also included proposed emissions guidelines for states to follow to
develop plans to regulate existing sources in the Crude Oil and Natural
Gas source category under EG OOOOc. Under CAA section 111, relative to
a particular NSPS, a source is considered either new, i.e.,
construction, reconstruction, or modification commenced after a
proposed NSPS is published in the Federal Register (CAA section
111(a)(2)), or existing, i.e., any source other than a new source (CAA
section 111(a)(6)). Accordingly, any source that is not subject to the
proposed NSPS OOOOb as described is an existing source for purposes of
EG OOOOc. As explained, the EPA is finalizing that for purposes of NSPS
OOOOb new sources are those that commenced construction,
reconstruction, or modification after December 6, 2022. Therefore,
existing sources are those that commenced construction, reconstruction,
or modification on or before December 6, 2022.
C. How will the final EG OOOOc impact sources already subject to NSPS
KKK, NSPS OOOO, or NSPS OOOOa?
Sources currently subject to 40 CFR part 60, subpart KKK (NSPS
KKK), 40 CFR part 60, subpart OOOO, or NSPS OOOOa would continue to
comply with their respective VOC and methane standards until sources
are subject to and in compliance with a state or Federal plan
implementing EG OOOOc. While EG OOOOc specifically addresses methane
and not VOC, any reductions from the methane standards established in a
state or Federal plan implementing EG OOOOc will similarly reduce VOCs.
Therefore, the EPA concludes that the methane presumptive standards in
EG OOOOc will result in the same or greater emission reductions than
the VOC and methane standards in previous NSPS KKK, NSPS OOOO, or NSPS
OOOOa. Once sources are subject to and in compliance with a state or
Federal plan implementing EG OOOOc, and if that plan is just as
stringent as or more stringent than the presumptive standards in EG
OOOOc, the source will be deemed to comply with the previous respective
VOC NSPS, and no longer subject to the methane NSPS, and will comply
with only the state or Federal plan implementing EG OOOOc. Because the
EG OOOOc does not contain SO2 standards, sources subject to
SO2 standards in NSPS OOOO or NSPS OOOOa would continue to
comply with their respective SO2 standards unless they
modify and become subject to the requirements in NSPS OOOOb.
In this rulemaking, the EPA is finalizing standards for dry seal
centrifugal compressor and intermittent vent process controllers for
the first time in NSPS OOOOb and presumptive standards in EG OOOOc.
These designated facilities (i.e., dry seal centrifugal compressors and
intermittent vent process controllers) are not subject to regulation
under a previous NSPS. The EPA is also finalizing presumptive standards
in EG OOOOc for fugitive emissions at compressor stations, pumps at
natural gas processing plants, and process controllers at natural gas
processing plants that are all the same or more stringent than previous
standards in NSPS KKK, NSPS OOOO, and NSPS OOOOa, as applicable.
Additionally, the final presumptive standards in EG OOOOc for pumps
(excluding processing) and natural gas processing plant equipment leaks
are more stringent than the standards in NSPS OOOOa for pneumatic pumps
and the standards in NSPS KKK, NSPS OOOO, and NSPS OOOOa for natural
gas processing plant equipment leaks.
For wet seal centrifugal compressors, two different standards are
in place in the previous NSPS. NSPS KKK is an equipment standard that
provides several compliance options including: (1) Operating the
compressor with the barrier fluid at a pressure that is greater than
the compressor stuffing box pressure; (2) equipping the compressor with
a barrier fluid system degassing reservoir that is routed to a process
or fuel gas system, or that is connected by a CVS to a control device
that reduces VOC emissions by 95 percent or more; or (3) equipping the
compressor with a system that purges the barrier fluid into a process
stream with zero VOC emissions to the atmosphere. NSPS KKK exempts a
compressor from these requirements if it is either equipped with a
closed vent system to capture and transport leakage from the compressor
drive shaft back to a process or fuel gas system or to a control device
that reduces VOC emissions by 95 percent, or if it is designated for no
detectable emissions (NDE). NSPS OOOO and NSPS OOOOa require 95 percent
reduction of emissions from each centrifugal compressor wet seal fluid
degassing system. NSPS OOOO and OOOOa also allow the alternative of
routing the emissions to a process. For sources transitioning from NSPS
KKK to EG OOOOc, the EPA is finalizing a subcategory for wet seal
centrifugal compressors at onshore natural gas processing plants for
which construction, reconstruction, or modification commenced after
January 20, 1984, and on or before August 23, 2011. This subcategory
will apply to all sources that were previously subject to NSPS KKK, and
have EG OOOOc presumptive standards that are equivalent to NSPS KKK
with three compliance options including: (1) operating the compressor
with the barrier fluid at a pressure that is greater than the
compressor stuffing box pressure; (2) equipping the compressor with a
barrier fluid system degassing reservoir that is routed to a process or
fuel gas system, or that is connected by a CVS to a control device that
reduces methane emissions by 95 percent or more; or (3) equipping the
compressor with a system that purges the barrier fluid into a process
stream with zero methane emissions to the atmosphere. While EG OOOOc
specifically addresses methane and not VOC, any reductions from the
methane standards contained in this subcategory that reduce methane as
established in a state or Federal plan implementing EG OOOOc will
similarly reduce VOCs. Therefore, wet seal centrifugal compressors
within this subcategory will only need to comply with a state or
Federal plan implementing EG OOOOc and will then no longer need to
comply with NSPS KKK. The EPA is not aware of any wet seal centrifugal
compressors subject to NSPS OOOO or NSPS OOOOa, and the EPA believes
that centrifugal compressors installed since those rules went into
effect (August 2011 and September 2015) are utilizing dry seals rather
than wet seals.
Similarly, there are two different standards for reciprocating
compressors
[[Page 16870]]
in the previous NSPS: (1) NSPS KKK requires the use of a seal system
and includes a barrier fluid system that prevents leakage of VOC to the
atmosphere for reciprocating compressors located at natural gas
processing plants, and (2) NSPS OOOO and NSPS OOOOa require changing
out the rod packing every 3 years or routing emissions to a control.
For sources transitioning from NSPS KKK to EG OOOOc, the EPA is
finalizing a subcategory for reciprocating compressors at onshore
natural gas processing plants for which construction, reconstruction,
or modification commenced after January 20, 1984, and on or before
August 23, 2011. This subcategory will apply to all sources that were
previously subject to the VOC standards of NSPS KKK and have EG OOOOc
presumptive standards that are equivalent to the VOC standards of NSPS
KKK with the requirement of the use of a seal system and including a
barrier fluid system that prevents leakage of methane to the
atmosphere. Again, while EG OOOOc specifically regulates methane and
not VOC, any methane standards contained in this subcategory that
reduce methane as established in a state or Federal plan implementing
EG OOOOc will similarly reduce VOCs. Therefore, reciprocating
compressors within this subcategory will only need to comply with a
state or Federal plan implementing EG OOOOc and will then no longer
need to comply with NSPS KKK. For sources transitioning from NSPS OOOO
and NSPS OOOOa, as previously explained in section XII.E.1.d of the
November 2021 Proposal \178\ and section IV.I of the December 2022
Supplemental Proposal, the EPA concludes that the final EG OOOOc
presumptive methane standard is more efficient at discovering and
reducing any emissions that may develop than the set 3-year replacement
interval from NSPS OOOO and NSPS OOOOa. Overall, the final presumptive
standards in EG OOOOc would result in more rod packing replacements,
thereby reducing more emissions compared to the 3-year interval.
Therefore, reciprocating compressors transitioning from NSPS OOOO and
NSPS OOOOa only need to comply with a state or Federal plan
implementing EG OOOOc, and will then be no longer needed to comply with
NSPS OOOO or NSPS OOOOa.
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\178\ 86 FR 63215-20 (November 15, 2021).
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The affected facility for storage vessels is defined in the NSPS
OOOO and NSPS OOOOa as a single storage vessel with the potential to
emit (PTE) greater than 6 tons of VOC per year and the standard that
applies is 95 percent emissions reduction. Under the final EG OOOOc,
the designated facility is a tank battery with the PTE greater than 20
tons of methane per year with the same 95 percent emission reduction
standard. Affected facilities under NSPS OOOO or OOOOa that are part of
a designated facility under the EG presumptive standard would be
required to meet the 95 percent reduction standard, and therefore only
need to comply with a state or Federal plan implementing EG OOOOc and
will then no longer need to comply with NSPS OOOO or OOOOa. Affected
facilities under NSPS OOOO or OOOOa that emit 6 tpy or more of VOCs but
that do not meet the PTE 20 tons of methane per year definition would
continue to comply with the 95-percent emissions reduction standard in
their respective NSPS. Scenarios regarding further physical or
operational changes in NSPS OOOOb that would reclassify sources from
the previous NSPS and/or EG OOOOc into NSPS OOOOb are discussed in
section IV.J.1.b of this preamble.
Similarly, process controller affected facilities not located at
natural gas processing plants are defined as single high-bleed
controllers with a low-bleed standard under NSPS OOOO and NSPS OOOOa,
while the designated facility under EG OOOOc is defined as a collection
of natural gas-driven process controllers at a site with a zero-
emissions standard (discussed further in section IV.D of this
preamble). Because the final zero-emissions presumptive standard in EG
OOOOc is more stringent than the low-bleed standard found in the
previous NSPS, sources only need to comply with a state or Federal plan
implementing EG OOOOc and will then no longer need to comply with NSPS
OOOO and OOOOa (assuming the state or Federal plan implementing EG
OOOOc is as stringent as the presumptive standard of zero emissions in
the final EG).
Lastly, standards for fugitive emissions from well sites under NSPS
OOOOa require semiannual OGI monitoring on all components at the well
site except for wellhead only well sites (which are not affected
facilities), while the presumptive standards under the final EG OOOOc
would require quarterly OGI monitoring with bimonthly audible, visual,
and olfactory (AVO) inspections at well sites with major production and
processing equipment, semiannual OGI combined with quarterly AVO
inspections at multi-wellhead only well sites,\179\ and quarterly AVO
inspections for small sites and single wellhead well sites, as
described in sections X and XI of this preamble. It is clear that the
final presumptive standards in EG OOOOc for well sites with major
production and processing equipment and the final presumptive standards
for multi-wellheads only well sites are both more stringent than the
semiannual OGI monitoring standard under NSPS OOOOa because one would
require more frequent OGI monitoring while the other would require AVO
inspections in addition to semiannual OGI monitoring. Therefore, these
existing well sites only need to comply with a state or Federal plan
implementing EG OOOOc and will then no longer need to comply with NSPS
OOOOa. Likewise, as the EPA has concluded that the advanced methane
detection technology periodic screening work practice being finalized
in EG OOOOc is equivalent to the standard fugitive emissions work
practice using OGI and AVO, the advanced methane detection technology
periodic screening work practice being finalized in EG OOOOc is also
more stringent than the OGI monitoring standard in NSPS OOOOa. In order
to allow owners and operators to adopt implementation of these advanced
methane detection technologies early, the EPA is finalizing in NSPS
OOOOa an option for owners and operators to comply with the advanced
methane detection technology work practices in NSPS OOOOb in lieu of
the OGI surveys required in 40 CFR 60.5397a. The EPA recognizes that
there are some differences between the definition of fugitive emissions
component between EG OOOOc and NSPS OOOOa. In NSPS OOOOa, the EPA has
clarified that if an owner or operator subject to NSPS OOOOa chooses to
implement the advanced methane detection technology work practices in
NSPS OOOOb the definitions in 40 CFR 60.5430b, which would include the
definition of fugitive emissions component, apply for the purposes of
the advanced methane detection technology work practice.
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\179\ Because of a difference in the definition of a wellhead
only well site in NSPS OOOOa and the proposed EG OOOOc, some single
and multi-wellhead only well sites could be subject to the
semiannual OGI monitoring under NSPS OOOOa.
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For existing single wellhead only well sites and small sites that
are previously subject to the semiannual monitoring under NSPS OOOOa
and transitioning to EG OOOOc, the EPA is concluding that, as explained
in more detail in section IV.A of this preamble, AVO is effective, and
therefore OGI is unnecessary, for detecting fugitive emissions from
many of the fugitive emissions components at these sites. By
[[Page 16871]]
requiring more frequent visits to the sites, the final presumptive
standard in EG OOOOc would allow earlier detection and repair of
fugitive emissions, in particular large emissions from components such
as thief hatches on uncontrolled storage vessels. The EPA concludes
that the final presumptive standards under the proposed EG OOOOc would
effectively address the fugitive emissions at these well sites and that
semiannual OGI monitoring would no longer be necessary for these well
sites. Therefore, these sources need to comply with NSPS OOOOa until
they are in compliance with a state or Federal plan implementing EG
OOOOc. Once subject to and in compliance with such a plan, then they no
longer need to comply with NSPS OOOOa.
X. Summary of Final Standards NSPS OOOOb and EG OOOOc
A. Fugitive Emissions From Well Sites, Centralized Production
Facilities, and Compressor Stations
As described in section IV.A of the December 2022 Supplemental
Proposal preamble (87 FR 74722, December 6, 2022) and section XI.A of
the November 2021 Proposal preamble (86 FR 63169, November 15, 2021),
fugitive emissions are unintended emissions that can occur from a range
of components at any time due to leaks. Collectively, these emissions
constitute one of the largest sources of methane from this source
category, representing approximately 700 kt of the 2019 methane
emissions from this source category reported in the GHGI. The magnitude
of these emissions can also vary widely across different facilities and
over time. The EPA has historically addressed fugitive emissions from
the Crude Oil and Natural Gas source category through ground-based
component level monitoring using OGI or EPA Method 21 of appendix A-7
to 40 CFR part 60.
This section of the preamble presents a summary of the final
standards for NSPS OOOOb and final presumptive standards for EG OOOOc
regarding fugitive emissions components affected facilities and
designated facilities located at well sites, centralized production
facilities, and compressor stations. As defined in the final NSPS
OOOOb, a fugitive emissions component is ``any component that has the
potential to emit fugitive emissions of methane or VOC at a well site,
centralized production facility, or compressor station, such as valves
(including separator dump valves), connectors, pressure relief devices,
open-ended lines, flanges, covers and closed vent systems not subject
to Sec. 60.5411b, thief hatches or other openings on a storage vessel
not subject to Sec. 60.5395b, compressors, instruments, meters, and
yard piping.'' \180\
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\180\ The definition of a fugitive emissions component in EG
OOOOc is the same except for the reference to 60.5411c instead of
60.5411b and 60.5396c instead of 60.5395b.
---------------------------------------------------------------------------
1. Fugitive Emissions at Well Sites and Centralized Production
Facilities
a. NSPS OOOOb
i. Affected Facility
The standards apply to each fugitive emissions components affected
facility, which is the collection of fugitive emissions components at a
well site or centralized production facility.
ii. Final Standards
In this final rule, the EPA is finalizing the work practice
standards for monitoring and repairing (including replacing) fugitive
emissions components at fugitive emissions components affected
facilities located at well sites and centralized production facilities,
as proposed in the December 2022 Supplemental Proposal. Specifically,
the EPA is finalizing monitoring and repair programs for four
subcategories of well sites as follows:
1. Single wellhead only well sites: Quarterly AVO inspections,
2. Multi-wellhead only well sites: Semiannual OGI (or EPA Method
21) monitoring following the monitoring plan required in 40 CFR
60.5397b and quarterly AVO inspections,
3. Well sites with major production and processing equipment and
centralized production facilities: Quarterly OGI (or EPA Method 21)
monitoring following the monitoring plan required in 40 CFR 60.5397b
and bimonthly AVO inspections, and
4. Small well sites: Quarterly AVO inspections.
The third subcategory includes well sites and centralized
production facilities that have:
1. One or more controlled storage vessels or tank batteries,
2. One or more control devices,
3. One or more natural gas-driven process controllers or pumps, or
4. Two or more pieces of major production or processing equipment
not listed in items 1-3.
The EPA explained in the December 2022 Supplemental Proposal that
it was proposing to define this third subcategory as such (in
particular items 1-3 above) ``because those sources individually are
known sources of super-emitter emissions events (see section IV.C) and
are subject to quarterly OGI for compliance assurance (storage vessels
and pneumatic controllers) or are subject to other continuous
monitoring requirements (control devices).'' \181\ As discussed in
section XI.D.3 of this preamble, we have changed the terminology from
``pneumatic controllers'' to ``process controllers'' in the final rule.
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\181\ 87 FR 74735.
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Also, as explained in the December 2022 Supplemental Proposal, the
fourth subcategory, small well sites, includes single wellhead well
sites that do not contain any controlled storage vessels, control
devices, natural gas-driven process controllers, or natural gas-driven
pumps and contain only one piece of certain major production and
processing equipment. Major production and processing equipment that
would be allowed at a small well site would include a single separator,
glycol dehydrator, centrifugal or reciprocating compressor, heater/
treater, or a storage vessel that is not controlled. Id. at 74723.
For the second subcategory, multi-wellhead only well sites, where
semiannual OGI monitoring is required, subsequent semiannual monitoring
would be required to occur at least 4 months apart and no more than 7
months apart. For the third subcategory, well sites with major
production and processing equipment and centralized production
facilities, where quarterly OGI monitoring is required, subsequent
quarterly monitoring would occur at least 60 days apart. Quarterly OGI
monitoring may be waived when temperatures are below 0 [deg]F for two
of three consecutive calendar months of a quarterly monitoring period.
In the final rule, the EPA clarified that the monitoring
requirements for fugitive emissions components do not apply to buried
yard piping and associated buried fugitive emissions components (e.g.,
buried connectors on the buried yard piping).
In addition to clarifying in the fugitive emissions component
definition that ``valves'' include dump valves, the EPA specifies in
the final rule the requirement to visually inspect the separator dump
valve while at the site conducting regular AVO monitoring surveys
(either quarterly or bimonthly, depending on the site) to ensure that
it is operating as designed and not stuck in an open position. As
proposed in the December 2022 Supplemental Proposal, the EPA is also
finalizing the closed and sealed requirement for thief hatches or other
openings (on storage vessels or tank batteries) that are fugitive
emissions components and the
[[Page 16872]]
requirement to visually inspect the hatch to confirm compliance during
the AVO monitoring survey.
The EPA is finalizing the following repair timelines. A first
attempt at repair of malfunctioning separator dump valves, open or
unsealed thief hatches and other storage vessel openings, or other
sources of fugitive emissions identified with AVO must be made within
15 days after the detection, with final repair required within 15 days
after the first attempt. A first attempt at repair of the source of
fugitive emissions identified with OGI or EPA Method 21 must be made
within 30 days after the detection, with final repair required within
30 days after the first attempt. The EPA is also finalizing provisions
to allow a delay of repair if the repair is technically infeasible,
would require a vent blowdown, well shutdown, or well shut-in, would be
unsafe to repair during operation of the unit, or would require
replacement parts that are unavailable for certain reasons (see section
XI.A.1.e for details); in no case is delay allowed beyond 2 years.
Monitoring surveys of fugitive emissions components affected
facilities at a well site or centralized production facility must
continue until the site or facility is permanently closed following the
required well closure plan. After all well closure activities are
completed, a final OGI survey of the site must be conducted (and
recorded in the well closure plan) and any emissions detected must be
eliminated.
iii. Recordkeeping and Reporting Requirements
The final rule requires specific recordkeeping and reporting
requirements for each fugitive emissions components affected facility
located at a well site or centralized production facility. The
recordkeeping requirements closely follow those in the December 2022
Supplemental Proposal but incorporate the addition of new delay of
repair recordkeeping requirements. In the case of delay of repair due
to parts unavailability, operators must document the date the leak was
added to the delay of repair list, the date the replacement fugitive
emissions component or part thereof was ordered, the anticipated
delivery date, and the actual delivery date.
The reporting requirements are unchanged from the December 2022
Supplemental Proposal. Sources would be required to report the
designation of the type of site (i.e., well site or centralized
production facility) at which the fugitive emissions components
affected facility is located. In addition, for each fugitive emissions
components affected facility that becomes an affected facility during
the reporting period, the date of the startup of production or the date
of the first day of production after the modification would be required
to be reported for well sites or centralized production facility. Each
fugitive emissions components affected facility at a well site would
also be required to specify in the annual report what type of site it
is (i.e., a single wellhead only well site, small well site, a multi-
wellhead only well site, or a well site with major production and
processing equipment) and to report information on changes such as the
removal of all major production and processing equipment or well
closure activities during the reporting period.
For fugitive emissions components affected facilities located at
well sites and centralized production facilities, the following
information is required to be included in the annual report for
fugitive emissions monitoring surveys conducted using AVO, OGI, or
Method 21:
Date of the survey,
Monitoring instrument or, if the survey was conducted
using AVO, notation that AVO was used,
Any deviations from key monitoring plan elements or a
statement that there were no deviations from these elements of the
monitoring plan,
Number and type of components for which fugitive emissions
were detected,
Number and type of fugitive emissions components that were
not repaired as required,
Number and type of fugitive emissions components
(including designation as difficult-to-monitor or unsafe-to-monitor, if
applicable) on delay of repair and explanation for each delay of
repair, and
Date of planned shutdown(s) that occurred during the
reporting period if there are any components that have been placed on
delay of repair.
For fugitive emissions components affected facilities located at
well sites and centralized production facilities complying with an
alternative fugitive emissions standard under 40 CFR 60.5399b, the
annual report must identify the alternative standard and include either
the site-specific report or the same information described above. For
fugitive emissions components affected facilities located at well sites
and centralized production facilities complying with an alternative
fugitive emissions standard under 40 CFR 60.5398b, the annual report
must include information specified in 40 CFR 60.5424b.
b. EG OOOOc
i. Designated Facility
These final EG define designated facilities as the collection of
fugitive emissions components at a well site or a centralized
production facility.
ii. Final Presumptive Standards
The presumptive methane standards for existing sources under EG
OOOOc are the same as the methane standards for new sources under NSPS
OOOOb.
2. Fugitive Emissions at Compressor Stations
a. NSPS OOOOb
i. Affected Facility
The standards apply to each fugitive emissions components affected
facility, which is the collection of fugitive emissions components at a
compressor station.
ii. Final Standards
In this final rule, the EPA is finalizing the quarterly OGI (or EPA
Method 21) monitoring requirement for fugitive emissions components
affected facilities located at compressor stations, as proposed in the
December 2022 Supplemental Proposal. Specifically, the EPA is
finalizing the requirement that quarterly surveys be performed using
OGI or EPA Method 21 following the monitoring plan required in the
final regulatory text at 40 CFR 60.5397b. The EPA is also finalizing
the requirement to conduct monthly AVO monitoring at compressor
stations. Any indications of fugitive emissions identified via AVO
would be subject to repair requirements.
The EPA is also finalizing the repair timelines proposed in the
December 2022 Supplemental Proposal. A first attempt at repair of the
source of fugitive emissions identified with AVO must be made within 15
days after the detection, with final repair required within 15 days
after the first attempt. A first attempt at repair of the source of
fugitive emissions identified with OGI or EPA Method 21 must be made
within 30 days after the detection, with final repair required within
30 days after the first attempt. The EPA is also finalizing provisions
to allow a delay of repair if the repair is technically infeasible,
would require a vent blowdown, a compressor station shutdown, a well
shutdown or well shut-in, would be unsafe to repair during operation of
the unit, or would require replacement parts that are unavailable for
certain reasons (see section XI.A.2.b for details); in no case is delay
allowed beyond 2 years.
The final rule for fugitive emissions components affected
facilities located at
[[Page 16873]]
compressor stations includes the requirement that consecutive quarterly
monitoring surveys be conducted at least 60 days apart. As proposed,
the EPA is finalizing the provision that the quarterly OGI monitoring
may be waived when temperatures are below 0 [deg]F for 2 of 3
consecutive calendar months of a quarterly monitoring period.
iii. Recordkeeping and Reporting Requirements
The final rule requires specific recordkeeping and reporting
requirements for each fugitive emissions components affected facility.
The recordkeeping requirements closely follow those in the December
2022 Supplemental Proposal but incorporate the addition of new delay of
repair recordkeeping requirements. In the case of delay of repair due
to parts unavailability, operators must document the date the leak was
added to the delay of repair list, the date the replacement fugitive
emissions component or part thereof was ordered, the anticipated
delivery date, and the actual delivery date.
The reporting requirements are unchanged from the December 2022
Supplemental Proposal. Sources would be required to report the
designation of the type of site (i.e., compressor station) at which the
fugitive emissions components affected facility is located. For
fugitive emissions components affected facilities located at compressor
stations, the following information is required to be included in the
annual report for monthly surveys conducted using AVO, OGI, or Method
21:
Date of the survey,
Monitoring instrument or, if the survey was conducted
using AVO, notation that AVO was used,
Any deviations from key monitoring plan elements or a
statement that there were no deviations from these elements of the
monitoring plan,
Number and type of components for which fugitive emissions
were detected,
Number and type of fugitive emissions components that were
not repaired as required,
Number and type of fugitive emissions components
(including designation as difficult-to-monitor or unsafe-to-monitor, if
applicable) on delay of repair and explanation for each delay of
repair, and
Date of planned shutdown(s) that occurred during the
reporting period if there are any components that have been placed on
delay of repair.
For fugitive emissions components affected facilities located at
compressor stations complying with an alternative fugitive emissions
standard under 40 CFR 60.5399b, the annual report must identify the
alternative standard and include either the site-specific report or the
same information described above. For fugitive emissions components
affected facilities located at compressor stations complying with an
alternative fugitive emissions standard under 40 CFR 60.5398b, the
annual report must include information specified in 40 CFR 60.5424b.
b. EG OOOOc
i. Designated Facility
These final EG define designated facilities as the collection of
fugitive emissions components at a compressor station.
ii. Final Presumptive Standards
The presumptive methane standards for existing sources under EG
OOOOc are the same as the methane standards for new sources under NSPS
OOOOb.
B. Advanced Methane Detection Technology Work Practices
The EPA has included the use of advanced methane detection
technologies in this final rule, in recognition of the rapid and
continued advancement of these technologies and their current use by
owner or operators to supplement their existing ground based OGI
surveys and AVO inspections. Industry has applied many such
technologies, from on-site sensor networks to aerial flyovers using
remote sensing technology that can screen hundreds of sites in a single
deployment, to efficiently detect methane emissions at a variety of
facilities and focus their methane mitigation efforts. In the November
2021 Proposal, we proposed to allow owners and operators to undertake
an approach with bimonthly periodic screening events using these
technologies as an alternative to periodic OGI surveys. In doing so,
the EPA acknowledged that these advanced methane detection technologies
have important advantages, including the ability to detect fugitive
emissions quickly and cost-effectively in a manner that may be less
susceptible to operator error or judgement than traditional leak
detection technologies. Because many of these advanced methane
detection technologies are designed to scan multiple sites at once,
owners and operators have used them as an effective ``screening'' tool
to rapidly identify particular high-emitting sites that warrant
targeted inspection and repair efforts.
The inclusion of these advanced methane detection technologies in
NSPS OOOOb and EG OOOOc received widespread support from stakeholders.
We also received feedback on how the EPA could improve on its proposal
and expand this approach to maximize its efficacy in reducing methane
emissions and its utility as a compliance flexibility for owners and
operators. In the December 2022 Supplemental Proposal, we provided
additional flexibility for advanced methane technologies using the
periodic screening approach by allowing the frequency of the surveys to
vary according to the sensitivity of the technology used, instead of
requiring the same frequency of monitoring for all technologies (i.e.,
periodic screening surveys performed with technologies with lower
detection thresholds would need to be performed less frequently than
screening surveys performed with technologies with higher detection
thresholds). We also introduced a separate alternative work practice
using continuous methane monitoring systems. Finally, we proposed a
streamlined approach to approving new technology that is similar to our
current alternative test method approval process. This approach ensures
that the advanced methane detection technologies used to conduct
periodic screening or continuous monitoring will provide consistent and
reliable information for emission reductions, while also allowing an
easier pathway for owners and operators to adopt the use of the
technologies. We believe that this approach will continue to
incentivize the continued development and improvement of these
technologies, thus leading to even greater emission reductions.
This section summarizes the final provisions in NSPS OOOOb and in
the model rule implementing EG OOOOc for the use of advanced methane
detection technologies in lieu of OGI and/or AVO at well sites,
centralized production facilities, and compressor stations. As
described here, the EPA is finalizing a compliance option that would
allow the use of these advanced methane detection technologies as an
alternative to the use of ground-based OGI surveys, EPA Method 21
(which the final rule continues to allow as an alternative to OGI), and
AVO inspections to identify emissions from the collection of fugitive
emissions components located at well sites, centralized production
facilities, and compressor stations. In response to comments received
on the December 2022 Supplemental Proposal, the EPA has made revisions
and clarifications to the periodic screening approach, continuous
monitoring provisions, and alternative test method process for
[[Page 16874]]
approving advanced methane detection technologies for use in these work
practices.
1. Periodic Screening
In this final rulemaking, the EPA is expanding the proposed
alternative periodic screening approach to provide more flexibility in
selection of appropriate advanced methane detection technology and to
account for the spatial resolution of these technologies. The EPA has
also re-evaluated the equivalency modeling from the December 2022
Supplemental Proposal used to develop the screening frequency matrix
and is finalizing revisions to these tables to account for uncertainty
in the models as discussed in the revised Supplemental TSD Fugitive
Emissions Abatement Simulation Toolkit (FEAST) Memo.\182\ The updated
periodic screening frequency matrices are specified in tables 3 and 4
of the final NSPS OOOOb and the model rule implementing the final EG
OOOOc. The EPA is also finalizing an interim periodic screening option
that will expire on March 9, 2026. See section XI.B.1 of this preamble
for more information on this interim periodic screening matrix.
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\182\ See Memorandum in EPA-HQ-OAR-2021-0317.
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For periodic screening using advanced methane detection technology,
the final rules provide greater flexibility by allowing the owner or
operator to utilize multiple detection technologies in combination,
instead of requiring the owner or operator to choose one technology.
This approach will allow end-users to optimize their periodic screening
program by choosing the most suitable technology based on time of year
and availability of technology providers. The periodic screening
frequency will be based on the technology with the highest aggregate
detection threshold that the owner or operator lists as a technology
they plan to use in their monitoring plan (e.g., if you use methods
with aggregate detection thresholds of 15 kg/hr, your periodic
screenings must be conducted monthly). The final rule also allows an
owner or operator to replace any periodic screening survey with an OGI
survey.
This final rulemaking will require owners and operators to develop
a monitoring plan, which can be site-specific or cover multiple sites.
The monitoring plan must contain the following information at a
minimum, consistent with the December 2022 Supplemental Proposal:
Identification of each site, including latitude and
longitude;
Identification of the alternative test methods(s) used
(i.e., advanced methane detection technology) and required frequency;
Contact information of the entities performing the
screening;
Procedures for conducting OGI surveys;
Procedures for identifying and repairing fugitive
emissions components, covers, and closed vents systems when emissions
are detected; and
Procedures for verifying repairs of fugitive emissions
components, covers, and closed vents system.
The final rulemaking finalizes the proposed timeframe in the
December 2022 Supplemental Proposal that an owner or operator must
initiate periodic screenings using advanced methane detection
technology, within 90 days after startup or modification of a fugitive
emissions components affected facility and storage vessel affected
facility at new, modified, or existing well sites, centralized
production facilities, and/or compressor stations, as well as
timeframes for initiating periodic screenings if an owner or operator
opts to switch to periodic screenings at a later time (i.e., the owner
or operator was originally conducting fugitive emissions surveys with
OGI or EPA Method 21). The final rule also sets timeframes for
conducting annual OGI surveys, if an owner or operator is required to
do so based on the periodic screening matrix.
The final rulemaking finalizes the requirement in the December 2022
Supplemental Proposal that owners and operators must receive the data
from a periodic screening event within 5 calendar days. If the
screening event indicates a confirmed detection, the owner or operator
must conduct follow-up monitoring. In the final rule, we are allowing a
more targeted follow-up survey, dependent on the spatial resolution of
the advanced methane detection technology used during the periodic
screening event. The final rulemaking includes three different
classifications for spatial resolution: facility-level, which must be
able to identify emissions within the boundary of a well site,
centralized production facility, or compressor station; area-level,
which must be able to identify emissions within a radius of 2 meters of
the emission source; and component-level, which must be able to
identify emissions within a radius of 0.5 meters of the emission
source. The follow-up monitoring that must be conducted for a confirmed
detection during a periodic screening event using a technology with
facility-level spatial resolution includes:
A monitoring survey of all the fugitive emissions
components in an affected facility using either OGI or EPA Method 21;
Inspection of all covers and closed vent systems of the
affected facility with either OGI or EPA Method 21; and
Visual inspection of all closed vent systems and covers to
identify if there are any defects.
The follow-up monitoring that must be conducted for a confirmed
detection during a periodic screening event using a technology with
area-level spatial resolution includes:
A monitoring survey of all the fugitive emissions
components located within a 4-meter radius of the location of the
confirmed detection using either OGI or EPA Method 21; and
If the confirmed detection occurred in a portion of a site
with a storage vessel or closed vent system, inspection of all covers
and closed vent systems that are connected to all storage vessels and
closed vent systems that are within a 2-meter radius of the confirmed
detection location (i.e., you must inspect the whole system that is
connected to the portion of the system, not just the portion of the
system that falls within the radius of the detected event). Inspection
must be conducted using either OGI or EPA Method 21, as well as
visually to identify defects.
The follow-up monitoring that must be conducted for a confirmed
detection during a periodic screening event using a technology with
component-level spatial resolution includes:
A monitoring survey of all the fugitive emissions
components located within a 1-meter radius of the location of the
confirmed detection using either OGI or EPA Method 21; and
If the confirmed detection occurred in a portion of a site
with a storage vessel or closed vent system, inspection of all covers
and closed vent systems that are connected to all storage vessels and
closed vent systems that are within a 0.5-meter radius of the confirmed
detection location (i.e., you must inspect the whole system that is
connected to the portion of the system, not just the portion of the
system that falls within the radius of the detected event). Inspection
must be conducted, as well as visually to identify defects.
As proposed, the final rulemaking requires that the owner or
operator follow the repair requirements and timelines in the December
2022 Supplemental Proposal for fugitive emissions components where
emissions are detected from fugitive components, and the repair
requirements for covers
[[Page 16875]]
and closed vent systems (CVS) if emissions are detected during the
follow-up monitoring survey. We are also finalizing as proposed the
requirement to conduct an investigative analysis when the source of a
confirmed detection is determined to be a control device subject to the
rule or an emission from or defect from a cover or closed vent system
associated with an affected facility, although we have refined the
requirements. These requirements include:
Repair all fugitive emissions components, covers, and
closed vent systems within 30 days after receiving the periodic
screening data (except where delay of repair is allowed).
Initiate an investigative analysis within 5 days if an
emission or defect in a closed vent system or cover is determined to be
the cause of the emissions.
Initiate an investigative analysis within 24 hours of
receiving the monitoring survey and inspection results if a failed
control device is determined to be the cause of the emissions.
Investigative analyses must be used to determine the
underlying primary cause and other contributing causes to the emissions
event. Owners and operators must determine the actions needed to bring
the control device into compliance; how to prevent future failures of
the control device from the same underlying cause(s); and updates are
necessary to the engineering analysis for the cover or closed vent
system to prevent future emissions from the cover and closed vent
system.
2. Continuous Monitoring Screening
In this final rulemaking, the EPA is finalizing the continuing
monitoring approach and associated work practice in the December 2022
Supplemental Proposed Rule with some changes to better account for
background methane concentrations and to better incorporate additional
types of measurement systems. The EPA has reexamined the proposed
detection threshold for these systems and has adjusted that threshold
in the final rule to better account for background methane
concentrations.
The final rule includes defined requirements for operating
continuous monitoring systems, including using advanced methane
monitoring technology approved by the EPA for this purpose. This system
must be set-up in a manner to generate a valid methane mass emission
rate (or equivalent) once at least every twelve-hour block, have an
operation downtime of less than 10 percent, and have checks in place to
monitor the health of the system. We have revised the proposed
sensitivity requirements to allow systems with detection thresholds of
0.40 kg/hr of methane or lower and, are requiring systems to transmit
data at least once every 24 hours. The final rule maintains the
timeframe in the December 2022 Supplemental Proposal for when the owner
or operator must initiate continuous monitoring using advanced methane
detection technology (i.e., within 120 days after startup of a fugitive
emissions components affected facility and storage vessel affected
facility at new, modified, and existing well sites, centralized
production facilities, and/or compressor stations), as well as
timeframes for initiating continuous monitoring if an owner or operator
opts to switch to periodic screenings at a later time (i.e., the owner
or operator was originally conducting fugitive emissions surveys with
OGI or EPA Method 21).
In the final rulemaking, we have revised the ``action-levels'' in
the December 2022 Supplemental Proposal to account for the potential
for background methane emission levels at many of these sites. An
action-level is the time weighted average that triggers an
investigative analysis to identify the cause(s) of the exceedance. For
affected facilities located at wellhead only well sites, these
``action-levels'' are as follows:
Rolling 90-day average of 1.2 kg/hr of methane over the
site-specific baseline.
Rolling 7-day average of 15 kg/hr of methane over site-
specific baseline.
For affected facilities located at well sites with major production
and processing equipment, small well sites, centralized production
facilities, and compressor stations, the action levels are as follows:
Rolling 90-day average of 1.6 kg/hr of methane over the
site-specific baseline.
Rolling 7-day average of 21 kg/hr of methane over the
site-specific baseline.
The final rule includes a new and defined set of criteria for the
timeframe and site conditions under which to establish the site-
specific baseline emissions since the December 2022 Supplemental
Proposal, finalizes as proposed how to calculate emissions after the
baseline has been established, and has refined the proposed actions the
owner or operator must take when an ``action-level'' is exceeded. Prior
to establishing the site-specific baseline, the owner or operator must
perform inspections of the fugitive emissions components, any covers
and closed vent systems, and control devices to ensure the site is leak
free and in compliance with the requirements in NSPS OOOOb and/or the
applicable state plan implementing EG OOOOc. The owner or operator must
then record the site-level emissions from the continuous monitoring
system for 30 days and determine the mean emission rate, less any time
periods when maintenance activities were conducted.
The final rule has changed the requirements in the December 2022
Supplemental Proposal for how to calculate the 7-day and 90-day rolling
average to account for the site-specific baseline and has maintained
the intent of required follow-up activities when exceedances of the
action-level have occurred. We have also changed the nomenclature of
the follow-up activities from ``root cause analysis'' to
``investigative analysis'' and from ``corrective action'' to ``mass
emission rate reduction plan'' to eliminate confusion caused by the
terminology we used in the December 2022 Supplemental Proposal. We have
also more clearly specified the requirements for these activities. The
requirements for an investigative analysis are as follows:
The investigative analysis must be initiated within 5 days
after an exceedance of an action-level to determine the underlying
primary and contributing cause(s).
When the 7-day action-level is exceeded, within 5 days
after the exceedance the investigative analysis must be completed and
initial steps must be taken to reduce the mass emission rate.
When the 90-day action-level is exceeded, within 30 days
after the exceedance the investigative analysis must be completed and
initial steps must be taken to reduce the mass emission rate.
An owner or operator must develop a mass emission rate reduction
plan when any of the following conditions have been met:
For an exceedance of the 90-day action-level, 30-day
average mass emission rate for the 30 days following the completion of
the investigative analysis and initial steps to reduce the mass
emission rate is not below the applicable 90-day action-level.
For an exceedance of the 7-day action-level, the mass
emission rate for the 24-hour period after the completion of the
investigative analysis and initial steps to reduce the mass emission
rate is not below the applicable 7-day action-level.
The actions needed to reduce the emission rate below the
applicable action-level will take more than 30 days to implement.
[[Page 16876]]
3. Alternative Test Method for Methane Detection Technology
In this final rule, the EPA has strengthened the alternative test
method approval process for advanced methane detection technology used
in periodic screening and continuous monitoring. The EPA has further
clarified the Administrator authority in the approval process, the
criteria for who may submit requests for approval, and the requirements
for what information must be submitted by those entities seeking
approval.
This final rule specifies a process for applying and obtaining the
EPA's approval for the use of an advanced methane detection technology
in lieu of the required monitoring methods in the rule by submitting
the test method for the alternative technology. However, instead of
relying on existing provisions for alternative test methods 40 CFR
60.8(b), we are in the final rule citing a new alternative test method
provision in 40 CFR 60.5398b(d). This provision incorporates specific
criteria for the review, evaluation, and potential use of advanced
methane detection technology for use in periodic screening, continuous
monitoring, and/or super-emitter detection.
This final rule maintains the procedures in the December 2022
Supplemental Proposal for submitting an alternative test method for
methane detection technology request. These requests must be submitted
to the Leader, Measurement Technology Group along with any supporting
data to the methane detection portal at (www.epa.gov/emc/oil-and-gas-alternative-test-methods). Confidential Business Information (CBI) must
not be submitted through this portal; detailed instructions for
submitting information for which an entity submits a claim of CBI are
provided in 40 CFR 60.5398b(d)(1). The Administrator will complete an
initial completeness review of submissions within 90 days. An approval
or disapproval will be issued in writing within 270 days after
receiving a request. Submission approvals may be considered on a site-
specific basis or more broadly applicable, depending on the technology
and the information provided in the request.
The December 2022 Supplemental Proposal included limitations on
which entities could submit an alternative test method request. The
final rule retains these provisions while also providing improvements
to allow for proprietary advanced methane measurement technology
internally developed by owners and operators. Any entity that meets the
following specifications may submit an alternative test method request:
The entity must be an individual or organization located
in or that has representation in the United States.
The entity must be an owner or operator of an affected
facility under NSPS OOOOb or EG OOOOc.
If the entity is the not the owner or operator of an
affected facility, the entity must directly represent the provider of
the candidate measurement system using advanced methane detection
technology and the measurement system must have been applied to
measurements and monitoring in the oil and gas sector (domestically or
internationally).
The candidate measurement system must have been sold,
leased, or licensed, or offered for sale, lease, or license to the
general public or developed by an owner or operator for internal use
and/or use by external partners.
The final rule also expands upon the information you are required
to provide to the Administrator when submitting a request to use an
alternative test method for advanced methane detection technology.
These expanded requirements represent the minimum amount of material
required by the EPA to completely understand the functionality of
candidate measurement technology systems, how these systems are applied
to generate a methane mass emission rate (kg/hr) or equivalent emission
rate, data management, detection threshold, and spatial resolution.
The final rule requires an entity to provide the Administrator
contact information for the requester, the desired applicability of the
technology, and a description of the candidate measurement technology
system, including:
A description of the scientific theory and appropriate
references outlining the underlying technology;
A description of the physical instrument;
Type of measurement and desired application (e.g.,
airborne, in-situ); and
Potential limitations of the candidate measurement system,
including application limitations.
The request must also include information on how the system
converts results to a mass emission rate or equivalent. This
information must include the following:
Workflow and description covering all steps and processes
from measurement technology signal output to final, validated mass
emission rate (i.e., kg/hr) or equivalent.
Description of how any meteorological data are used,
including how they are collected and/or sourced.
Identification of any model(s) used, including how inputs
are determined or derived.
All calculations used, including the defined variables for
any calculations.
A-priori methods and datasets used.
Explanation of any algorithms/machine learning procedures
used in the data processing, if applicable.
The request must also include a description of how data collected
and generated by the system are collected, maintained, and stored; how
these data streams are processed and manipulated, including how the
resultant data processing is documented; and a description of which
data streams are provided to the end-user of the data and how that
information is delivered or supplied.
The EPA has further refined the supporting information that must be
used to verify detection thresholds and information on how the
candidate measurement system must be applied to ensure the detection
thresholds are maintained during monitoring events. We have also
revised the detection threshold to an average aggregate detection
threshold, which is defined as the average of all site-level detection
thresholds from a single deployment (e.g., a singular flight that
surveys multiple well sites, centralized production facility, and/or
compressor stations). The information provided in the request must
include published reports produced by either the submitting entity or
an outside entity evaluating the technology, standard operating
procedures, alternative testing procedure(s) (preferably in the format
described in Guideline Document 45),\183\ and documents provided to
end-users of the data.
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\183\ Available at https://www.epa.gov/sites/default/files/2020-08/documents/gd-045.pdf.
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The final rule includes a new requirement for entities to verify
the spatial resolution of the candidate measurement system. The
supporting information verifying the spatial resolution must be in the
form of published report (e.g., scientific papers) produced by either
the submitting entity or an outside entity evaluating the submitted
measurement technology that has been independently evaluated.
C. Super Emitter Program
This section presents a summary of the final standards for the
Super Emitter Program. As described in section IV.C of the December
2022 Supplemental Proposal preamble (87 FR 74722,
[[Page 16877]]
December 6, 2022), the EPA proposed the Super Emitter Program to ensure
that this rulemaking comprehensively addresses the widespread problem
of abnormally large emissions events known as super-emitters. The EPA
is including the Super Emitter Program in this final rulemaking,
previously proposed as the Super Emitter Response Program in the
December 2022 Supplemental Proposal. The EPA has developed this program
in response to recent studies, which indicate that a small portion of
sources contribute almost 50 percent of the methane emissions in the
oil and gas sector, and on a global scale, the largest of these
emissions sources may represent as much as 12 percent of global methane
emissions from oil and gas production. For purposes of this rule, a
super-emitter event is one that has a quantified emission rate of 100
kg/hr of methane or greater.
As described here, this program is designed to provide a
transparent, reliable, and efficient mechanism by which the EPA will
provide owners and operators with timely notifications of super-emitter
emissions data collected by the EPA-certified third parties using the
EPA-approved remote sensing technologies (e.g., satellites). Where such
an event is attributable to a source regulated under CAA section 111
(NSPS OOOO, OOOOa, or OOOOb, or a state or Federal plan implementing EG
OOOOc), the responsible owner or operator will take action in response
to such notifications in accordance with the applicable regulation.
The EPA anticipates that the NSPS and presumptive standards for
existing sources that are included in this final rulemaking will reduce
many sources of super-emitters. However, these events sometimes arise
from planned maintenance, other routine operations, and are also
frequently attributable to major malfunctions or improperly operating
control devices. These events are unpredictable and can occur in
between routine inspections and/or fugitive emissions monitoring
surveys. Moreover, these events are sufficiently large to result in
significant emissions of the harmful air pollutants regulated under
this rule in a short span of time. By leveraging data collected by the
EPA-approved third parties using the EPA-approved methods to identify
such events and providing a mechanism for the EPA to promptly notify
owners and operators of such events for appropriate follow-up action,
the Super Emitter Program serves as both a complement and a backstop to
the other requirements of this rulemaking.
As described in our response to comments, the EPA received several
comments--including from owners and operators of regulated facilities--
supporting the objectives of the Super Emitter Program and the
importance of timely identifying and resolving super-emitter events. In
this final rulemaking, the EPA has also made a number of changes to the
Super Emitter Program in order to provide appropriate oversight by the
EPA, address implementation concerns raised by commenters, and ensure
that the program provides owners and operators with transparent,
reliable, and timely information about super-emitter events.
As described in section IV.C of the December 2022 Supplemental
Proposal preamble (87 FR 74746, December 6, 2022), the EPA proposed a
Super Emitter Program as a backstop to address large methane super-
emitters from this sector. This program is designed for the EPA to
receive super-emitter emission data collected by the EPA-certified
third parties using the EPA-approved remote sensing technologies (e.g.,
satellites) in a timely manner. In response to comments objecting to or
otherwise expressing concerns with requiring owners and operators to
respond directly to third-party notifications of super-emitter events,
the EPA has revised the program in the final rulemaking such that it is
the EPA, and not third parties, that will notify an identified owner or
operator after reviewing third-party notifications of the presence of a
super-emitter event at or near its oil and gas facility (e.g., a
specific well site, centralized production facility, gas processing
plant, or compressor station), requiring the owner or operator to
investigate and report the results to the EPA. Also, in response to
comments, the EPA emphasizes that certified third parties will only be
authorized to use remote sensing technologies such as satellites or
aerial surveys--i.e., this program does not authorize third parties to
enter well sites or other oil and gas facilities, and it does not allow
for the use of technologies such as OGI that would require close access
to such facilities.
1. Statutory Authority
The Super Emitter Program finalized in this rule is based on the
EPA's authority under CAA section 114(a) to require ``any person who
owns or operates any emission source'' (except mobile sources) \184\ to
provide information necessary for purposes of carrying out the CAA and
its authority to regulate sources under CAA section 111. In the 2022
Supplemental Proposal, the EPA proposed two separate legal frameworks
for the Super Emitter Program. 87 FR 74752. The final Super Emitter
Program is based on the second legal framework. Under this framework,
the EPA's authority to require sources (regardless of whether those
sources are regulated under CAA section 111) to investigate potential
sources of super-emitter events and report to EPA is CAA section 114.
The EPA's authority to require regulated sources to repair or otherwise
address the cause of the super-emitter event is CAA section 111. In
particular, for sources regulated under CAA section 111, the Super
Emitter Program will serve as: (1) an additional work practice standard
under NSPS OOOOb (and presumptive standard under EG OOOOc) for fugitive
emissions at well sites, centralized production facilities and
compressor stations, and as (2) an additional compliance assurance
measure for other NSPS OOOOb affected facilities, NSPS OOOO and OOOOa
affected facilities, and designated facilities under EG OOOOc.
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\184\ The EPA has similar information collection authority with
respect to mobile sources under CAA section 208.
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a. Authority To Require Investigation and Reporting for all Sources
The EPA's authority to require all sources, regardless of whether
they are regulated under CAA section 111, to investigate potential
super-emitter events and report back to the EPA stems from the EPA's
broad authority under CAA section 114(a) to require, among other
things, monitoring, reporting, and recordkeeping from owners and
operators of stationary sources. CAA section 114(a)(1) gives the EPA
broad authority to ``require any person . . . to (A) establish and
maintain such records; (B) make such reports; (C) install, use and
maintain such monitoring equipment, and use such audit procedures, or
methods; . . . and (G) provide such other information as the
administrator may reasonably require . . . .'' The EPA can impose such
obligations on ``any person who owns or operates any emission source,''
whether or not the emission source is regulated under the CAA, ``[f]or
the purpose of assisting in the development of any implementation plan
under . . . section 7411(d) of this title, any standard of performance
under section 7411 of this title,'' ``determining whether any person is
in violation of any such standard or any requirement of such plan,'' or
``carrying out any provision of this chapter.'' CAA section 111(b)
requires that the EPA review and, if appropriate, revise an NSPS at
least every 8 years
[[Page 16878]]
following its promulgation.\185\ The information on super-emitter
events from both regulated and unregulated oil and gas sources can help
inform the EPA on the effectiveness of its current NSPS for this sector
and potential focus in its future review. Therefore, based on the
authority under CAA section 114(a), the Super Emitter Program requires
owners and operators to investigate and report all sources, including
non-NSPS/EG sources, that they suspect may have caused or contributed
to the super-emitter event specified in the EPA notice that they have
received, to ensure that a regulated source is not contributing to the
event, as well as to provide useful information to the EPA in carrying
out its review obligation under CAA section 111(b). The information on
super-emitter events can also help owners and operators prevent or
minimize losing a valuable product (natural gas).
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\185\ As explained earlier in section IV.A of this preamble, CAA
section 111(b)(1)(B) provides the EPA discretion to determine the
pollutants and sources to be regulated. In addition, concurrent with
the 8-year review (and though not a mandatory part of the 8-year
review), the EPA may examine whether to add standards for pollutants
or emission sources not currently regulated for that source
category.
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b. Authority To Require Repair for Regulated Sources: Work Practice
Standards for Fugitive Emissions
Pursuant to CAA section 111, the EPA has incorporated the Super
Emitter Program, in particular the requirement to repair fugitive
emissions components that are sources of super-emitter events, as a
part of the BSER and therefore work practice standards for fugitive
emissions components affected/designated facilities under NSPS OOOOb/EG
OOOOc. As the first part of the fugitive emissions BSER and work
practice standards, discussed in section X.A of this document, the EPA
has established periodic monitoring and repair work practice standards
as the BSER for these fugitive emissions components affected/designated
facilities under NSPS OOOOb and EG OOOOc. Fugitive emissions may
nevertheless occur from these components between the specified periodic
monitoring. Emissions from certain fugitive emissions components can be
significant (as one example, a stuck-open thief hatch) and can remain
undetected until the next scheduled periodic monitoring. Accordingly,
as the second part of the fugitive emissions BSER and work practice
standard for affected/designated facilities under NSPS OOOOb and EG
OOOOc, the EPA is requiring repair of fugitive emissions components
that are the cause of super-emitter events in between routine
monitoring. While the EPA has determined that it is not cost effective
to require more frequent periodic monitoring, where a super-emitter
event (i.e., 100 kg/hr) is caused by fugitive emissions components,
repair to reduce such large emissions is clearly cost effective. To
that end, the Super Emitter Program supplements the periodic monitoring
and repair work practice standards in NSPS OOOOb (and presumptive
standards in EG OOOOc) by requiring repair of fugitive emissions
components affected/designated facilities under these subparts that the
owner or operator has identified as the source of the super-emitter
event through this program.\186\ The owner or operator will conduct
repair in accordance with the same repair requirements as those for
fugitive emissions detected during the periodic monitoring, as
specified in the applicable standard (i.e., NSPS OOOOb or a state plan
implementing EG OOOOc).
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\186\ As explained in the 2022 Supplemental Proposal (87 FR
74753), despite our incorporation of this additional repair
requirement under the Super Emitter Program into the work practice
standards for the fugitive emissions components at well sites,
centralized production facilities and compressor stations, this
repair requirement is nevertheless severable from the periodic
monitoring and repair work practices that we have separately
analyzed and established as the BSER for fugitive emissions at each
of these facilities. In addition, the additional repair requirement
of the Super Emitter Program is severable from the CAA section
114(a)(1) monitoring and reporting aspect of the Program.
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c. Authority To Require Monitoring and Reporting for Regulated Sources:
Compliance Assurance for Other Regulated Sources
For regulated sources that are not fugitive emissions components
affected/designated facilities under NSPS OOOOb/EG OOOOc, the presence
of a super-emitter event suggests that the source may not be in
compliance with the applicable requirements for that source contained
in the EPA's regulations. The compliance assurance aspect of the Super
Emitter Program is based on the EPA's regulations for individual
emissions sources in the NSPS and EG promulgated pursuant to CAA
section 111. NSPS OOOO/OOOOa/OOOOb and the model rule implementing EG
OOOOc all include design and/or operational requirements \187\ and
monitoring, recordkeeping, and reporting requirements \188\ to assure
that standards of performance \189\ are being met. However, as
explained above, super emitter events are unpredictable; they can occur
between routine inspections and release significant emissions in a
short span of time. To address this concern, the Super Emitter Program
provides additional monitoring, reporting and recordkeeping for
affected/designated facilities under NSPS OOOO/OOOOa/OOOOb and EG OOOOc
based on the EPA's authority under CAA section 114(a) to impose such
requirements for purposes of determining whether or not standards under
these subparts are being met. Where a super-emitter event originates
from one of these affected/designated facilities or associated
equipment regulated under NSPS OOOO, OOOOa, OOOOb, or a state or
Federal plan implementing EG OOOOc, the Super Emitter Program serves as
an additional source of monitoring data to inform and alert owners and
operators to check and make sure that the source and associated control
device and equipment are operating as required under the applicable
NSPS or State or Federal plan implementing EG OOOOc. For example, a
super-emitter event may be caused by an open thief hatch on a storage
vessel subject to NSPS OOOOa, which is not permitted except for very
limited circumstances as defined in the rule. In that event, the Super
Emitter Program serves to alert an owner or operator of the need to
close the thief hatch pursuant to the requirements of NSPS OOOOa, but
the Super Emitter Program does not itself impose a requirement to close
the thief hatch. Since there are already requirements in place to bring
emissions down to or below the applicable NSPS standards (and will be
in state or Federal plans implementing EG OOOOc), the Super Emitter
Program does not itself independently require specific actions
[[Page 16879]]
to address emissions from super-emitter events attributed to NSPS or EG
sources; it merely puts owners and operators on notice that action may
be required to bring a source back into compliance with the applicable
emission standards. To clarify this point, the final rule includes
amendments to NSPS OOOO and OOOOa to incorporate relevant compliance
assurance provisions of the Super Emitter Program, specifically the
requirement to investigate and report whether the super-emitter event
was caused by a NSPS OOOO or OOOOa affected facility or associated
equipment.
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\187\ The EPA establishes ``standards of performance'' pursuant
to CAA section 111. CAA section 302(l) defines a ``standard of
performance'' to include not only standards limiting the quantity,
rate, or concentration of emissions, but also requirements
``relating to the operation or maintenance of a source to assure
continuous emission reduction.'' Examples of such compliance
assurance requirements include 40 CFR 60.5411/60.5411a (cover and
closed vent system requirements) and 60.5412/60.5412a (control
device requirements) in NSPS OOOO/OOOOa.
\188\ The EPA has long relied on CAA section 114 to establish
monitoring, recordkeeping, and reporting requirements to implement
and enforce the emissions standards promulgated under CAA section
111 (see, e.g., 36 FR 24876 (December 23, 1971) (NSPS for the
initial five listed source categories, citing both CAA sections 111
and 114 as the statutory authorities). That was the case with the
2012 NSPS OOOO and 2016 NSPS OOOOa, and the EPA has similarly
included such measures in the present rule in NSPS OOOOb and in the
model rule for EG OOOOc.
\189\ These do not include fugitive emissions components
affected/designated facilities under NSPS OOOOb and EG OOOOc, which
the EPA has separately addressed, as discussed above.
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2. Major Elements
The following describes the major elements in the Super Emitter
Program that serve to assure the reliability of the super-emitter data
that the EPA receives under this program. These elements ensure that
the data the EPA receives is meaningful and lead to expeditious and
effective mitigation of super-emitter events by owners and operators,
whether required or voluntarily.
a. Qualifications for Third-Party Notifiers
A third party can be any independent entity, meaning that the third
party does not own or operate the site where a super-emitter is
detected. In this final rulemaking, the EPA is maintaining the
requirements for the qualification of the third-party notifiers in the
December 2022 Supplemental Proposal, including the requirement that
notifiers use remote sensing technologies. These technologies and their
method for operation must be approved under the advanced methane
detection technology program in 40 CFR 60.5398b(d). Third parties are
limited to using remote sensing technologies such as satellites or
aerial surveys and would not be authorized by this program to enter a
site.
b. Third-Party Notifier Certification
In this final rulemaking, the EPA establishes a framework by which
we will certify third-party notifiers from whom the EPA would accept
data from super-emitter events under the Super Emitter Program. The
final rulemaking includes provisions governing how the third-party must
submit a request to be certified, requirements that a third-party must
meet to be certified and/or re-certified, obligations for notifiers to
maintain records of surveys performed to maintain certification, and
procedures for revoking a notifiers certification.
A third-party notifier certification request must be submitted to
the Leader, Measurement Technology Group, 109 T.W. Alexander Drive,
P.O. Box 12055, Research Triangle Park, NC 27711. If your request
contains CBI, you must transmit these data electronically using email
attachments, File Transfer Protocol, or other online file sharing
services.\190\ This request must include general identification for the
entity submitting the request, including the mailing address, physical
address, and contact information for the principal officer and
certifying officials(s). This request must also include the following
information:
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\190\ Please email [email protected] to request a file transfer
link.
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Description of the advanced methane detection technologies
that the third party intends to use, including reference to any
alternative test method approval under 40 CFR 60.5398b(d), and any
agreements with the technology providers.
Curriculum vitae of the certifying official(s) detailing
training for evaluating results of the chosen advanced methane
detection technology.
The entity's standard operating procedure(s) detailing the
procedures and processes used by the entity for data review, including
the accuracy of emissions data and locality data provided by the
technology provider, how the entity will identify the owner or operator
of a site, and procedures for handling potentially erroneous data.
Description of the system for maintaining essential
records.
A Quality Management Plan consistent with the EPA's
Quality Management Plan Standard (Directive No: CIO 2015-S-01.0,
January 17, 2023).
An entity that has received third-party approval must maintain the
following records in order to retain its certification status:
Records for all surveys conducted by or sponsored by the
certified third-party notifier that are the basis for a third-party
super-emitter identification submitted to the EPA.
Records for any notifications provided to the EPA and any
additional data collected supporting the notification not required by
the EPA to be reported.
Records or identification of databases used to identify
owner or operators of sites where super-emitter events reported to the
EPA occurred.
The Administrator will assess the completeness, reasonableness, and
accuracy of the third party's request based on the updated
certification criteria in the final rule. Once certified, the third-
party notifier will receive a unique notifier ID which will be posted
at www.epa.gov/emc-third-party-certifications. If there is any material
change to the information included in the third party's initial
certification request, e.g., a change to the technology that the third
party intends to use or a change to the certifying official(s), the
final rule requires the third party to submit a revised request and be
recertified before implementing those changes.
As proposed, the EPA is finalizing provisions providing for the
revocation of a third party's certification under certain conditions.
In response to comments, the EPA has expanded in the final rule the
circumstances for removing a third-party certification, which are as
follows:
Submitting super-emitter notifications after making
material changes to the third party's procedures for identifying super-
emitters without seeking recertification.
If the Administrator finds that the certified third-party
notifier has persistently submitted data with significant errors.
Having engaged in illegal activity during the assessment
of a super-emitter event (e.g., trespassing).
Upon determination by the Administrator, following
petition from the owner or operator, that the owner or operator has
received from the EPA more than three notices with meaningful and/or
demonstrable errors of a super-emitter event at the same oil and
natural gas facility (e.g., a well site, centralized production
facility, natural gas processing plant, or compressor station), that
were submitted to the EPA by the same third party, and the owner or
operator demonstrates that the claimed super-emitter event did not
occur. The failure of the owner or operator to find the source of the
super-emitter emissions event upon subsequent inspection would not be
proof, by itself, of demonstrable error on the part of the third-party
notifier.
c. Notification of Super-Emitter Events
In the final rules, the EPA has amended the super-emitter
notification process in the December 2022 Supplemental Proposal to now
include a step whereby the EPA will receive and review the super-
emitter data from certified third-party notifiers before triggering any
obligation on the part of the owner or operator. The final rules
require the third-party notifier to submit notifications to the EPA
within 15 calendar days after detection of a super-emitter event to
ensure timely notice and includes standards for the content of the
notification to aid in the EPA's
[[Page 16880]]
review of the data. Third-party notifications must be submitted into
the Super Emitter Program Portal at https://www.epa.gov/super-emitter
and must include the following:
Unique Third-Party Notifier ID.
Date of detection of the super-emitter event.
Location of super-emitter event in latitude and longitude
coordinates.
Owner(s) or operator(s) of an oil and natural gas facility
of any individual well site, centralized production facility, or
compressor station within 50 meters of the latitude and longitude
coordinates of the super-emitter event, if available, and the method
used by the third party to identify the owner or operator.
Identification of the detection technology and reference
to the approval of the technology.
Documentation (e.g., imagery) depicting the detected
super-emitter event and the site from which the super-emitter event was
detected.
Quantified emission rate of the super-emitter event in kg/
hr.
Attestation statement that the information submitted by
the third-party notifier is true and accurate to the best of the
notifier's knowledge.
Upon receiving a third-party notification of super-emitter data
through the Super Emitter Program Portal, the EPA will evaluate the
notifications for completeness and accuracy to a reasonable degree of
certainty. When the EPA determines that a notification has met these
conditions, the EPA shall assign the notification a unique notification
identification number, provide the notification to the owner/operator.
and post the notification, except for the owner/operator attribution,
at www.epa.gov/super-emitter. This approach responds to comments asking
that notice of super-emitter events be provided as quickly as possible,
both to the public and the identified owner/operator, but also that the
owner/operator have an opportunity to respond before the super-emitter
event is publicly attributed to a particular owner/operator. The EPA
shall post owner/operator attributions that have been confirmed through
the responses received; where response submittal deadlines have passed
but no responses have been received, the EPA intends to post owner/
operator attributions that the EPA reasonably believes to be accurate.
d. Identification of a Super-Emitter Event
In the final rules, the owner or operator must initiate an
investigation within 5 days after receiving an EPA notification of a
super-emitter event and report the results to the EPA within 15 days
after receiving such notification. If an owner or operator determines
that they do not own or operate a well site, centralized production
facility, or compressor station within 50 meters from the latitude and
longitude provided in the notification, the owner or operator must
report that to the EPA and the investigation is then complete.
Otherwise, the owner or operator must investigate to determine the
source of the super-emitter event.
As explained earlier in this section X.C, a super-emitter event may
have been emitted from one or more of the following: (1) an affected
facility or associated equipment (e.g., a control device or CVS)
subject to regulation under NSPS OOOO, OOOOa, or OOOOb (``NSPS
sources''); (2) a designated facility or associated equipment subject
to a state or Federal Plan promulgated pursuant to EG OOOOc (``EG
sources''); or (3) an unregulated source (i.e., one that is not (1) or
(2) above). Therefore, the investigation is not limited to NSPS or EG
sources but also includes other sources that the owner or operator may
suspect could be the source of the super-emitter event.
The owner or operator must investigate and report to the EPA the
results of the investigation within 15 days after receiving a
notification from the EPA. The owner and operator must also maintain a
record of these investigations. To provide confidence in the reported
information, the final rule has updated the list of investigations that
the EPA believes will most likely reveal the source of the super-
emitter event. Because the relevant investigations for identifying the
source(s) of the super-emitter event may vary depending on what the
third-party data reveals, the final rules defer to the owner and
operator in deciding the appropriate investigation(s). However, where
there are affected or designated facilities or associated equipment
onsite, the owner and operator may conclude that they are unable to
identify the source of the super-emitter event only after having
conducted the applicable investigation listed in the respective final
rule for each affected or designated facility and associated equipment.
The list of potential actions to identify the potential cause of
super-emitter events may include but are not limited to the following:
Review any maintenance activities (e.g., liquids
unloading) or process activities starting from the date of detection of
the super-emitter event as identified in the notification.
Review all monitoring data from control devices (e.g.,
flares) over the same time period.
Review any fugitive emissions survey performed under a
fugitive emissions monitoring plan over the same time period.
Review data from any continuous alternative technology
systems over the same time period.
Screen the entire well site, centralized production
facility, or compressor station with OGI, EPA Method 21, or an
alternative test method(s).
e. Super-Emitter Event Report
As was proposed, the final rules require that the owner or operator
submit a report to the EPA within 15 days after receiving a Super-
Emitter Event notification through the Super Emitter Program Portal,
including an attestation that the report is complete and accurate. The
report must include the following information:
Notification Report ID
Confirmation that you are the owner or operator of the oil
and gas facility within the immediate area (i.e., 50 meters) of the
latitude and longitude provided in the notification. If you do not own
or operate an oil and gas facility within 50 meters of the of the
latitude and longitude provided in the notification, you are not
required to provide the additional information described below.
General identification for the facility, including
physical address and applicable ID (e.g., EPA ID Number, American
Petroleum Institute (API) Well ID) and the responsible official.
Whether there are affected facilities or associated
equipment subject to NSPS OOOO, OOOOa or OOOOb or designated facilities
or associated equipment subject to a state or Federal plan pursuant EG
OOOOc.
Attestation that investigations were conducted to verify
the presence or the absence of a super-emitter event.
If you were unable to identify the source of the super-
emitter and if there are NSPS OOOO, OOOOa or OOOOb affected facilities
or associated equipment, or designated facilities or associated
equipment subject to a state or Federal plan pursuant EG OOOOc, onsite,
confirmation that you have conducted all investigations listed in the
Super Emitter Program (as specified above in section X.C.2.d) that are
applicable to such affected or designated facilities and associated
equipment.
[[Page 16881]]
If a super-emitter source is identified, what the source
is and whether it is (i) an affected facility or associated equipment
subject to NSPS OOOO, OOOOa, or OOOOb or (ii) a designated facility or
associated equipment subject to a state or Federal plan under EG OOOOc.
If a super-emitter event is found, the date and time the
super-emitter event ended.
Upon receiving this information from the owner or operator, the EPA
will update the notification report with the information provided by
the owner or operator and will make the updated report publicly
available at www.epa.gov/super-emitter. If a super-emitter event
emitted from an NSPS OOOO, OOOOa or OOOOb affected facility or
associated equipment or a designated facility or associated equipment
subject to a state or Federal plan pursuant EG OOOOc, or associated
equipment, is ongoing, you are also required to report to the Super
Emitter Program Portal the following information:
A short narrative on how you intend to end the super-
emitter event, including the targeted date for completion.
Within 5 days after the super-emitter event has ended, the
date and time the super-emitter event ended.
As discussed earlier in this section X.C, CAA 114(a) gives the EPA
broad authority to require that owners and operators investigate and
report all sources that they suspect may have caused or contributed to
the super-emitter event specified in the EPA notice that they have
received under the Super Emitter Program. CAA 114(a) does not require
regulatory text for the EPA to exercise its information gathering
authority under CAA 114(a), and the EPA believes that adequate notice
is provided in this Federal Register document, which clearly sets forth
the required investigations and reporting requirements under the Super
Emitter Program and their applicability to all oil and gas emission
sources, whether or not they are subject to any applicable CAA section
111 standard. Nevertheless, to facilitate the implementation of the
Super Emitter Program, the EPA has codified provisions of the Super
Emitter Program into the regulatory text of the new NSPS OOOOb and, as
appropriate, in the model rule implementing EG OOOOc and amendments to
NSPS OOOO and OOOOa. Specifically, NSPS OOOOb provides the major
framework for the Super Emitter Program, including criteria for
certifying third-party notifiers, criteria for third-party
notifications to the EPA, and provisions governing the EPA's
notification of identified owners and operators.\191\ In addition, NSPS
OOOOb includes regulatory text governing the investigation and
reporting as they relate to NSPS OOOOb affected facilities and
associated equipment. Similarly, the EPA has amended NSPS OOOO and
OOOOa to include super-emitter event investigation and reporting
requirements as they relate to affected facilities and associated
equipment under those NSPS. Such provisions are also included in the
model rule implementing EG OOOOc. In addition, both NSPS OOOOb and the
model rule implementing EG OOOOc includes a requirement to repair
fugitive component(s) that owners and operators have identified as the
source of super-emitter event specified in the EPA notice; as explained
earlier in this section X.C, the standards for fugitive emissions
components affected facilities under NSPS OOOOb (and presumptive
standards under EG OOOOc) include a requirement to repair fugitive
component(s) that owners and operators have identified as the source of
super emitter-event specified in the EPA notice.
---------------------------------------------------------------------------
\191\ Unlike the EPA, the Super Emitter Program imposes no
obligations on States; their obligation under this final rule is to
promulgate a state plan implementing EG OOOOc, as required under CAA
111(d) and EPA's implementing regulation at 40 CFR part 60, subpart
Ba.
---------------------------------------------------------------------------
Further, pursuant to the Paperwork Reduction Act (PRA), the EPA
estimated the reporting burden under the Super Emitter Program when it
issued the December 2022 Supplemental Proposal. The total burden
presented in section XVII.B for NSPS OOOOb of this final preamble
includes the reporting burden for the entire Super Emitter Program,
including reporting pertaining to affected facilities under NSPS OOOO
and NSPS OOOOa and non-NSPS sources. The estimated reporting burden for
the final Super Emitter Program has not changed since the December 2022
Supplemental Proposal and includes the estimated burden of required
activities under the Super Emitter Program such as third-party
certifications and notifications to the EPA and reporting requirements
for identified owners and operators. Both the supplemental proposal and
this final rulemaking have been reviewed by the Office of Management
and Budget (OMB) through the interagency review process. The EPA
envisions that for simplicity, completeness, and transparency, owners
and operators would prefer one comprehensive Super Emitter Program over
the possibility of having to respond to two EPA notices on a super-
emitter event.
D. Process Controllers
Process controllers are automated instruments used for maintaining
a process condition, such as liquid level, pressure, pressure
difference, or temperature. In the oil and gas industry, many process
controllers are powered by pressurized natural gas and emit natural gas
to the atmosphere. However, process controllers may also be powered by
electricity or compressed air, and these types of controllers do not
use or emit natural gas. Natural gas-driven process controllers are a
significant source of methane emissions. For instance, in the 2019
GHGRP, methane emissions from process controllers made up 65 percent of
the total methane emissions from petroleum system onshore production
and 28 percent of the total methane emissions from natural gas systems
onshore production.
In the December 2022 Supplemental Proposal, the EPA proposed a
``zero emissions'' VOC and methane standard in NSPS OOOOb and a ``zero
emissions'' methane presumptive standard in EG OOOOc. This standard can
be achieved by using a process controller that is not powered by
natural gas, by capturing the emissions from the natural gas-driven
controllers and routing them to a process, or by using self-contained
controllers. The proposed rules included an exemption from the zero-
emissions requirement for process controllers in Alaska at locations
where access to electrical power from the power grid is not available.
The proposed requirements for these sources in Alaska were to use lower
emitting natural gas-driven process controllers and to perform
inspections to ensure that they are operating properly. While there are
changes to some compliance aspects in the final rules, such as a
further-out compliance date than proposed with an interim standard for
the NSPS, the zero-emissions standard in NSPS OOOOb and presumptive
standard in EG OOOOc (with the Alaska exemption) are being finalized as
proposed.
1. NSPS OOOOb
a. Affected Facility
The standards apply to the collection of new, modified, and
reconstructed natural gas-driven process controllers at a site (i.e., a
well site, centralized production facility, onshore natural gas
processing plant, or compressor station). Process controllers that are
emergency shutdown devices (ESD) or that are not
[[Page 16882]]
natural gas-driven are not included in the affected facility.
b. Final Standards
The standards that apply differ depending on the location of the
site and whether access to electrical power is available at the site,
which are sites that have commercial line power onsite. For any site
outside of Alaska, the standard for all process controllers is zero
emissions of VOC and GHG (in the form of methane). Zero emissions of
VOC and GHG may be achieved by using process controllers that are not
driven by natural gas (and thus not affected facilities), by routing
natural gas-driven process controller vapors through a closed vent
system to a process, by using self-contained natural gas-driven process
controllers, or by another means that achieves the numerical standard
of zero emissions of GHG (in the form of methane) and VOC. For sites in
Alaska with access to electrical power the standard for all process
controllers at the site is also zero emissions of VOC and GHG. For
sites in Alaska without access to electrical power, owners/operators
must use natural gas-driven process controllers with low natural gas
emission rates. These process controllers include continuous bleed
controllers with an emissions rate (or bleed rate) of less than or
equal to 6 standard cubic feet per hour (scfh) and intermittent vent
controllers, which are process controllers that only emit natural gas
when they actuate, rather than emitting continuously. Intermittent vent
controllers are subject to monitoring requirements explained below.
Further, as an optional alternative, sites in Alaska without access to
electrical power may route emissions from natural gas-driven process
controllers to a control device achieving a 95 percent emissions
reduction. Table 12 summarizes the emissions standards for process
controllers.
Table 12--Summary of Process Controller Emissions Standards
----------------------------------------------------------------------------------------------------------------
Emissions
Site has access to Emissions standard
Location of site electrical power standard compliance
method
------------------------------------------------------------------------------------------------
Outside Alaska................ Yes or No................... Zero GHG and VOC Use process
emissions. controllers not
driven by
natural gas
Or
Route natural
gas-driven
process
controller
emissions
through a
closed vent
system to a
process
Or
Use self-
contained
natural gas-
driven process
controllers
Or
Other means to
achieve zero-
emissions
standard.
In Alaska..................... Yes......................... Zero GHG and VOC Use process
emissions. controllers not
driven by
natural gas
Or
Route natural
gas-driven
process
controller
emissions
through a
closed vent
system to a
process
Or
Use self-
contained
natural gas-
driven process
controllers
Or
Other means to
achieve zero-
emissions
standard.
In Alaska..................... No.......................... 95 percent Route natural
emissions gas-driven
control. process
Or.............. controller
Emissions emissions
achieved by use through a
of low- closed vent
emitting system to a
controllers. control device
that reduces
emissions by
>=95 percent
Or
Use low-bleed or
intermittent
vent natural
gas-driven
process
controllers
with monitoring
for
intermittent
process
controllers.
----------------------------------------------------------------------------------------------------------------
Based on comments expressing concerns about new sources' ability to
obtain the equipment necessary to demonstrate compliance with the final
standard of zero emissions immediately upon the effective date of the
final rule, the EPA is finalizing a NSPS compliance deadline for
process controllers that allows for up to 1 year from the effective
date of the final rule. This means that new sources will have up to 1
year to come into full compliance with the final standard of zero
emissions. Until that final date of compliance, owners and operators
must demonstrate compliance with an interim standard which mirrors the
requirements for sites in Alaska that do not have access to electrical
power. This topic is explained in detail in section XI.D.4 below.
c. Monitoring Requirements
Monitoring is required for most natural gas-driven process
controllers. For self-contained process controllers, initial and
periodic monitoring is required to demonstrate that there are no
identifiable emissions from the process controller. For intermittent
process controllers (allowed at sites in Alaska without access to
electrical power), initial and periodic monitoring is required to
demonstrate that there are no identifiable emissions from the process
controller when the process controller is idle. For process controllers
that have emissions routed through a closed vent system to a process or
to a
[[Page 16883]]
control device, initial and periodic monitoring is required to
demonstrate that there are no identifiable emissions from the closed
vent system. In addition to the closed vent system monitoring
requirements, process controllers that have emissions routed through a
closed vent system to a control device (allowed at sites in Alaska
without access to electrical power) must perform the monitoring
specified in 40 CFR 60.5417b for the particular type of control device
that is used. As further discussed in sections X.H and XI.H of this
document, each control device must have a continuous parameter system
installed and a continuous recording device for the monitoring results.
Enclosed combustion devices and flares also must have either periodic
visible emissions inspections or use a surveillance camera system to
monitor for visible emissions. A summary of the required monitoring for
natural gas-driven process controllers is shown in table 13.
Table 13--Summary of Process Controller Inspection and Monitoring
Requirements
------------------------------------------------------------------------
Monitoring
Equipment type Monitoring requirement frequency
------------------------------------------------------------------------
Natural gas-driven self- Use OGI or EPA Method Initially and
contained controllers. 21 to demonstrate no quarterly.
identifiable
emissions from the
process controller.
Natural gas-driven Use OGI or EPA Method Initially and
intermittent vent controllers 21 to demonstrate no quarterly.
(Alaska-only sites without identifiable
electrical power). emissions occur
during idle periods.
Closed vent system on a Use OGI or EPA Method Initially and
natural gas-driven process 21 to demonstrate no quarterly..
controller. identifiable
emissions from the
closed vent system.
AVO monitoring........ Initially and bi-
monthly.
Inspection for defects Annually.
that could result in
air emissions.
Control device for a natural Parameter monitoring.. Continuously
gas-driven process controller Visible emissions Monthly.
(Alaska-only sites without inspections for
electrical power). enclosed combustion
devices and flares.
Or
Surveillance camera Continuously.
monitoring.
------------------------------------------------------------------------
d. Recordkeeping and Reporting Requirements
Owners or operators of a process controller affected facility are
required to submit information about the affected process controller
facility in annual reports. The information required for the first
annual report includes an identification of each natural gas-driven
controller included in the process controller affected facility and an
identification of the emissions standards compliance method that will
be used for the affected facility. The initial annual report must also
include a demonstration that a natural gas-driven process controller
with a bleed rate greater than 6 scfh is required if such a process
controller is used in Alaska at a site without access to electricity
(the standard allows a process controller with a bleed rate greater
than 6 scfh in certain circumstances), and also a certification that
the closed vent system is adequately designed if a closed vent system
is used for a process controller affected facility. After the initial
annual report, this information about the affected facility is only
required to be submitted in the annual report if there are changes to
the previously submitted information. Each annual report must include
the dates and results of inspections conducted for self-contained and
intermittent vent natural gas-driven process controllers, inspections
of closed vent systems (for sites routing emissions to a process or
sites in Alaska routing emissions to a control device), monitoring and
inspections of control devices (for sites in Alaska using a control
device to reduce emissions by 95 percent), and information for any
deviations from the process controller emissions standards that
occurred during the reporting period.
Owners and operators are also required to keep records of the
information submitted in the annual reports regarding the process
controller affected facility, and if applicable, the records required
for monitoring and inspections of closed vent systems, control devices,
self-contained process controllers, and intermittent vent process
controllers. Records of each deviation must also be kept.
2. EG OOOOc
a. Designated Facility
The final EG define designated facilities for purposes of process
controllers as the collection of existing natural gas-driven process
controllers at a well site, centralized production facility, onshore
natural gas processing plant, or compressor station. Process
controllers that are emergency safety devices (ESD) or that are not
natural gas-driven are not included in the designated facility.
b. Final Presumptive Standards
The presumptive methane standards for existing sources under EG
OOOOc are the same as the final methane standards for new sources under
NSPS OOOOb.
c. Monitoring Requirements
The monitoring requirements in EG OOOOc are the same as those for
NSPS OOOOb.
d. Recordkeeping and Reporting Requirements
The recordkeeping and reporting requirements in EG OOOOc are the
same as those for NSPS OOOOb.
E. Pumps
In the oil and natural gas industry, pumps are used for many
purposes, including chemical injection, hot glycol circulation for heat
tracing/freeze protection, and glycol circulation in dehydrators. These
pumps are generally either piston pumps or diaphragm pumps that can be
powered by compressed air, compressed natural gas, or electricity. Of
these pumps, those that are pneumatic units driven by natural gas emit
methane and VOC to the atmosphere as part of their normal operation. In
many situations across all segments of the oil and gas industry,
natural gas-driven pneumatic pumps are used where electricity is not
readily available.
In the December 2022 Supplemental Proposal, the proposed standard
in NSPS OOOOb and presumptive standard in EG OOOOc was zero emissions
of methane and VOC. The proposed standards may be achieved by the use
of pumps not powered by natural gas. In that situation, the pump would
not be an affected or designated facility because it would not be
powered by natural gas. For sites in the
[[Page 16884]]
production or transmission and storage segment of the industry without
access to electricity from the power grid, the proposed standards in
the December 2022 Supplemental Proposal included a complex hierarchical
structure that allowed the use of natural gas-driven pumps in certain
situations based on the technical feasibility of pump control measures
and the existence of situations that would allow the emissions to be
routed to a process or to a control device already on a site. In the
final rule, the complex hierarchical structure has been removed, and
final NSPS OOOOb and EG OOOOc (presumptive standard) specify zero
emissions for all pumps except those at sites without access to
electricity with fewer than three natural gas-driven diaphragm pumps.
For those sites, the final standards in NSPS OOOOb and presumptive
standards in EG OOOOc are based on whether an existing situation exists
that allows the emissions to be routed to a process or to a control
device already on site.
1. NSPS OOOOb
a. Affected Facility
The pump standards apply to the collection of new, modified, and
reconstructed natural gas-driven pumps at a well site, centralized
production facility, onshore natural gas processing plant, or
compressor station. Pumps that are in operation less than 90 days per
calendar year or that are not natural gas-driven are not included in
the affected facility.
b. Final Standards
The standards that apply differ depending on the number of natural
gas-driven diaphragm pumps at the site (i.e., well site, centralized
production facility, onshore natural gas processing plant, or
compressor station) and whether the site has access to electrical grid
power. For any site with access to electrical power and for sites
without access to electrical power that have three or more natural gas-
driven diaphragm pumps, the standard for all pumps in the affected
facility is zero emissions of VOC and GHG (in the form of methane).
Zero emissions of VOC and GHG may be achieved by either using pumps
that are not driven by natural gas (and are therefore not affected
facilities), by routing natural gas-driven pump vapors through a closed
vent system to a process, or by other means that achieves the standard
of zero emissions. For sites without access to electrical power that
have fewer than three diaphragm pumps (two or one), the standards
require that GHG and VOC emissions from all natural gas-driven pumps in
the affected facility be routed to a process if a vapor recovery unit
(VRU) is onsite. If a VRU is not onsite, emissions must be reduced by
95 percent if a control device with at least this emissions reduction
capability is already available onsite, or be reduced by less than 95
percent if a control device is onsite but is not capable of reducing
GHG and VOC emissions by 95 percent or more. Table 14 summarizes the
emissions standards for pumps.
Table 14--Summary of Pump Emissions Standards
----------------------------------------------------------------------------------------------------------------
Number of natural gas-
Facility site electrical access to driven diaphragm pumps
power? at pump affected Standard Compliance method
facility site
----------------------------------------------------------------------------------------------------------------
Yes.................................. Any.................... Zero GHG and VOC Use pumps not driven by
emissions. natural gas
Or
Route pump emissions
through a closed vent
system to a process
Or
Other means to achieve
zero-emissions
standard.
No................................... Has >=3 diaphragm pumps Zero GHG and VOC Use pumps not driven by
emissions. natural gas
Or
Route pump emissions
through a closed vent
system to a process
Or
Other means to achieve
zero-emissions
standard.
No................................... Has <3 diaphragm pumps. Control emissions if Route pump emissions
VRU or control device through a closed vent
is already present at system to a process if
site and can accept a VRU is onsite; if no
emissions from pumps. VRU onsite, route
emissions to a control
device that reduces
emissions by >=95
percent; if no control
device capable of
reducing emission by
>=95 percent is
present then still
route to control
device if present.
----------------------------------------------------------------------------------------------------------------
Just as with process controllers, and based on comments expressing
concerns about new sources' ability to obtain the equipment necessary
to demonstrate compliance with the final standard of zero emissions
immediately upon the effective date of the final rule, the EPA is
finalizing a NSPS compliance deadline for pumps that allows for up to 1
year from the effective date of the final rule. This means that new
sources will have up to 1 year to come into full compliance with the
final standard of zero emissions. Until that final date of compliance,
owners/operators must demonstrate compliance with an interim standard
which mirrors the requirements for pumps at sites without access to
grid electricity that have fewer than three diaphragm pumps found at 40
CFR 60.5393b(b). This topic is explained in detail in section XI.E.2
below.
c. Monitoring Requirements
Monitoring is required for pump affected facilities that have
emissions routed to a process or control device. For these affected
facilities, initial and periodic monitoring is required to demonstrate
that there are no identifiable emissions from the closed vent system.
In addition to the closed vent system monitoring requirements, pumps
that have emissions routed through a closed vent system to a control
device reducing emissions by 95 percent or more must perform the
monitoring specified in 40 CFR 60.5417b for the particular type of
control device that is used. As further discussed in sections X.H and
XI.H of this document, each control device must have a continuous
parameter system installed and a continuous recording device for the
monitoring results.
[[Page 16885]]
Enclosed combustion devices and flares also must have either periodic
visible emissions inspections or use a surveillance camera system to
monitor for visible emissions. A summary of the required monitoring for
pump affected facilities is shown in table 15.
Table 15--Summary of Pump Inspection and Monitoring Requirements
------------------------------------------------------------------------
Monitoring Monitoring
Equipment type requirement frequency
------------------------------------------------------------------------
Closed vent system on a natural Use OGI or EPA Initially and
gas-driven pump. Method 21 to quarterly.
demonstrate no
identifiable
emissions from
the closed vent
system.
AVO monitoring.... Initially and bi-
monthly.
Inspection for Annually.
defects that
could result in
air emissions.
Control device achieving 95 Control device Continuously.
percent emissions reduction for parameter
a natural gas-driven pump. monitoring..
Visible emissions Monthly.
inspections for
enclosed
combustion
devices and
flares.
Or
Surveillance Continuously.
camera monitoring.
------------------------------------------------------------------------
d. Recordkeeping and Reporting Requirements
Owners or operators of a pump affected facility are required to
submit information about the affected pump facility in annual reports
after becoming subject to NSPS OOOOb. The information required for the
first annual report includes an identification of each natural gas-
driven pump included in the pump affected facility and an
identification of the emissions standards compliance method that will
be used for the affected facility. The initial annual report must also
include a certification that the closed vent system is adequately
designed if a closed vent system is used for the pump affected
facility. If complying by using a control device that achieves less
than 95 percent emissions control or if no control device will be used,
owners or operators must include a certification that no control device
is on site that is capable of achieving a 95 percent emissions
reduction or a certification that no control device is present at the
site. After the initial annual report, this information about the
affected facility is only required to be submitted in the annual report
if there are changes to the previously submitted information. Each
annual report must include the dates and results of inspections
conducted of closed vent systems, monitoring and inspections of control
devices that reduce emissions by 95 percent or more, and information
for any deviations from the pump emissions standards that occurred
during the reporting period.
Owners and operators are also required to keep records of the
information submitted in the annual reports regarding the pump affected
facility, and if applicable, the records required for monitoring and
inspections of closed vent systems and control devices. Records of each
deviation must also be kept.
2. EG OOOOc
a. Designated Facility
These final EG define designated facilities as the collection of
natural gas-driven pumps at a well site, centralized production
facility, onshore natural gas processing plant, or compressor station.
Pumps that are in operation less than 90 days per calendar year or that
are not natural gas-driven are not included in the designated facility.
b. Final Presumptive Standards
The presumptive methane standards for existing sources under EG
OOOOc are the same as the methane standards for new sources under NSPS
OOOOb.
c. Monitoring Requirements
The monitoring requirements in EG OOOOc are the same as those for
NSPS OOOOb.
d. Recordkeeping and Reporting Requirements
The recordkeeping and reporting requirements in EG OOOOc are the
same as those for NSPS OOOOb.
F. Wells and Associated Operations
A well is a hole drilled for the purpose of producing oil or
natural gas. Many of the sources covered by NSPS OOOOb and addressed by
EG OOOOc are associated with processes and equipment that is used to
handle, store, move, and process the oil and natural gas downstream of
the well. There are three sources, however, that are more directly
related to the well itself. These are well completions, liquids
unloading from gas wells, and associated gas from oil wells. In the
November 2021 Proposal, the EPA proposed separate NSPS OOOOb affected
facility definitions for each of these three sources. The result of
including all three definitions would have been that a single well
could have three different affected facilities for three different
emissions sources. In the December 2022 Supplemental Proposal, to
eliminate the potential confusion from this complex regulatory
structure, the EPA proposed to change its approach as part of the
supplemental proposal. Rather than three separate well affected
facilities, the EPA proposed a definition of well affected facility,
which is defined as a single well. Separate standards were proposed for
well completions, liquids unloading from gas wells, and associated gas
from oil wells. This structure is retained in the final rule.
For existing sources, there will never be well completions, as that
activity is only performed for newly constructed or reconstructed/
modified wells. Therefore, the proposed EG OOOOc in the 2022
Supplemental Proposal included the same basic definition for well
designated facility, but only included presumptive standards for
liquids unloading from gas wells and associated gas from oil wells.
This structure is also retained in the final EG OOOOc.
The following sections summarize the final NSPS OOOOb and EG OOOOc.
Specifically, section X.F.1 addresses the affected facility and
designated facility definitions, section X.F.2 addresses the standards
and presumptive standards for associated gas wells, section X.F.3
addresses the standards and presumptive standards for liquids
unloading, and section X.F.4 addresses the standards for well
completions.
[[Page 16886]]
1. Well Affected and Designated Facility Definitions
a. NSPS OOOOb
Well affected facility. Each well affected facility, which is a
single well.
(1) In addition to 40 CFR 60.14, a ``modification'' of an existing
well occurs when:
(i) An existing well is hydraulically fractured, or
(ii) An existing well is hydraulically refractured.
b. EG OOOOc
Well designated facility. Each well designated facility, which is a
single well.
2. Associated Gas From Wells Producing Primarily Oil
a. NSPS OOOOb
i. Affected Facility and Final Work Practice Standards
Each well affected facility that produces associated gas is subject
to the standards, where associated gas is defined as natural gas which
originates at wells operated primarily for oil production that is
released from the liquid hydrocarbon during the initial stage of
separation after the wellhead. For the purpose of distinguishing wells
operated primarily for oil production that produce associated gas from
wells operated primarily for gas production, the EPA refers to the
former as associated gas wells in this final rule. To provide
additional clarity regarding which wells are affected facilities
subject to the associated gas standards, the EPA added a definition of
associated gas to this final rule. In order to clearly distinguish
associated gas from gas vented during well completion activities, the
definition of associated gas specifies that associated gas production
begins at the startup of production after the flow back period ends.
Further, the EPA has chosen not to define oil wells or gas wells in
NSPS OOOOb or EG OOOOc.
The NSPS OOOOb final rule separates new associated gas wells into
multiple groups based on when construction is commenced. This grouping
serves the purpose of a ``phase-in'' of the final rule standards which
the EPA believes is appropriate in this situation because of certain
changes that the EPA made to these standards between the December 2022
Supplemental Proposal and final rule. These groups are: (1) Wells that
commence construction after May 7, 2026, (2) wells that commence
construction between May 7, 2024 and May 7, 2026, and (3) wells that
commenced construction between December 6, 2022, and May 7, 2024, and
wells that are modified or reconstructed after December 6, 2022. The
definition of ``commenced'' within the NSPS general provisions apply
for purposes of the NSPS OOOOb. 40 CFR 60.2.
The final work practice standard for all three groups is largely
the same. The associated gas must either be recovered from the
separator and routed into a gas gathering flow line or collection
system to a sales line, recovered from the separator and used as an
onsite fuel source, recovered from the separator and used for another
useful purpose that a purchased fuel, chemical feedstock, or raw
material would serve, or recovered from the separator and reinjected
into the well or injected into another well. The final work practice
standard for wells in the second and third group, is very similar to
what the EPA proposed in the December 2022 Supplemental Proposal,
although there are certain limitations that were not included in the
supplemental proposal, which we discuss below.
Wells in the first group (i.e., those wells that commence
construction after May 7, 2026) are required to route the gas to a
sales line, use the gas as an onsite fuel source, for another useful
purpose that a purchased fuel, chemical feedstock, or raw material
would serve, or reinject it into the well or into another well upon
start-up. The final standards do not allow these wells to routinely
flare emissions because we have determined that, with advance planning,
at least one of the options to avoid routine flaring will be feasible
at such wells (including routing the gas to a sales line, using the gas
as an onsite fuel source, using the gas for another useful purpose that
a purchased fuel, chemical feedstock, or raw material would serve, or
reinjecting it into the well or into another well). These sites must
handle the associated gas using one of these options, but the final
rule still includes provisions to allow short-term flaring for specific
circumstances such as safety concerns. The EPA recognizes that this is
a change from what was included in the December 2022 Supplemental
Proposal because there the EPA proposed to allow certain wells to
routinely flare provided they made a technical infeasibility
demonstration that was certified. Because of this change at final, the
EPA is applying this requirement (no routine flaring) to wells that
commence construction later than 24 months after the effective date of
this final rule. This additional time beyond the rule's effective date
will provide owners and operators with a sufficient period to adjust to
this change so that they can ensure compliance with the final standard
as soon as the well starts to produce associated gas.
Wells in the second group (i.e., wells that commence construction
between May 7, 2024 and May 7, 2026) must comply with the final
standard of no routine flaring on or before May 7, 2026. At that time,
these wells will no longer be allowed to flare routinely with a showing
of technical infeasibility, and must route associated gas to a sales
line, use the gas for another useful purpose that a purchased fuel,
chemical feedstock, or raw material would serve, or reinject the gas
into the well or inject it into another well. In the interim period not
to exceed 24 months from the effective date of the final rule, these
wells may route the associated gas to a flare or control device that
reduces methane and VOC emissions by at least 95.0 percent provided the
owner/operator can demonstrate that the other control options discussed
above are technically infeasible. Again, this will allow for a
sufficient phase in period for owners and operators of wells in this
group to adjust to the final standard, which is different than what the
EPA included in the December 2022 Supplemental Proposal.
For wells in the third group (wells that commenced construction,
modified, or reconstructed, between December 6, 2022 (the date that the
supplemental proposal published in the Federal Register), and May 7,
2024), the final rule allows routing the associated gas to a flare or
control device that reduces methane and VOC emissions by at least 95.0
percent on a routine basis, provided that the owner or operator
documents and certifies that routing the associated gas to a sales
line, using it as onsite fuel or for another beneficial purpose, or
injecting/reinjecting it are technically infeasible. This allowance for
technical infeasibility is provided for a period of 1 year at a time.
Owners and operators of wells in the third group must renew the
technical infeasibility determination/certification annually to be able
to continue to route the associated gas to a flare or control device.
Table 16 summarizes the different groups of associated gas wells
under NSPS OOOOb for purposes of phasing in the final rule standards
and when routine flaring is, or is not, allowed for each group.
[[Page 16887]]
Table 16--Summary of Allowance to Routinely Route Associated Gas to a
Flare or Control Device for NSPS OOOOb
------------------------------------------------------------------------
Routinely route to flare/
Construction commencement date control
------------------------------------------------------------------------
New well commencing construction after Not Allowed.
May 7, 2026.
New well commencing construction One year upon certification of
between May 7, 2024, and May 7, 2026. technical infeasibility. May
not exceed 790 days from
publication date of the rule.
Thereafter no routine flaring
allowed.
New well commencing construction One year upon certification of
between December 6, 2022, and May 7, technical infeasibility.
2024. Renewable upon annual
recertification.
------------------------------------------------------------------------
When associated gas is routed to a flare or control device, the
control device must meet all the requirements specified in 40 CFR
60.5412b. See section X.H of this preamble for more information on
control device requirements, including requirements for flares. In
addition, the CVS routing the associated gas to the flare or control
device must comply with the provisions in 40 CFR 60.5411b(a) and (c).
The EPA recognizes that temporary situations can occur beyond the
control of an owner/operator that could make it technically infeasible
or unsafe to comply with the standard for a limited period of time.
Therefore, for all wells subject to NSPS OOOOb, the final rule allows
owners and operators to route the associated gas to a flare or control
device temporarily. Specifically, the final rule allows this for the
situations and durations shown in table 17.
Table 17--Situations and Durations Where Associated Gas May Temporarily
Be Routed to a Flare or Control Device
------------------------------------------------------------------------
Situations where temporary routing
associated gas to a flare or control Maximum duration
device is allowed
------------------------------------------------------------------------
During a deviation caused by malfunction, 24 hours.
including for reasons of safety.
During repair, maintenance including 24 hours.
blowdowns, a bradenhead test, a packer
leakage test, a production test, or
commissioning.
During temporary interruption in service 30 days.
from the gathering or pipeline system.
If associated gas does not meet pipeline 72 hours.
specifications.
------------------------------------------------------------------------
The final rule requires that during any period when associated gas
is temporarily routed to a flare, the owner or operator demonstrate
that the flare is meeting the requirements in 40 CFR 60.5412b. See
section X.H of this preamble for more information on control device
standards.
The final rule also allows short-term venting in malfunction
situations where flaring the associated gas would cause an unsafe
environment. This venting would be limited to 12 hours.
As noted earlier in this preamble, for wells for which construction
commenced between December 6, 2022, and May 7, 2024, and for wells that
are reconstructed or modified after December 6, 2022, the final rule
allows routinely routing the associated gas to a flare or control
device that achieves 95.0 percent VOC and methane reduction provided a
yearly technical infeasibility demonstration. This means routinely
routing the associated gas to a flare or control device is allowed only
if the owner or operator demonstrates that all four options included in
the work practice standard discussed previously are infeasible due to
technical reasons. In order to demonstrate such technical
infeasibility, the final rule requires that a detailed analysis be
performed, and that documentation be prepared that demonstrates the
technical reasons for this infeasibility. The demonstration must
address the technical infeasibility for all options identified in the
rule, specifically: (1) Route into a gas gathering flow line or
collection system to a sales line, (2) recover from the separator and
use as an onsite fuel source, (3) recover from the separator and use
for another useful purpose that a purchased fuel, chemical feedstock,
or raw material would serve, or (4) recover from the separator and
reinject into the well or injected into another well.
The two components of a technical infeasibility demonstration are
the list of technologies to be evaluated, and reason that each of
technologies is infeasible. The first is the technologies or solutions
to be evaluated. For three of the options--route into a gas gathering
flow line or collection system to a sales line, recover from the
separator and use as an onsite fuel source, reinject into the well or
another well--this is straightforward. However, the third option--use
the associated gas for another useful purpose that a purchased fuel,
chemical feedstock, or raw material would serve--is more open ended.
The final rule does not specify the ``other useful purpose''
solutions that must be evaluated, but it is the responsibility of the
owner and operator, along with the qualified professional engineer or
other qualified personnel performing the evaluation, to ensure that the
list of options evaluated is comprehensive to address technically
viable solutions.
Technologies that are in the evaluation, pilot-plant, or testing
stages are not considered to be technically viable.
In summary, to demonstrate technical infeasibility in order to
route to a flare or control device, you must establish that it is not
technically feasible to route the associated gas into a gas gathering
flow line or collection system to a sales line, and not technically
feasible to use the associated gas as an onsite fuel source such as a
generator, fuel cell, or other power-producing use, and not technically
feasible to reinject into the well or another well, and not technically
feasible to utilize ``other useful purposes'' of the associated gas. A
technically viable ``other useful purpose'' is likely to require the
routing of the associated gas to on-site or nearby equipment that
compresses, liquifies, or transforms the gas into a physical state that
can be transported by pipeline or other transportation mode to an
eventual user. A determination of technical infeasibility requires a
[[Page 16888]]
showing of site-specific conditions that make these operations
infeasible for even the most basic of such uses. One such basic use is
capture and truck transportation offsite to a user or processing
facility.
The second component of the demonstration is the determination that
each of the possibilities is infeasible. While the final rule does not
specify criteria for technical infeasibility, the EPA generally
characterizes acceptable reasons in the general categories of physical,
logistical, or legal factors. Examples could include, but are not
limited to, the following. It may be infeasible to connect to a sales
line because of inability to secure necessary easements and/or rights-
of-way, inability to obtain necessary specialized equipment, inadequate
capacity of gathering system to accept the gas, or production sharing
contract restrictions. It may be infeasible to use the associated gas
as an onsite fuel source because there are no onsite power needs or
power needs have been met with less gas than produced, there is
insufficient associated gas to support a small electricity generation
plant, and there is no local demand for the power. Note that it would
be difficult to claim technical infeasibility based on no onsite power
needs if the site has equipment that is burning diesel or other fuel
which could be replaced by using the associated gas. Reinjection may be
infeasible because there is no subsurface reservoir or other storage
available for reinjection in the vicinity. To demonstrate that the
``other beneficial use'' option is not technically feasible an owner or
operator could show that there is an observable or demonstrable reason
that the operator cannot install equipment to convert associated gas to
compressed natural gas (CNG) at the well site due to physical or
technical constraints and/or that CNG transport in the region is not
available. It is expected that owners and operators will conduct
detailed evaluations of all such options. The analysis must show clear
evidence that the owner and operator has conducted due diligence to
understand the situations where the solution is being successfully
utilized and a demonstration of why it is not feasible at their site.
Note that the EPA acknowledges that the unavailability of a solution,
even one that has been demonstrated at one or more sites in the U.S.,
is a valid reason for an infeasibility conclusion. One overarching
factor that may impact technical feasibility is the composition of the
gas. The EPA recognizes that there are situations (e.g., high sulfur
content, high CO2 and low methane content) where some
solutions may be infeasible.
Each infeasibility demonstration must be certified by a qualified
professional engineer or other qualified individual with expertise in
the uses of associated gas. This certification must state: ``I certify
that the assessment of technical and/or safety infeasibility was
prepared under my direction or supervision. I further certify that the
assessment was conducted, and this report was prepared, pursuant to the
requirements of 40 CFR 60.5377b(b)(1). Based on my professional
knowledge and experience, and inquiry of personnel involved in the
assessment, the certification submitted herein is true, accurate, and
complete.''
Where available, each properly executed infeasibility determination
and certification allows the owners and operators of that particular
well site to routinely flare the associated gas for a one-year period.
While some new and modified sites can make such showings to routinely
flare, this mechanism is not available to all new well sites. See table
16 above. In the fast-moving landscape of the oil and natural gas
industry, there are a variety of factors that could change the
circumstances present when the previous infeasibility determination was
performed. For example, a gathering system could have been built or
extended in the vicinity of the well, the site could have expanded
operations and have a need for onsite power, or a new commercially
viable solution could become available. For this reason, the final rule
requires that an updated infeasibility determination and certification
be performed each year and submitted in the annual compliance report.
If an option that was technically infeasible before has since become
available, meaning that the reason that such option was technically
infeasible before has changed in a way that the option is now feasible,
then the owner/operator of the well must utilize that option going
forward and must cease routine flaring.
ii. Recordkeeping and Reporting Requirements
For affected facilities, required records include documentation of
the specific type(s) of compliance methods used (i.e., routed into a
gas gathering flow line or collection system to a sales line, used as
an onsite fuel source, used for another useful purpose that a purchased
fuel or raw material would serve, reinjected into the well or injected
into a another well). For those temporary situations where the
associated gas must be routed to a flare or control device, owners/
operators must document the reason for this temporary flaring, along
with the duration. If the gas is routed to a flare either on a
temporary or routine basis, records must be kept demonstrating that
flares meet the requirements outlined in 40 CFR 60.5412b. This
information must also be reported in the annual report. For those
temporary situations where the associated gas is vented due to
malfunction situations where flaring or routing to a control device
would cause an unsafe environment, the owner or operator must document
the reason for this venting, along with the duration, the volume of gas
vented, and the VOC and methane emissions. The annual report must
include all information for each venting episode.
For wells that properly demonstrate technical infeasibility and
therefore routinely route the associated gas to a flare or control
device that achieves 95.0 percent reduction in VOC and methane,
detailed records must be maintained supporting the infeasibility
determination due to technical reasons, along with the signed
certification by a qualified professional engineer or other qualified
individual. This information must also be included in the annual
report. As discussed previously, this demonstration and certification
is required to be updated annually.
In addition, all records associated with a demonstration of proper
design and operation of the control device, where used, must be
maintained (see section X.H of this preamble). For all instances where
associated gas is temporarily vented due to malfunction situations
where flaring or routing to a control device would cause an unsafe
environment, an owner or operator must also document the reason for
this venting, along with the duration, the volume of gas vented, and
the VOC and methane emissions. The annual report must include all
information for each venting episode.
b. EG OOOOc
i. Designated Facility
Consistent with the NSPS OOOOb affected facility, each existing
well that produces associated gas which commenced construction before
December 6, 2022, is a designated facility for purposes of EG OOOOc.
Associated gas is defined as natural gas which originates at wells
operated primarily for oil production that is released from the liquid
hydrocarbon during the initial stage of separation after the wellhead.
To distinguish associated gas from gas vented during the completion
activities, the definition of associated gas specifies that associated
gas production begins at the
[[Page 16889]]
startup of production after the flow back period ends.
ii. Final Work Practice Presumptive Standards
The final EG separates (subcategorizes) existing oil wells with
associated gas into two groups based on the amount (mass) of methane in
the associated gas. The demarcation between these two groups is 40 tons
of methane per year. The presumptive standard in the final EG for wells
that produce associated gas with over 40 tpy of methane is the same as
what the EPA proposed for existing sources within the 2022 Supplemental
Proposal.
The presumptive standard for existing wells that produce associated
gas with over 40 tpy of methane is summarized as follows. For these
sites, the associated gas must either be recovered from the separator
and routed into a gas gathering flow line or collection system to a
sales line, recovered from the separator and used as an onsite fuel
source, recovered from the separator and used for another useful
purpose that a purchased fuel, chemical feedstock, or raw material
would serve, or recovered from the separator and reinjected into the
well or injected into another well. If all of these options are
technically infeasible, then these existing wells (producing associated
gas with more than 40 tpy of methane) can route associated gas to a
flare or control device that achieve 95.0 percent reduction in methane.
The determination of technical infeasibility must be certified by a
professional engineer or other qualified personnel, the flare or
control device must meet the requirements of 40 CFR 60.5412b, and
technical infeasibility must be re-certified on an annual basis. For
purposes of this presumptive standard, the EPA intends that technical
infeasibility be defined in the same manner as explained above for new
sources. See the discussion under the NSPS (see section X.F.1 of this
document) related to the requirements for an infeasibility
determination and certification.
The presumptive standard in the final EG for wells that produce
associated gas with 40 tpy of methane or less is to route associated
gas to a flare or control device that achieves 95.0 percent reduction
in methane. The difference between the two groups is that, for those
existing wells with annual methane in the associated gas greater than
40 tpy, owners and operators are required to demonstrate that it is
infeasible for technical reasons to utilize any of the work practice
options before they can route associated gas to a flare or control
device. For existing wells that produce associated gas containing 40
tpy or less of methane, flaring or routing to control is allowed
without an infeasibility determination and certification. However,
existing wells that produce associated gas containing 40 tpy or less of
methane can still utilize any of the control options that result in
zero emissions to meet the standard.
The EPA has created subcategories for designated facilities because
EPA's analysis conducted after reviewing comments on the 2022
Supplemental Proposal indicates that it is not reasonable with respect
to cost to require sources that produce less than 40 tpy methane of
associated gas to route their associated gas to a sales line. The EPA
analyzed the task of routing to a sales line and found that the two
factors that controlled whether routing to a sales line was BSER was
the distance that a pipeline would need to go to reach the sales line,
and the amount of gas that could be recovered as measured at the
separator. Over even short distances, the cost of routing to a sales
line was not reasonable at very low levels of available associated gas.
Given this and the comments that we received on this point, the EPA
agreed with commenters that at low levels of associated gas production
the flaring of associated gas is the BSER. See the final rule TSD
chapter 3 on Associated Gas for further information on the
determination of BSER for designated sources.
In order to determine whether the methane contained in the
associated gas is 40 tpy or less, owners and operators must utilize a
gas-to-oil ratio (GOR)-based method derived from paragraphs 40 CFR
98.234(m)(1) through (4) of GHGRP subpart W. Sources with methane
contained in the associated gas greater than 40 tpy, and sources with
methane contained in the associated gas 40 tpy or less that elect to
comply with one of the work practices, are not required to calculate
and document the annual methane content in the associated gas.
iii. Recordkeeping and Reporting
The recordkeeping and reporting requirements included in EG OOOOc
are the same as those included in the NSPS OOOOb. Wells that elect to
demonstrate that the methane contained in the associated gas is 40 tpy
or less are required to maintain records of this calculation and submit
it in the annual reports.
3. Gas Well Liquids Unloading Operations
a. NSPS OOOOb
i. Affected Facility
Each well affected facility gas well that undergoes liquids
unloading.
ii. Final Standards
Each affected gas well that unloads liquids is required to employ
techniques or technology(ies) that minimize or eliminate venting of
emissions during liquids unloading events to the maximum extent. For
the EPA's rationale for prescribing a work practice standard over a
numeric standard, see section XI.F.3.a of this preamble. Owners or
operators are also allowed the option to comply with the GHG and VOC
standards by reducing methane and VOC emissions from each gas well
liquids unloading event by 95 percent by routing emissions to a control
device via a CVS.
For unloading technologies or techniques that eliminate venting of
emissions during liquids unloading events, the final rule requires
minimal recordkeeping and reporting.
For unloading technologies or techniques that could result in
venting to the atmosphere, the final rule requires work practices be
followed. Specifically, the final rule requires that owners or
operators employ and document best management practices to minimize or
eliminate venting of methane and VOC emissions for each gas well
liquids unloading operation.
Specifically, owners or operators of well affected facilities that
are gas wells that unload liquids must develop, maintain, and follow a
best management practice plan to eliminate or minimize venting of
methane and VOC emissions to the maximum extent possible from each gas
well liquids unloading operation. This best management practice plan
must meet the following minimum criteria: (1) Include steps that create
a differential pressure to minimize the need to vent a well to unload
liquids; (2) include steps to reduce wellbore pressure as much as
possible prior to opening the well to the atmosphere; (3) unload
liquids through the separator where feasible; and (4) close all
wellhead vents to the atmosphere and return the well to production as
soon as practicable.
The best management practice plan that provides steps to minimize
or eliminate venting of emissions would apply for both planned venting
events and unintended/unplanned venting events due to malfunctions or
error. In some instances, depending on the non-venting liquids
unloading technology or
[[Page 16890]]
technique employed, the best management plan for planned and unplanned
events may differ. In such cases, an owner or operator may choose to
develop a separate plan to cover unplanned events. However, to minimize
emissions, depending on technology or technique employed, the same
minimum best management practice criteria should apply, i.e.: (1)
Include steps that create a differential pressure to minimize the need
to vent a well to unload liquids; (2) include steps to reduce wellbore
pressure as much as possible prior to opening the well to the
atmosphere; (3) unload liquids through the separator where feasible;
and (4) close all wellhead vents to the atmosphere and return the well
to production as soon as practicable. Where a planned or unplanned
event occurs where best management practices were unable to be
followed, an owner or operator is required to report those events as
deviations. Specifically, owners or operators are required to report
the number of liquids unloading events during the year where deviations
from your best management practice plan occurred, the date and time the
deviation began, the duration of the deviation in hours, documentation
of why best management practice plan steps were not followed, and what
steps, in lieu of your best management practice plan steps, were
followed to minimize emissions to the maximum extent possible.
For owners or operators that comply with the GHG and VOC standards
by reducing methane and VOC emissions from each gas well liquids
unloading event by 95 percent by routing emissions to a control device
via a CVS, an owner or operator is required to maintain records and
report that it is complying by using this option. In instances where a
deviation from the standard has occurred during the reporting period,
an owner or operator would be required to provide information on the
date and time the deviation began, the duration of the deviation, and a
description of the deviation. Additionally, the dates of each cover and
CVS inspection, whether emissions are identified, and the date of
repair or the date of anticipated repair if repair is delayed would be
required in the annual report. Where bypass requirements apply, the
date and time of each bypass alarm or each instance the key is checked
out would be included in the annual report. For the reports and records
that must be maintained to demonstrate proper design and operation of
the control device, see sections X.H.1 and X.H.2 of this preamble.
iii. Recordkeeping and Reporting Requirements
For each gas well liquids unloading operation where the technique/
technology employed eliminates venting to the atmosphere, owners or
operators are only required to maintain the identification of the well
affected facility and the zero-emitting technology or technique used;
and the number of liquids unloading events conducted during the
reporting period that had unplanned venting events (if any) that
required that they employ best management practices to minimize
emissions to the maximum extent possible during the unplanned event. As
noted previously, any unplanned venting events would be subject to the
required best management practices and associated recordkeeping and
reporting requirements for those events.
For each gas well liquids unloading operation where emissions are
vented to the atmosphere, owners or operators of affected facilities
are required to keep the following records: (1) Identification of each
well affected facility that conducted liquids unloading during the
reporting period that vented to the atmosphere; (2) the number of
liquids unloading events during the reporting period that vented to the
atmosphere; (3) documentation of your best management practice plan
developed that meets the criteria specified in 40 CFR 60.5376b(d) of
the final NSPS OOOOb; (4) a log of each best management practice plan
step taken to minimize emissions to the maximum extent possible for
each gas well liquids unloading event; and (5) documentation of each
gas well liquids unloading event where deviations from your best
management practice plan steps occurred, the date and time the
deviation began, the duration of the deviation, documentation of best
management practice plans steps were not followed, and the steps taken
in lieu of your best management practice plan steps during those events
to minimize emissions to the maximum extent possible. These
requirements apply for both planned and unintended/unplanned venting
events due to malfunctions or error.
For each well affected facility where gas well liquids unloading
operations are conducted, an annual report is required to include a
summary of the information required to be maintained.
b. EG OOOOc
i. Designated Facility
Each well designated facility gas well that undergoes liquids
unloading.
ii. Final Presumptive Standards and Recordkeeping and Reporting
Requirements
The work practice standards and recordkeeping and reporting
requirements for well designated facilities that undergo gas well
liquids unloading under EG OOOOc are the same as those finalized for
NSPS OOOOb.
4. Well Completions
a. NSPS OOOOb
i. Affected Facility
Each well affected facility well completion of hydraulically
fractured (or refractured) wells.
ii. Final Standards
For well completion of hydraulically fractured (or refractured)
wells, there are two subcategories of hydraulically fractured wells for
which well completions are conducted: (1) Non-wildcat and non-
delineation wells (subcategory 1 wells); and (2) wildcat and
delineation wells, and non-wildcat and non-delineation low-pressure
wells (subcategory 2 wells). A wildcat well is a well drilled outside
known fields or is the first well drilled in an oil or gas field where
no other oil and gas production exists. A delineation well is a well
drilled to determine the boundary of a field or producing reservoir.
For non-wildcat and non-delineation wells (subcategory 1 wells),
owners or operators are required to use a combination of reduced
emissions completion (REC) equipment/practices and a completion
combustion device to control emissions from a completion event. For
each flowback stage (i.e., initial flowback stage, separation flowback
stage) of the well completion, the EPA specifies requirements in the
final rule. During the initial flowback stage, owners or operators are
required to route the flowback to a storage vessel or completion vessel
(frac tank, lined pit, or other vessel) and separator. During the
separation flowback stage, owners or operators are required to route
all salable gas from the separator to a gas flow line or collection
system, re-inject the gas into the well or another well, use the gas as
an onsite fuel source or use for another useful purpose that a
purchased fuel or raw material would serve. If technically infeasible
to route recovered gas as specified previously, recovered gas must be
combusted. All
[[Page 16891]]
liquids, during the separation phase, must be routed to a storage
vessel or well completion vessel, collection system, or be reinjected
into the well or another well. The final rule requires the operator to
have the separator available and to use the separator for the entirety
of flowback, either by having the separator on-site or at a nearby
centralized facility or well pad that services the well affected
facility. A well that is not hydraulically fractured or refractured
with liquids, or that does not generate condensate, intermediate
hydrocarbon liquids, or produced water such that there is no liquid
collection system at the well site is not required to have a separator
on-site or at a centralized production facility or well pad that
services the well completion well affected facility.
For each wildcat and delineation well, and non-wildcat and non-
delineation low pressure wells (subcategory 2 wells), owners or
operators must either: (1) Route all flowback to a completion
combustion device equipped with a continuous pilot flame; or (2) route
all flowback into one or more well completion vessels and commence
operation of a separator unless it is technically infeasible for a
separator to function. Gas recovered from the separator must be
captured and routed to a completion combustion device equipped with a
continuous pilot flame. Option (2) may only be used where the owner or
operator is able to operate a separator, and the separator must be
available (onsite or otherwise available for use) and must be used for
the entirety of flowback. For both options (1) and (2), combustion is
not required in conditions that may result in a fire hazard or
explosion, or where high heat emissions from a completion combustion
device may negatively impact tundra, permafrost, or waterways.
Oil wells with a gas-to-oil ratio less than 300 scf of gas per
stock tank barrel of oil produced are well affected facilities but have
no requirements other than to maintain records of the low GOR
certification and a claim signed by the certifying official.
iii. Recordkeeping and Reporting Requirements
Owners or operators of a well affected facility must notify the
Administrator no later than 2 days prior to the commencement of each
well completion operation listing the anticipated date of the well
completion operation. If an owner or operator is subject to state
regulations that require advance notification of well completions and
you have met those notification requirements, then you are considered
to have met the advance notification requirements of the final rule.
Owners or operators of well affected facilities must maintain a log
for each well completion operation at each well affected facility. The
log must be completed daily for the duration of the well completion
operation and must contain specified record information (see 40 CFR
60.5420b(c)(1)(iii)).
Annual reports are required to include general information for all
well affected facility reports, and for each well affected facility
subject to well completion requirements. Owners or operators are
required to maintain records and report information regarding each well
completion operation conducted during the reporting period, including
the location of the well, type of well, duration of completion event,
and information related to the well completion itself (e.g., actions
taken to mitigate emissions). Additionally, if venting occurs, the
annual report is required to include the specific reasons for venting
in lieu of capture or combustion, as well as any deviations recorded
(i.e., the date and time the deviation began, the duration of the
deviation in hours, and a description of the deviation).
For each well affected facility that is an oil well with a gas-to-
oil ratio less than 300 scf of gas per stock tank barrel of oil
produced, the annual report must include a record of the well type
(i.e., wildcat well, delineation well, or low-pressure well) and
supporting inputs and calculations, if applicable. The records required
to be maintained by the owner or operator include: (1) A record of the
analysis performed in order to make that claim, including but not
limited to, GOR values for established leases and data from wells in
the same basin and field; (2) the latitude and longitude of the well in
decimal degrees to an accuracy and precision of five decimals of a
degree using North American Datum of 1983; (3) the United States Well
Number; and (4) a record of the claim signed by the certifying
official.
For each well meeting affected facility claiming an exemption at 40
CFR 60.5375b(h) for a well modified in accordance with 40 CFR
60.5365b(a)(1)(ii) (i.e., an existing well that is hydraulically
refractured), the annual report must include a statement that the well
completion operation requirements of 40 CFR 60.5375b(a)(1) through (3)
were met. Records required to be maintained include: (1) A record of
the latitude and longitude of the well in decimal degrees to an
accuracy and precision of five decimals of a degree using North
American Datum of 1983; (2) the United States Well Number; (3) the date
and time of the onset of flowback following hydraulic fracturing or
refracturing; and (4) a record of the claim that the well completion
operation requirements of 40 CFR 60.5375b(a)(1) through (3) were met.
b. EG OOOOc
Because the fracturing or re- fracturing of an existing well would
constitute a modification under NSPS OOOOb, it would make the existing
well a well affected facility under NSPS OOOOb. Thus, no requirements
are specified for well completions under EG OOOOc.
G. Centrifugal Compressors
1. NSPS OOOOb
a. Affected Facility
The centrifugal compressor affected facility is defined as a single
centrifugal compressor. A centrifugal compressor located at a well site
is not a centrifugal compressor affected facility under NSPS OOOOb. A
centrifugal compressor located at a centralized production facility is
a centrifugal compressor affected facility under NSPS OOOOb.
b. Final Standards
Centrifugal compressor affected facilities with wet seals must
comply with the GHG and VOC standards by reducing methane and VOC
emissions from each centrifugal compressor wet seal fluid degassing
system by 95 percent by routing emissions via a CVS to a control
device. As an alternative to routing the CVS to a control device, an
owner or operator may also route the CVS to a process. If an owner or
operator chooses to comply with this requirement either by using a
control device to reduce emissions or by routing to a process to reduce
emissions, an owner must equip the wet seal fluid degassing system with
a cover and the cover must be connected through a CVS meeting specified
requirements, such as design and operation with no identifiable
emissions.
For specified centrifugal compressors (i.e., self-contained wet
seal compressor, wet seal compressor equipped with a mechanical seal,
centrifugal compressors equipped with sour seal oil separator and
capture system, centrifugal compressors equipped with dry seals), an
owner or operator has the option to comply with the rule by meeting the
following work practice performance-based volumetric flow rate
standards in lieu of requiring that emissions be routed to a control
device or process:
[[Page 16892]]
(1) If an owner or operator uses a self-contained wet seal
centrifugal compressor or a wet seal compressor equipped with a
mechanical seal, an owner or operator must conduct monitoring and
repair of the wet seal (as necessary) to maintain volumetric flow rate
at or below 3 standard cubic feet per minute (scfm), in operating or
standby pressurized mode, per seal. The volumetric flow rate of 3 scfm
is an action level that, if exceeded, triggers the requirement to
repair or replace the seal and is not a numeric limit.
(2) Owners or operators of centrifugal compressors on the Alaska
North Slope that are equipped with a seal oil recovery system (i.e.,
centrifugal compressors equipped with sour seal oil separator and
capture system, such as a seal oil gas separation system that separates
gas from the sour seal oil exiting the compressor seal assembly,
upstream from the degassing drum) must conduct monitoring and repair of
the wet seal (as necessary) to maintain a volumetric flow rate at or
below 9 scfm (in operating or standby pressurized mode) per seal. The
volumetric flow rate of 9 scfm is an action level that, if exceeded,
triggers the requirement to repair or replace the seal and is not a
numeric limit.
(3) If an owner or operator uses a centrifugal compressor equipped
with a dry seal, an owner or operator must conduct monitoring and
repair of the dry seal to maintain a volumetric flow rate at or below
10 scfm (in operating or standby pressurized mode) per seal. The
volumetric flow rate of 10 scfm is an action level that, if exceeded,
triggers the requirement to repair or replace the seal and is not a
numeric limit. In addition to the volumetric flow rate monitoring
required every 8,760 hours of operation, additional preventative
(maintenance) or corrective measures may be required to maintain
compliance with the centrifugal compressor wet and dry seal volumetric
flow rate performance standard. Specifically, if the volumetric flow
rate measured exceeds the flowrate specified for a centrifugal
compressor seal, the seals connected to the measured vent must be
repaired. Seal repair must be conducted within 90 calendar days from
the date of the volumetric emissions measurement. If the repair of the
wet or dry seal is technically infeasible, would require a vent
blowdown, a compressor station shutdown, or would be unsafe to repair
during operation of the unit, the repair can be delayed but must be
completed during the next scheduled compressor station shutdown for
maintenance, after a scheduled vent blowdown, or within 2 years,
whichever is earliest. A vent blowdown is the opening of one or more
blowdown valves to depressurize major production and processing
equipment, other than a storage vessel. In addition, if the repair
requires replacement of the compressor seal or a part thereof, but the
necessary replacement seal or part cannot be acquired and installed
within the repair timelines specified due to supplies being unavailable
(where previously sufficiently-stocked), a delay of repair is allowed.
However, in order to qualify for a delay of repair, the required seal
or part replacement must be ordered no later than 10 calendar days
after the centrifugal compressor seal is added to the delay-of-repair
list due to parts unavailability.
Owners or operators must conduct volumetric flow rate measurements
from each centrifugal compressor wet and dry seal vent within 15 days
after the repair to document that the rate has been reduced to less
than applicable flow rate per seal. If the individual seals are
manifolded to a single open-ended vent line, the volumetric flow rate
must be reduced to less than the sum of the individual seals multiplied
by the applicable required flow rate per seal.
For the EPA's rationale for prescribing a work practice standard
over a numeric standard, see section XI.G.2 of this preamble.
c. Recordkeeping and Reporting Requirements
For a centrifugal compressor affected facility complying by routing
emissions from the wet seal degassing system to a process through a
CVS, an owner or operator is required to maintain records and report
that it is complying by using this option. In instances where a
deviation from the standard has occurred during the reporting period,
an owner or operator would be required to provide information on the
date and time the deviation began, the duration of the deviation, and a
description of the deviation. Additionally, they would be required to
report of the dates of each cover and CVS inspection, whether emissions
are identified, and the date of repair or the date of anticipated
repair if repair is delayed would be included in the annual report.
Where bypass requirements apply, the date and time of each bypass alarm
or each instance the key is checked out would be included in the annual
report.
For a centrifugal compressor affected facility complying by routing
emissions from the wet seal degassing system to a control device
through a CVS, an owner or operator is required to maintain records and
report that it is complying by using this option. In instances where a
deviation from the standard has occurred during the reporting period,
an owner or operator would be required to provide information on the
date and time the deviation began, the duration of the deviation, and a
description of the deviation. Additionally, the dates of each cover and
CVS inspection, whether emissions are identified, and the date of
repair or the date of anticipated repair if repair is delayed would be
required in the annual report. Where bypass requirements apply, the
date and time of each bypass alarm or each instance the key is checked
out would be included in the annual report. For the reports and records
that must be maintained to demonstrate proper design and operation of
the control device, see sections X.H.1 and X.H.2 of this preamble.
Owners or operators complying with a performance-based emissions
standard for specified centrifugal compressors equipped with wet seals
and dry seals must track and report in their annual report the
cumulative number of hours of operation of each centrifugal compressor
since startup, or since the previous screening/volumetric flow rate
emissions measurement, as applicable. The annual report must also
include a description of the method used and the results of the
volumetric flow rate measurement or emissions screening, as applicable.
Lastly, owners or operators must maintain records and report each
measurement that exceeds the applicable performance-based emissions
standard per seal during the reporting period, and the date and time
the compressor seal was repaired to meet the required performance-based
emissions standard per seal. In the case of delay of repair due to
parts unavailability, operators must document the date the centrifugal
compressor was added to the delay-of-repair list, the date the
replacement seal or part thereof was ordered, the anticipated delivery
date, and the actual delivery date; and the annual report needs to
provide the reason for the needed delay and the date of anticipated
repair.
2. EG OOOOc
a. Designated Facility
The centrifugal compressor designated facility is defined as a
single centrifugal compressor. A centrifugal compressor located at a
well site is not a centrifugal compressor designated facility under EG
OOOOc. A centrifugal compressor located at a centralized production
facility is a centrifugal compressor designated facility under EG
OOOOc.
[[Page 16893]]
b. Final Presumptive Standards
For centrifugal compressor designated facilities with wet seals
(including self-contained wet seal centrifugal compressors and
centrifugal compressors equipped with mechanical seals) the presumptive
GHG standards are work practice performance-based volumetric flow rate
standards. These designated facilities must reduce methane emissions by
maintaining a volumetric flow rate at or below 3 scfm (in operating or
standby pressurized mode) per seal. Centrifugal compressors designated
facilities operating on the Alaska North Slope that are equipped with a
seal oil recovery system (i.e., centrifugal compressors equipped with
sour seal oil separator and capture system, such as a seal oil gas
separation system that separates gas from the sour seal oil exiting the
compressor seal assembly, upstream from the degassing drum) must
maintain a volumetric flow rate at or below 9 scfm (in operating or
standby pressurized mode) per seal. The volumetric flow rates of 3 and
9 scfm are action levels that, if exceeded, trigger the requirement to
repair or replace the seal and are not numeric limits.
Centrifugal compressor designated facilities with dry seals must
maintain a volumetric flow rate at or below 10 scfm (in operating or
standby pressurized mode) per seal. The volumetric flow rate of 10 scfm
is an action level that, if exceeded, triggers the requirement to
repair or replace the seal and is not a numeric limit.
In addition to the flow rate monitoring required every 8,760 hours
of operation, additional preventative (maintenance) or corrective
measures may be required to maintain compliance. Specifically, if the
volumetric flow rate measured exceeds the flowrate specified for a
centrifugal compressor seal, the seals connected to the measured vent
must be repaired. Seal repair must be conducted within 90 calendar days
from the date of the volumetric emissions measurement. If the repair of
the wet or dry seal is technically infeasible, would require a vent
blowdown, would require a compressor station shutdown, or would be
unsafe to repair during operation of the unit, the repair can be
delayed but must be completed during the next scheduled compressor
station shutdown for maintenance, after a scheduled vent blowdown, or
within 2 years, whichever is earliest. A vent blowdown is the opening
of one or more blowdown valves to depressurize major production and
processing equipment, other than a storage vessel. In addition, if the
repair requires replacement of the compressor seal or a part thereof,
but the necessary replacement seal or part cannot be acquired and
installed within the repair timelines specified due to supplies being
unavailable (where previously sufficiently-stocked), a delay of repair
is allowed. However, in order to qualify for a delay of repair, the
required seal or part replacement must be ordered no later than 10
calendar days after the centrifugal compressor seal is added to the
delay-of-repair list due to parts unavailability.
Owners or operators must conduct volumetric flow rate measurements
from each centrifugal compressor wet and dry seal vent within 15 days
after the repair to document that the rate has been reduced to less
than applicable flow rate per seal. If the individual seals are
manifolded to a single open-ended vent line, the volumetric flow rate
must be reduced to less than the sum of the individual seals multiplied
by the applicable required flow rate per seal.
Owners or operators must conduct volumetric flow rate measurements
from each centrifugal compressor wet and dry seal vent within 15 days
after the repair to document that the rate has been reduced to less
than applicable flow rate per seal. If the individual seals are
manifolded to a single open-ended vent line, the volumetric flow rate
must be reduced to less than the sum of the individual seals multiplied
by the applicable required flow rate per seal.
For the EPA's rationale for prescribing a work practice standard
over a numeric standard, see section XI.G.2 of this preamble.
As an alternative, an owner or operator may reduce methane
emissions from each centrifugal compressor wet seal fluid degassing
system or dry seal system by 95 percent by routing emissions via a CVS
to a control device, or by routing emissions via a CVS to a process. If
an owner or operator chooses to comply with the requirement either by
using a control device to reduce emissions or by routing to a process
to reduce emissions, an owner or operator must equip the wet seal fluid
degassing system with a cover and the cover must be connected through a
CVS meeting specified requirements, such as design and operation with
no identifiable emissions.
c. Recordkeeping and Reporting Presumptive Work Practice Requirements
Owners or operators complying with a performance-based emissions
standard must track and report in their annual report the cumulative
number of hours of operation of each centrifugal compressor since
startup, or since the previous screening/volumetric flow rate emissions
measurement, as applicable. The annual report must also include a
description of the method used and the results of the volumetric flow
rate measurement or emissions screening, as applicable. Lastly, owners
or operators must maintain records and report each measurement that
exceeds the applicable performance-based emissions standard per seal
standard during the reporting period, and the date and time the
compressor wet or dry seal was repaired to meet the applicable
performance-based emissions standard. Where a delay of repair is
needed, the annual report needs to provide the reason for the needed
delay and the date of anticipated repair.
For a centrifugal compressor designated facility complying with the
routing emissions from the wet seal compressor degassing system to a
process through a CVS, an owner or operator is required to maintain
records and report each centrifugal compressor during the reporting
period that is complying by using this option. In instances where a
deviation from the standard has occurred during the reporting period,
an owner or operator would be required to provide information on the
date and time the deviation began, the duration of the deviation, and a
description of the deviation. Additionally, the dates of each cover and
CVS inspection, whether emissions are identified, and the date of
repair or the date of anticipated repair if repair is delayed would be
included in the annual report. Where bypass requirements apply, the
date and time of each bypass alarm or each instance the key is checked
out would be included in the annual report.
For a centrifugal compressor designated facility complying with the
routing emissions from the wet seal fluid degassing system to a control
device through a CVS, an owner or operator is required to maintain
records and report each centrifugal compressor during the reporting
period that is complying by using this option. In instances where a
deviation from the standard has occurred during the reporting period,
an owner or operator would be required to provide information on the
date and time the deviation began, the duration of the deviation, and a
description of the deviation. Additionally, they would be required to
report the dates of each cover and CVS inspection, whether emissions
are identified, and the date of repair or the date of anticipated
repair if repair is delayed. Where bypass requirements apply, the date
and time of
[[Page 16894]]
each bypass alarm or each instance the key is checked out would be
included in the annual report. For the reports and records that must be
maintained to demonstrate proper design and operation of the control
device, see sections X.H.1 and X.H.2 of this preamble.
A. Combustion Control Devices
1. NSPS OOOOb
a. Compliance Assurance Requirements
NSPS OOOOb contains various compliance requirements to ensure that
combustion control devices that are being used to meet a 95 percent
emission reduction standard can continuously demonstrate this level of
control of emissions from affected facilities. Except as noted in
section XI.H of this preamble, the final compliance assurance
requirements for combustion control devices reflect the requirements
that were proposed in the December 2022 Supplemental Proposal.\192\
This section of the preamble presents a summary of the final
requirements for combustion control devices.
---------------------------------------------------------------------------
\192\ See section IV.H, 87 FR 74792 (December 6, 2022).
---------------------------------------------------------------------------
Except for boilers and process heaters that introduce the vent
stream with the primary fuel into the flame zone and flares, combustion
control devices must demonstrate compliance with this control
efficiency \193\ through a performance test, which must be repeated
every 5 years. In lieu of conducting the initial performance test,
owners and operators may purchase an enclosed combustion device that is
tested by the manufacturer according to procedures outlined in 40 CFR
60.5413b(d). For combustion devices where temperature is an indicator
of destruction efficiency (e.g., incinerators), the owner or operator
must establish a temperature limit during the performance test and
continuously monitor the temperature after the performance test. Owners
and operators using catalytic vapor incinerators must establish a limit
on the temperature at the inlet of the catalyst bed and the temperature
differential across the catalyst bed during the performance test and
continuously monitor these temperatures after the performance test. For
all other enclosed combustion devices and flares, the owner and
operator must maintain the net heating value (NHV) of the gas sent to
the device above a minimum amount if the combustion device is pressure-
assisted or uses no assist gas. If an owner or operator uses a steam-
assisted enclosed combustion device, the owner or operator must
maintain the combustion zone NHV above a minimum level. If the owner or
operator uses an air-assisted enclosed combustion device, the owner or
operator must maintain the NHV dilution parameter above a minimum
level. The combustion zone NHV and NHV dilution parameter terms account
for the reduction in heating value caused by the introduction of air
and/or steam. These terms ensure that the assist gas does not overwhelm
the heating value provided by the vent gas to the point where proper
combustion is no longer occurring.
---------------------------------------------------------------------------
\193\ Alternatively, the performance test can demonstrate
compliance with a total organic compounds outlet concentration of
275 ppmv on a wet basis, as propane. See section XI.H.1 of this
preamble for more information on the alternative outlet
concentration limit.
---------------------------------------------------------------------------
All flares and all enclosed combustion devices, other than boilers
and process heaters that introduce the vent stream with the primary
fuel into the flame zone and catalytic incinerators, must operate above
a minimum flow rate established by the manufacturer. Additionally, the
flow rate to a flare must be maintained at a level that ensures
compliance with the flare tip velocity limits in the 40 CFR part 60
General Provisions, and the flow rate to an enclosed combustion device
must be below a maximum flow rate established during the performance
test or by the manufacturer, if the initial performance test is
performed by the manufacturer. Flares and enclosed combustion devices
that use pressure-assisted tips to promote mixing at the burner tip are
not subject to this maximum flow rate limit because these units are
designed to operate at high flow rates.
All flares and all enclosed combustion devices must also operate
with a continuous burning pilot flame and with no visible emissions,
except for periods not to exceed a total of 1 minute during any 15-
minute period. Compliance with the visible emissions requirement can be
confirmed either through monthly testing using EPA Method 22 or through
continuous use of a video surveillance camera. Additionally, during
each fugitive emissions inspection conducted using an OGI camera,
including those conducted in response to periodic screening events
using alternative technologies, owners and operators must observe each
enclosed combustion device and flare to determine if it is operating
properly, ensuring that a flame is present and that there is no
indication of uncontrolled emissions. During each fugitive emissions
inspection conducted using AVO, owners and operators must observe each
enclosed combustion device and flare to determine if it is operating
properly, visually confirming that the pilot flame is lit and operating
properly.
Owners and operators also have the option to request an alternative
test method to demonstrate continuous 95.0 percent control of
emissions. In this option, the owner or operator would demonstrate that
the combustion device continuously achieves 95.0 percent combustion
efficiency or that the combustion device continuously complies with the
combustion zone NHV and NHV dilution parameter requirements. The
alternative test method would be used in lieu of the other monitoring
required for combustion device (e.g., vent gas NHV, flow rate).
b. Recordkeeping and Reporting Requirements
Owners and operators are required to maintain records and report
the results of all performance tests conducted on combustion control
devices. Additionally, for each continuous parameter monitoring system
(CPMS) that is used to demonstrate continuous compliance for a
combustion control device, owners and operators must report the
identity of the CPMS, the date of last calibration, and the date,
duration, and cause of all deviations. Owners and operators must also
record and report the date, duration, and cause of events where
emissions bypassed the control device and any period when visible
emissions exceeded 1 minute during a 15-minute period. For each visible
emissions test following return to operation from a maintenance or
repair activity, owners and operators must record and report the date
of the visible emissions test, the length of the test in minutes, and
the number of minutes for which visible emissions were present.
If an owner or operator conducts a demonstration to prove that the
NHV of the inlet gas to an enclosed combustion device or flare is
consistently above the minimum required NHV, the owner or operator must
record and report the results of the demonstration. Likewise, if an
owner or operator conducts a demonstration that the maximum potential
pressure of units manifolded to an enclosed combustion device or flare
cannot cause the maximum inlet flow rate or the flare tip velocity
limit to be exceeded, the owner or operator must record and report the
results of the demonstration.
In addition to the information that must be reported, owners and
operators must keep records of continuous
[[Page 16895]]
compliance with the monitoring requirements, including indications that
the pilot flame is lit, CPMS limits, CPMS hourly and average values,
and results of visible emissions observations or surveillance camera
feed. Owners and operators are also required to keep records of CPMS
checks and audits, maintenance activities and repairs for each control
device failing a visible emissions test, and the manufacturer's written
operating instructions, procedures, and maintenance schedule to ensure
good air pollution control practices for minimizing emissions. If an
owner or operator uses a backpressure regulator valve to control the
minimum flow rate to the combustion device, the owner or operator must
keep records of the engineering evaluation and manufacturer
specifications used to identify the set point and annual confirmation
that the backpressure regulator valve set point is set correctly and
that the valve fully closes when not in open position.
2. EG OOOOc
a. Compliance Assurance Requirements
The compliance requirements for combustion control devices on
designated facilities specified in EG OOOOc are almost identical to the
requirements specified in the NSPS OOOOb final rule. The only
difference between the requirements in NSPS OOOOb and EG OOOOc is that
for enclosed combustion devices and flares that are air-assisted or
steam-assisted, the owner and operator would be required to maintain
the NHV of the gas sent to the device above a minimum amount instead of
monitoring the combustion zone NHV and the NHV dilution parameter. See
section XI.H.5 of this preamble for more information on monitoring
steam-assisted and air-assisted enclosed combustion devices and flares.
b. Recordkeeping and Reporting Requirements
The EG OOOOc recordkeeping and reporting requirements for
combustion control devices on designated facilities specified in EG
OOOOc are the same as those specified in the NSPS OOOOb final rule.
I. Reciprocating Compressors
1. NSPS OOOOb
a. Affected Facility
The reciprocating compressor affected facility is each
reciprocating compressor, which is a single reciprocating compressor. A
reciprocating compressor located at a well site is not a reciprocating
compressor affected facility under this subpart. A reciprocating
compressor located at a centralized production facility is a
reciprocating compressor affected facility under this subpart.
b. Final Standards
The NSPS OOOOb standard of performance for reciprocating compressor
affected facilities is a performance-based emissions standard of 2 scfm
(in operating or standby pressurized mode) per cylinder. The volumetric
flow rate of 2 scfm is an action level that, if exceeded, triggers the
action of repairing or replacing the rod packing and is not a numeric
limit. The volumetric flow rate measurement from each reciprocating rod
packing must be maintained to be less than or equal to a flow rate of 2
scfm (in operating or standby pressurized mode) per cylinder. An owner
or operator is required to repair or replace the rod packing and to
conduct other necessary repair and maintenance in order to ensure the
emission rate is maintained at or below 2 scfm (in operating or standby
pressurized mode) per cylinder. Owners and operators must conduct
volumetric flow rate measurements from each reciprocating compressor
rod packing using the screening and monitoring methods specified in 40
CFR 60.5386b.
The EPA is requiring that the first and subsequent volumetric flow
rate measurements from a reciprocating compressor affected facility be
conducted on or before 8,760 hours of operation after the effective
date of the final rule, on or before 8,760 hours of operation after the
previous flow rate measurement, or on or before 8,760 hours of
operation after the date of the most recent compressor rod packing
replacement, whichever is later. Preventative maintenance or other
corrective actions (e.g., repair or replacement of rod packing) may be
necessary in addition to monitoring every 8,760 hours of operation for
owners or operators to ensure compliance (consistent with the general
duty clause 40 CFR 60.5470b(b)) with the required flow rate of 2 scfm
(in operating or standby pressurized mode) or less per cylinder). As an
alternative to conducting required volumetric flow rate measurements,
the final rule also allows an owner or operator the option to comply by
replacing the rod packing on or before 8,760 hours of operation after
the effective date of the final rule, on or before 8,760 hours of
operation after the previous flow rate measurement, or on or before
8,760 hours of operation after the date of the most recent compressor
rod packing replacement, whichever is later.
In the final rule, repair or replacement of the rod packing is
required when the volumetric emission measurement of the reciprocating
compressor rod packing has a flow rate greater than 2 scfm (in
operating or standby pressurized mode) per cylinder or a combined rod
packing flow rate greater than the number of compressor cylinders
multiplied by 2 scfm. An owner or operator must repair or replace the
reciprocating compressor rod packing within 90 calendar days from the
date of the volumetric emissions measurement.
The final rule allows for a delay of repair if the repair or
replacement would require a vent blowdown, or it would otherwise be
infeasible or unsafe, until the next process unit shutdown.
Specifically, if the repair or replacement is technically infeasible,
would require a vent blowdown, a process unit or facility requires
shutdown, parts or materials are unavailable, or it would be unsafe to
repair during operation of the unit, the repair can be delayed but must
be completed during the next scheduled process unit or facility
shutdown for maintenance, after a scheduled vent blowdown, or within 2
years, whichever is earliest. In addition, if the repair requires
replacement of the compressor rod packing or a part, but the necessary
replacement rod packing or part cannot be acquired and installed within
the repair timelines specified due to supplies being unavailable (where
previously sufficiently-stocked), a delay of repair is allowed.
However, in order to qualify for a delay of repair, the required rod
packing or part replacement must be ordered no later than 10 calendar
days after the reciprocating compressor is added to the delay-of-repair
list due to parts unavailability.
Owner or operators must conduct volumetric flow rate measurements
from each reciprocating compressor vent within 15 days after the repair
to document that the rate has been reduced to less than the applicable
flow rate per cylinder. If the individual cylinders are manifolded to a
single open-ended vent line, the volumetric flow rate must be reduced
to less than the sum of the individual cylinders multiplied by the
applicable required flow rate per cylinder.
For the EPA's rationale for prescribing a work practice standard
over a numeric standard, see section XI.I.1 of this preamble.
[[Page 16896]]
c. Routing Emissions From the Rod Packing to a Process or to a Control
Device That Reduces Emissions by 95 Percent
Alternatively, an owner or operator may choose to comply with NSPS
OOOOb by routing emissions from the rod packing via a CVS to a process
or to a control device achieving 95 percent control. These options
achieve emissions reductions greater than or equal to the 2 scfm
performance-based emissions standard per cylinder. An owner or operator
must ensure that the CVS is designed to capture and route all gases,
vapors, and fumes to a process (40 CFR 60.5411b(a) and (c)).
An owner or operator complying with the alternative option to route
to a process is required to design and operate the CVS with no
identifiable emissions and would be subject to bypass requirements (as
applicable). Initial, monthly, and annual inspections (using OGI, EPA
Method 21, or AVO (for monthly inspections only)) are required to check
for defects and identifiable emissions.
An owner or operator complying with the alternative option to route
to a control device is required to design and operate the CVS with no
identifiable emissions and would be subject to bypass requirements (as
applicable). Initial, monthly, and annual inspections (using OGI, EPA
Method 21, or AVO (for monthly inspections only)) of the CVS are
required to check for defects and identifiable emissions. Control
devices are required to meet the conditions specified in 40 CFR
60.5412b of the final rule.
d. Recordkeeping and Reporting Requirements
Owners or operators complying with the performance-based emissions
standard must track and report in their annual report the cumulative
number of hours of operation of each reciprocating compressor since
startup, since the previous screening/volumetric flow rate emissions
measurement, or since the previous reciprocating compressor repair/
replacement of rod packing, as applicable. Their annual report must
also include a description of the method used and the results of the
volumetric flow rate measurement or emissions screening, as applicable.
Lastly, owners or operators must maintain records and report each
measurement that exceeds the 2 scfm performance-based emissions
standard per cylinder standard during the reporting period, and the
date and time the reciprocating compressor was repaired or packing
replaced to meet the 2 scfm performance-based emissions standard. In
the case of delay of repair due to parts unavailability, operators must
document the date the reciprocating compressor was added to the delay-
of-repair list, the date the required rod packing or part was ordered,
the anticipated delivery date, and the actual delivery date; and the
annual report needs to provide the reason for the needed delay and the
date of anticipated repair or replacement.
For a reciprocating compressor affected facility complying by
routing emissions from the rod packing to a process through a CVS, an
owner or operator is required to maintain records and report each
reciprocating compressor that was constructed, modified, or
reconstructed during the reporting period that is complying by using
this option. Owners or operators must maintain records and report each
deviation from the performance-based emissions standard that occurred
during the reporting period, the date and time the deviation began,
duration of the deviation and a description of the deviation.
Additionally, they would be required to report (in the annual report)
the dates of each cover and CVS inspection, whether emissions are
identified, and the date of repair or the date of anticipated repair if
repair is delayed. Where bypass requirements apply, the date and time
of each bypass alarm or each instance the key is checked out would also
be included in the annual report.
For a reciprocating compressor affected facility complying by
routing emissions from the rod packing to a control device through a
CVS, an owner or operator is required to maintain records and report
each reciprocating compressor that was constructed, modified, or
reconstructed during the reporting period that is complying by using
this option. In instances where a deviation from the standard has
occurred during the reporting period, an owner or operator would be
required to provide information on the date and time the deviation
began, the duration of the deviation, and a description of the
deviation. Additionally, they would be required to report (in the
annual report) the dates of each cover and CVS inspection, whether
emissions are identified, and the date of repair or the date of
anticipated repair if repair is delayed. Where bypass requirements
apply, the date and time of each bypass alarm or each instance the key
is checked out would also be included in the annual report. For the
reports and records that demonstrate proper design and operation of the
control device that must be maintained, see sections X.H.1 and X.H.2 of
this preamble.
2. EG OOOOc
a. Designated Facility
The reciprocating compressor designated facility is each
reciprocating compressor, which is a single reciprocating compressor. A
reciprocating compressor located at a well site is not a reciprocating
compressor designated facility under this subpart. A reciprocating
compressor located at a centralized production facility is a
reciprocating compressor designated facility under this subpart.
b. Final Presumptive Standards
The presumptive standards for reciprocating compressor designated
facilities are the same performance-based emissions work practice
standard, or alternative routing emissions from the rod packing to a
process or control device options as required in the NSPS OOOOb final
rule. The final designated facility recordkeeping and reporting
requirements specified in the final EG OOOOc rule are also the same as
specified in the NSPS OOOOb final rule.
J. Storage Vessels
1. NSPS OOOOb
a. Affected Facility
A storage vessel affected facility subject to the final standards
is defined as a tank battery that has the potential for VOC emissions
equal to or greater than 6 tpy or methane emissions equal to or greater
than 20 tpy is. A storage vessel is a tank or other vessel that
contains an accumulation of crude oil, condensate, intermediate
hydrocarbon liquids, or produced water, and that is constructed
primarily of nonearthen materials. A tank battery is a group of all
storage vessels that are manifolded together for liquid transfer. For
purposes of this rule, a tank battery may consist of a single storage
vessel if only one storage vessel is present.
b. Final Standards
Storage vessel affected facilities must reduce emissions of VOC and
methane by 95 percent. The standard reflects the degree of emission
limitation achievable through application of a combustion control
device or VRU, which we have identified as the BSER for storage vessel
affected facilities. See rationale for the BSER at section XII.B.1.e of
the November 2021 Proposal and Chapter 6 of the of the November 2021
TSD \194\ which is unchanged in this final rule. For storage vessel
affected facilities not at a well site or centralized production
[[Page 16897]]
site and without potential for flashing emissions, owners and operators
may choose to comply by using an internal or external floating roof to
reduce emissions in accordance with 40 CFR part 60, subpart Kb (NSPS
for Volatile Organic Liquid Storage Vessels). The rule allows removal
of a control device from a storage vessel affected facility if the
owner or operator maintains the uncontrolled actual VOC emissions at
less than 4 tpy and the actual methane emissions at less than 14 tpy as
determined monthly for 12 consecutive months.
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\194\ See Document ID No. EPA-HQ-OAR-2021-0317-0166.
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c. Cover and Closed Vent System Requirements--Control Device
Requirements
Storage vessel affected facilities which use a control device to
reduce emissions must equip each storage vessel in the tank battery
with a cover and must equip the tank battery with one or more closed
vent systems which route all emissions to a process or one or more
control devices. Flares and other control devices must conduct
monitoring, recordkeeping, and reporting to ensure that the control
device is continuously achieving the required 95 percent reduction.
More information on the flare and other control device monitoring and
compliance provisions is provided in section X.H of this preamble and
information regarding covers and closed vent systems may be found in
section X.K of this preamble.
d. Modification and Reconstruction
The EPA finalizes as proposed the definition of modification to
include specific physical changes that will trigger the modification
requirements (i.e., adding an additional storage vessel, replacing
existing storage vessel(s) that result in an increased capacity of the
tank battery, receiving additional throughput from production well(s))
at tank batteries at well sites or centralized production facilities,
or receiving additional fluids which cumulatively exceed the throughput
used in the most recent determination of the potential for VOC or
methane emissions not located at a well site or centralized production
facility, including each tank battery at compressors stations or
onshore natural gas processing plants that also result in exceeding the
applicability threshold for either VOC or methane). The EPA defines
reconstruction to mean at least half of the storage vessels are
replaced in the existing tank battery that consists of more than one
storage vessel, or the provisions of 40 CFR 60.15 are met for the
existing tank battery and the resulting emissions exceed the
applicability threshold for either VOC or methane.
e. Legally and Practicably Enforceable (LPE) Limitations
In this action, the EPA is finalizing the proposed criteria that
must be met for a permit limit or other requirement to qualify as a
legally and practicably enforceable limit for purposes of determining
whether a tank battery is an affected facility or designated facility
under NSPS OOOOb. A legally and practicably enforceable limit must
include a quantitative production limit and quantitative operational
limit(s) for the equipment, or quantitative operational limits for the
equipment; an averaging time period for the production limit, if a
production-based limit is used, that is equal to or less than 30 days;
established parametric limits for the production and/or operational
limit(s), and where a control device is used to achieve an operational
limit, an initial compliance demonstration (i.e., performance test) for
the control device that establishes the parametric limits; ongoing
monitoring of the parametric limits that demonstrates continuous
compliance with the production and/or operational limit(s);
recordkeeping by the owner or operator that demonstrates continuous
compliance with the limit(s) in; and periodic reporting that
demonstrates continuous compliance.
f. Recordkeeping and Reporting Requirements
In each annual report, owners and operators are required to
identify each storage vessel affected facility that was constructed,
modified, or reconstructed during the reporting period and must
document the emission rates of both VOC and methane individually. The
annual report must include deviations that occurred during the
reporting period and information for control devices tested by the
manufacturer or the date and results of the control device performance
test for control devices not tested by the manufacturer. The report
also must include the results of inspections of covers and CVS and the
identification of storage vessel affected facilities (or portion of
storage vessel affected facility) removed from service or returned to
service. For storage vessel affected facilities which comply with the
uncontrolled 4 tpy VOC limit or 14 tpy methane limit, the report must
include changes which resulted in the source no longer complying with
those limits and the dates that the source began to comply with the 95
percent reduction standard. The annual report must also include
information on control devices used to achieve the 95 percent reduction
standard. See section X.H of this preamble for more information related
to reporting and recordkeeping for control devices.
Required records include documentation of the methane and VOC
emissions determination and methodology, records of deviations and
duration, records for the number of consecutive days a skid-mounted or
permanently mobile-mounted storage vessel is on the site, the latitude
and longitude coordinates of each storage vessel affected facility,
dates that each storage vessel affected facility (or portion of storage
vessel affected facility) is removed from service or returned to
service, and records associated with control devices. For storage
vessel affected facilities which comply with the uncontrolled 4 tpy VOC
or 14 tpy methane limit, owners and operators must keep records of the
monthly methane and VOC determination and methodology, records of
changes which resulted in the source no longer complying with those
limits, and the dates that the source began to comply with the 95
percent reduction standard. All associated records that demonstrate
proper design and operation of the CVS, cover and control device also
must be maintained (see section X.K and X.H of this preamble).
2. EG OOOOc
a. Designated Facility
A storage vessel is a tank or other vessel that contains an
accumulation of crude oil, condensate, intermediate hydrocarbon
liquids, or produced water, and that is constructed primarily of
nonearthen materials. A tank battery is a group of all storage vessels
that are manifolded together for liquid transfer. For purposes of EG
OOOOc, a tank battery may consist of a single storage vessel if only
one storage vessel is present. Each tank battery that has the potential
for methane emissions greater than or equal to 20 tpy is a storage
vessel designated facility.
b. Final Presumptive Standards
The presumptive methane standards in EG OOOOc for storage vessel
designated facilities are the same emissions standards as those
specified for methane for storage vessel affected facilities in the
NSPS OOOOb final rule. Specifically, the presumptive standard is to
reduce methane emissions by 95 percent. It reflects the degree of
emission reduction through application of a combustion control device
or VRU, which we have identified as the BSER
[[Page 16898]]
for storage vessel designated facilities. See rationale for the BSER at
section XII.B.2. of the November 2021 Proposal and Chapter 6 of the of
the November 2021 TSD \195\ which is unchanged in this final rule. For
storage vessel designated facilities not at a well site or centralized
production site and without potential for flashing emissions, owners
and operators could choose to comply by using an internal or external
floating roof to reduce emissions in accordance with 40 CFR part 60,
subpart Kb (NSPS for Volatile Organic Liquid Storage Vessels). In
addition, the presumptive standards would allow removal of a control
device from a storage vessel affected facility if the owner or operator
maintains the uncontrolled actual VOC emissions at less than 4 tpy and
the actual methane emissions at less than 14 tpy as determined monthly
for 12 consecutive months. The designated facility presumptive
recordkeeping and reporting requirements in the final EG OOOOc rule are
also the same as those specified in the NSPS OOOOb final rule. Please
see a summary of these requirements above in section X.J.1.f.
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\195\ See Document ID No. EPA-HQ-OAR-2021-0317-0166.
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c. LPE Limitations
The EPA is finalizing the proposed criteria that must be met a
permit limit or other requirement to qualify as a legally and
practicably enforceable limits for purposes of determining whether a
tank battery is designated facility under EG OOOOc. A legally and
practicably enforceable limit must include a quantitative production
limit and quantitative operational limit(s) for the equipment, or
quantitative operational limits for the equipment; an averaging time
period for the production limit, if a production-based limit is used,
that is equal to or less than 30 days; established parametric limits
for the production and/or operational limit(s), and where a control
device is used to achieve an operational limit, an initial compliance
demonstration (i.e., performance test) for the control device that
establishes the parametric limits; ongoing monitoring of the parametric
limits that demonstrates continuous compliance with the production and/
or operational limit(s); recordkeeping by the owner or operator that
demonstrates continuous compliance with the limit(s) in; and periodic
reporting that demonstrates continuous compliance. These criteria are
the same as the LPE criteria for purposes of determining tank battery
affected facility status finalized in NSPS OOOOb as outlined in
X.J.1.e.
K. Covers and Closed Vent Systems
1. NSPS OOOOb
a. Compliance Assurance Requirements
This section of the preamble presents a summary of the final
compliance assurance requirements for CVS and covers. As noted in
section IV.K of the December 2022 Supplemental Proposal, the EPA
proposed several changes to the compliance assurance requirements for
CVS and covers between the November 2021 Proposal and the December 2022
Supplemental Proposal. First, the EPA proposed to align the design and
operational requirements for CVS, regardless of which affected or
designated facility is connected to the CVS and regardless of whether
the emissions are being routed to a process or a control device.
Second, the EPA proposed to allow the use of advanced methane detection
technologies to demonstrate continuous compliance for CVS and covers.
The use of advanced methane detection technologies to demonstrate
continuous compliance for CVS and covers is discussed in section X.B of
this preamble. Lastly the EPA proposed to change the emissions limit
for covers and CVS from no detectable emissions (NDE) to no
identifiable emissions (NIE). The EPA clarified that the proposed
change was not intended to change the stringency of the standard, but
to reflect the change in monitoring methods used for demonstrating
compliance with the standard. NDE is a term closely linked with EPA
Method 21; because the EPA proposed to allow owners and operators to
demonstrate compliance with the emissions limit for covers and CVS
using OGI and AVO in addition to EPA Method 21, the EPA proposed to
change the terminology used in the standard from NDE to NIE. Further
discussion on the NIE standard is provided below and in section XI.K.1
of this preamble. The final requirements for covers and CVS summarized
below reflect the requirements that were proposed in the December 2022
Supplemental Proposal.\196\
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\196\ See section IV.K, 87 FR 74804 (December 6, 2022).
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As in NSPS OOOO and OOOOa, NSPS OOOOb contains requirements for CVS
and covers to ensure compliance with the standards for centrifugal
compressor, reciprocating compressor, and storage vessel affected
facilities.\197\ CVS route emissions from well (i.e., oil wells when
routing associated gas to a control device), centrifugal compressor,
reciprocating compressor, process controllers, pumps, storage vessels
and process unit affected facilities to a control device or to a
process. Each CVS must be designed and operated to capture and route
all gases, vapors, and fumes to a process or to a control device and
comply with an emissions limit of NIE. Covers must form a continuous
impermeable barrier over the entire surface area of the liquid in the
storage vessel, over the centrifugal compressor wet seal fluid
degassing system, or over the reciprocating compressor rod packing
emissions collection system. Each cover opening shall be secured in a
closed, sealed position (e.g., covered by a gasketed lid or cap)
whenever material is in the unit on which the cover is installed,
except during those times when it is necessary to use an opening, such
as to inspect equipment or to remove material from the equipment.
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\197\ Also, as in NSPS OOOOa, CVS and covers not are not
associated with an affected facility are fugitive emissions
components.
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Initial and continuous compliance of the NIE standard would be
demonstrated through OGI or EPA Method 21 monitoring and AVO
inspections conducted at the same frequency as the fugitive emissions
monitoring for the type of site where the cover and CVS are located.
Alternatively, an owner or operator could demonstrate ongoing
compliance with the NIE standard for covers and CVS using the periodic
screening or continuous monitoring requirements for advanced methane
detection technologies in 40 CFR 60.5398b, as described in section X.B
of this preamble. Where AVO inspections are required, the CVS and cover
is determined to operate with NIE if no emissions are detected by AVO
means. Where OGI monitoring is conducted, the CVS and cover is
determined to operate with NIE if no emissions are imaged by the OGI
camera. Where EPA Method 21 monitoring is conducted, the CVS and cover
is determined to operate with NIE if the readings obtained using EPA
Method 21 are less than 500 parts per million by volume (ppmv) above
background. Emissions detected by AVO, OGI, or EPA Method 21 constitute
a deviation of the NIE standard until a subsequent inspection
determines that the CVS and cover operates with NIE. Where monitoring
is conducted using advanced methane detection technologies, covers and
CVS are determined to operate with NIE if no emissions are detected by
the periodic screening survey or, where continuous monitoring is
conducted, the site remains under the action levels. If emissions are
detected from the site during a periodic screening survey or the site
exceeds an action level, the
[[Page 16899]]
cover and CVS are still determined to operate with NIE unless a follow-
up inspection with EPA Method 21, OGI, or AVO indicates that the cover
and CVS do not operate with NIE.
Each CVS must be inspected to ensure that the CVS operates with NIE
initially within 30 calendar days after startup of the affected
facility routing emissions through the CVS and periodically.
Specifically, for the well sites and centralized production facilities
where a CVS is present, quarterly OGI or EPA Method 21 and bimonthly
AVO would be required; for compressor stations, quarterly OGI or EPA
Method 21 and monthly AVO would be required. For CVS and covers located
at onshore natural gas processing plants, AVO inspections are required
annually and instrument monitoring for NIE must be conducted either
bimonthly with OGI following the procedures in appendix K or quarterly
in accordance with EPA Method 21. For CVS joints, seams, and
connections that are permanently or semi-permanently sealed, owners and
operators are not required to conduct periodic instrument monitoring
with OGI or EPA Method 21, but the owner or operator must still conduct
initial instrument monitoring and periodic AVO monitoring.
Additionally, annual visual inspections must be conducted for all CVS
to check for defects, such as cracks, holes, or gaps.
If the CVS is equipped with a bypass, the bypass must include a
flow monitor and sound an alarm to alert personnel or send a
notification via remote alarm to the nearest field office that a bypass
is being diverted to the atmosphere, or it must be equipped with a car-
seal or lock-and-key configuration to ensure the valve remains in a
non-diverting position. To ensure proper design, an assessment of the
closed vent system must be conducted and certified by a qualified
professional engineer or in-house engineer.
Any emissions or defects detected during an inspection of a cover
or CVS is subject to repair, with a first attempt at repair within 5
days after detecting the emissions or defect and final repair within 30
days after detecting the emissions or defect. While awaiting final
repair, covers must have a gasket-compatible grease applied to improve
the seal. Delay of repair is allowed where the repair is infeasible
without a shutdown, or it is determined that immediate repair would
result in emissions greater than delaying repair. In all instances,
repairs must be completed by the end of the next shutdown. Owner and
operators may designate parts of the CVS as unsafe to inspect and
difficult to inspect but must have a written plan of the inspection of
this equipment. Equipment that is unsafe to inspect would expose
inspecting personnel to an imminent potential danger; this equipment
must be inspected as frequently as practicable, during safe to inspect
times. Equipment that is difficult to inspect would require elevating
inspecting personnel more than 2 meters above a support surface; this
equipment must be inspected at least once every 5 years.
b. Recordkeeping and Reporting Requirements
The CVS certification must be submitted in the annual report in the
reporting year in which the certification is signed. In each annual
report, the owner or operator must report the date of each cover and
CVS inspection, all defects or emissions identified during the
inspections, and the date of repair or anticipated repair if the repair
is delayed for each defect or emission. Owners and operators must also
report the date and time of each bypass or alarm or each instance where
the key is checked out. Records of CVS and cover inspections, CVS
bypass monitoring, and CVS design and certifications must be
maintained. The CVS certification must be submitted in the initial
annual report.
Records for CVS and covers include records of inspections, CVS
bypass monitoring, and CVS design and certifications. For each CVS or
cover inspection, owners and operators must keep records of the date of
the inspection, the method of inspection (i.e., visual, AVO, OGI, or
EPA Method 21), and all defects and emissions found. For each defect or
emission found, the owner or operator must record the location, a
description of the defect, the maximum concentration reading if EPA
Method 21 is used, the date of detection, the date of each attempt to
repair the defect or emission, the corrective action taken to repair
the defect or emission, and the date of final repair of the defect or
emission. If a repair is delayed, the owner or operator must record the
reason for delay and the anticipated date of repair. Owners and
operators must also keep records of unsafe and difficult to inspect
portions of the CVS, including the written inspection plan. For each
CVS bypass, owners and operators must keep records of readings from the
flow indicator and the date and time of each instance the alarm is
sounded, inspections of the seal or closure mechanism, and dates and
times of each instance the key is checked out.
2. EG OOOOc
a. Compliance Assurance Requirements
The model rule in EG OOOOc includes the same covers and CVS
requirements as those in NSPS OOOOb to assure that emissions from
designated facilities, such as wells (i.e., oil wells when routing
associated gas to a control device), centrifugal compressors,
reciprocating compressors, process controllers, pumps, and process
unit, are captured and routed to a control device or process when such
control device or process are being used to meet the presumptive
standards for the designated facilities.
b. Recordkeeping and Reporting Requirements
The recordkeeping and reporting requirements for EG OOOOc are the
same as those for NSPS OOOOb.
L. Equipment Leaks at Natural Gas Processing Plants
1. NSPS OOOOb
a. Affected Facility
Each process unit equipment affected facility, which is the group
of all equipment within a process unit at an onshore natural gas
processing plant, is an affected facility. Equipment, as used in the
standards and requirements of this subpart relative to the process unit
equipment affected facility at onshore natural gas processing plants,
means each pump, pressure relief device, open-ended valve or line,
valve, and flange or other connector that has the potential to emit
methane or VOC and any device or system required by those same
standards and requirements of this subpart. Process unit means
components assembled for the extraction of natural gas liquids from
field gas, the fractionation of the liquids into natural gas products,
or other operations associated with the processing of natural gas
products. A process unit can operate independently if supplied with
sufficient feed or raw materials and sufficient storage facilities for
the products.
b. Final Standards
The NSPS OOOOb final standards apply to the ``process unit
equipment'' affected facility and require that, for each piece of
equipment that has the PTE methane or VOC, owners and operators conduct
bimonthly (i.e., once every other month) OGI monitoring in accordance
with 40 CFR part 60, appendix K \198\ to detect equipment
[[Page 16900]]
leaks from pumps in light liquid service, pressure relief devices in
gas/vapor service, valves in gas/vapor or light liquid service,
connectors in gas/vapor or light liquid service, and CVS. As an
alternative to the bimonthly OGI monitoring, EPA Method 21 may be used
to detect leaks from the same equipment at frequencies specific to the
process unit equipment type (e.g., monthly for pumps, quarterly for
valves). Open-ended valves and lines, pumps, valves and connectors in
heavy liquid service and pressure relief devices in light liquid or
heavy liquid service must be monitored using AVO. The final rule
requires that when a leak is detected it must be repaired. Valves must
be repaired by replacing the leaking valve with a low emission (low-E)
valve, where technically feasible. The final rule also includes
requirements that the leaking equipment must be tagged for
identification and a first attempt at repair for all identified leaks
must be commenced within 5 days after detection, with final repair
completed within 15 days after detection (unless the delay-of-repair
provisions are applicable). Delay of repair would be allowed where it
is technically infeasible to complete repairs within 15 days without a
process unit shutdown. See rationale for the BSER at section XII.H.1.c.
of the November 2021 Proposal which is unchanged in this final rule.
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\198\ See section XIV of this preamble for information related
to appendix K.
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In addition to the monitoring and repair requirements summarized
previously, the final rule includes requirements for specific types of
equipment. Each open-ended valve or line must be equipped with a
closure device (i.e., cap, blind flange, plug, or a second valve) that
seals the open end at all times except during operations which require
process fluid flow through the open-ended valve or line. CVS used to
comply with the standards for process unit equipment must be monitored
bimonthly using OGI (or quarterly using EPA Method 21 if this
alternative is used). Control devices used to comply with the equipment
leak provisions must comply with the requirements described in section
X.H of this preamble. Pressure relief devices must be monitored within
5 days after a pressure release to ensure the device has reseated after
a pressure release. The final rule allows exceptions to the 5-day post-
pressure release monitoring requirement for pressure relief devices
that are located in a non-fractionating plant where the non-
fractionating plant is monitored only by non-plant personnel that are
not onsite.\199\ The exception allows the pressure relief device to be
monitored after a pressure release the next time non-plant monitoring
personnel are onsite, but in no event can the monitoring be delayed
beyond 30 calendar days after a pressure release. Pressure relief
devices that are routed to a process, fuel gas system, or control
device are not required to be monitored following a release because the
emissions from the release are controlled. The rule also provides
exceptions to the GHG and VOC standards for process unit equipment
affected facilities for certain types of equipment at a non-
fractionating plant that does not have the design capacity to process
283,200 standard cubic meters per day (scmd) (10 million scf per day)
\200\ or more of field gas and for equipment within a process unit at
the Alaskan North Slope.
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\199\ A nonfractionating plant refers to any gas plant that does
not fractionate mixed natural gas liquids into natural gas products.
See 40 CFR 60.5430b and 60.5430c.
\200\ For example, for pumps in light liquid service, pressure
relief devices in gas/vapor service, valves in gas/vapor and light
liquid service, and connectors in gas/vapor service and in light
liquid service that are located at a non-fractionating plant that do
not have the design capacity to process 283,200 standard cubic
meters per day (scmd) (10 million scf per day) or more of field gas,
owners or operators may comply with the following exceptions: (1)
They may conduct quarterly monitoring instead of bimonthly
monitoring as required under Sec. 60.5400b(b), and (2) they are
exempt from the routine monitoring requirements if complying with
the alternative standards of Sec. 60.5401b.
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NSPS OOOOb reporting is required semiannually for process unit
equipment affected facilities, which differs from the annual reporting
for other affected facilities in NSPS OOOOb. In the initial semiannual
report, the owner or operator must identify: each process unit
associated with the process unit equipment affected facility; the
number of each type of equipment subject to the monitoring
requirements; for each month of the reporting period, the number of
leaking equipment for which leaks were identified, the number of
leaking equipment for which leaks were not repaired, and the facts that
explain each delay of repair; and dates of process unit shutdowns. In
subsequent semiannual reports, owners and operators must report the
name of each process unit associated with the process unit equipment
affected facility; any changes to the process unit identification or
the number or type of equipment subject to the monitoring requirements;
for each month of the reporting period, the number of leaking equipment
for which leaks were identified, the number of leaking equipment for
which leaks were not repaired, and the facts that explain each delay of
repair; and dates of process unit shutdowns.
Required records in the final rule include inspection records
consisting of equipment identification, date and start and end times of
the monitoring inspection, inspector name, leak determination method,
monitoring instrument identification, type of equipment monitored,
process unit identification, appendix K records (where applicable), EPA
Method 21 instrument readings and calibration results (where
applicable) and, for visual inspections, the date, name of inspector
and result of inspection. For each leak detected, the final rule
requires recording of the instrument and operator identification (or
record of AVO method, where applicable), the date the leak was
detected, the date and repair method applied for first attempts at
repair, indication of whether the leak is still detected, and the date
of successful repair, which includes results of a resurvey to verify
repair. For each delay of repair, the final rule requires that the
equipment is identified as ``repair delayed'' along with the reason for
the delay, the signature of the certifying official, and the dates of
process unit shutdowns which occurred while the equipment is
unrepaired. Additionally, the final rule requires records of equipment
designated for NDE; the identification of valves, pumps, and connectors
that are designated as unsafe-to-monitor, an explanation stating why it
is unsafe-to-monitor, and the plan for monitoring that equipment; a
list of identification numbers for valves that are designated as
difficult-to-monitor, an explanation stating why it is difficult-to-
monitor, and the schedule for monitoring each valve; a list of
identification numbers for equipment that is in vacuum service and a
list of identification numbers for equipment designated as having the
PTE methane or VOC less than 300 hr/yr.\201\
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\201\ This exemption is similar to that in NSPS OOOOa, which
exempts owners/operators from monitoring leaks from equipment in VOC
service less than 300 hr/yr. As in NSPS OOOOa, this exemption
applies to equipment at onshore natural gas processing plants that
is used only during emergencies, used as a backup, or that is in
service only during startup and shutdown. See 85 FR 57408.
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Finally, for CVS and control devices used to control emissions from
process unit equipment affected facilities, the reports and records
that demonstrate proper design and operation of the control device also
must be maintained (see section X.H. of this preamble).
[[Page 16901]]
With the exception of the requirements for low-E valves, where
technically feasible, these standards are unchanged from section IV.L.1
of the December 2022 Supplemental Proposal. For each valve where a leak
is detected, you must comply by repacking the existing valve with a
low-E packing, replacing the existing valve with a low-E valve; or
performing a drill and tap repair with a low-E injectable packing. An
owner or operator is not required to utilize a low-E valve or low-E
packing to replace or repack a valve if the owner or operator
demonstrates that a low-E valve or low-E packing is not technically
feasible. Low-E valve or low-E packing that is not suitable for its
intended use is considered to be technically infeasible. Factors that
may be considered in determining technical infeasibility include:
retrofit requirements for installation (e.g., re-piping or space
limitation), commercial unavailability for valve type, or certain
instrumentation assemblies.
2. EG OOOOc
a. Designated Facility
Each process unit equipment designated facility, which is the group
of all equipment within a process unit at an onshore natural gas
processing plant, is a designated facility. Equipment, as used in the
standards and requirements of this subpart relative to the process unit
equipment designated facility at onshore natural gas processing plants,
means each pump, pressure relief device, open-ended valve or line,
valve, and flange or other connector that has the potential to emit
methane and any device or system required by those same standards and
requirements of this subpart. Process unit means components assembled
for the extraction of natural gas liquids from field gas, the
fractionation of the liquids into natural gas products, or other
operations associated with the processing of natural gas products. A
process unit can operate independently if supplied with sufficient feed
or raw materials and sufficient storage facilities for the products.
b. Final Standards
The EG OOOOc final methane presumptive standards for ``process unit
equipment'' designated facilities are the same as finalized for NSPS
OOOOb affected facilities. The Model Rule reporting and recordkeeping
requirements are also the same as finalized for NSPS OOOOb affected
facilities.
With the exception of low-E valves, these presumptive standards are
unchanged from section IV.L.2 of the December 2022 Supplemental
Proposal. See rationale for the BSER at section XII.B.2 of the November
2021 Proposal which is unchanged in this final rule.
M. Sweetening Units
1. Affected Facility
A sweetening unit refers to a process device that removes
H2S and/or CO2 from the sour natural gas stream--
i.e., sweetening units convert H2S in acid gases (i.e.,
H2S and CO2) that are separated from natural gas
by a sweetening process, like amine gas treatment, into elemental
sulfur in the Claus process. Each sweetening unit that processes
natural gas produced from either onshore or offshore wells is an
affected facility as well as each sweetening unit that processes
natural gas followed by a sulfur recovery unit.
2. Final Standards
Affected facilities with a sulfur production rate of at least 5
long tons per day (LT/D) must reduce SO2 emissions by 99.9
percent. Compliance with the standard is determined based on an initial
performance test and daily reduction efficiency measurements. During
the performance test, the minimum required reduction efficiency of
SO2 emissions is determined for the sweetening unit. For
affected facilities that have a design capacity less than 2 LT/D of
H2S in the acid gas (expressed as sulfur), recordkeeping and
reporting requirements are required. However, emissions control
requirements are not required. Facilities that produce acid gas that is
entirely reinjected into oil/gas-bearing strata or that is otherwise
not released to the atmosphere are also not subject to emissions
control requirements.
For affected facilities that use an oxidation control system, or a
reduction control system followed by an incineration device, an owner
or operator must (1) continually operate the oxidation/incineration
device and (2) install, calibrate, maintain, and operate monitoring
devices and continuous emission monitors. For affected facilities that
use a reduction control system not followed by an incineration device,
an owner or operator must install, calibrate, maintain, and operate a
continuous monitoring system to measure the emission rate of reduced
sulfur compounds.
Owners and operators of a sweetening unit device affected facility
are required to submit notifications required under the NSPS General
Provisions, initial and annual reports, and excess emissions reports
(as applicable). Affected facilities are also required to retain
records of the following:
(1) the applicable calculations and measurements,
(2) an analysis demonstrating that the facility's design capacity
is less than 2 LT/D of H2S expressed as sulfur to document
exemption from the control requirements (when applicable), and
(3) a record demonstrating that the facility's design capacity is
less than 150 LT/D of H2S expressed as sulfur (if electing
to comply with 40 CFR 60.5407b(e)).
This is unchanged from section IV.M of the December 2022
Supplemental Proposal.
N. Electronic Reporting
To increase the ease and efficiency of data submittal and data
accessibility, the EPA is finalizing, as proposed, a requirement that
owners and operators submit electronic copies of performance test
reports, natural gas processing plant semiannual reports, annual
reports, and notifications of well closure activities through the EPA's
Central Data Exchange (CDX) using the Compliance and Emissions Data
Reporting Interface (CEDRI). A description of the electronic data
submission process is provided in the memorandum, Electronic Reporting
Requirements for New Source Performance Standards (NSPS) and National
Emission Standards for Hazardous Air Pollutants (NESHAP) Rules,
available in the docket for this action. The final rulemaking requires
that performance test results be submitted in the format generated
through the use of the ERT or an electronic file consistent with the
xml schema on the ERT website. For natural gas processing plant
semiannual reports and annual reports, the final rule requires that
owners and operators use the appropriate spreadsheet template to submit
information to CEDRI. The final version of the templates for these
reports will be located on the CEDRI website.\202\ The final rulemaking
requires that notifications of well closure activities be submitted as
a portable document format (PDF) upload in CEDRI. The EPA is also
finalizing, as proposed, these same requirements in EG OOOOc.
---------------------------------------------------------------------------
\202\ https://www.epa.gov/electronic-reporting-air-emissions/cedri.
---------------------------------------------------------------------------
Furthermore, the EPA is finalizing in NSPS OOOOb and EG OOOOc, as
proposed, provisions that allow owners and operators the ability to
seek extensions for submitting electronic reports for circumstances
beyond the control of the facility, i.e., for a possible
[[Page 16902]]
outage in CDX or CEDRI or for a force majeure event, in the time just
prior to a report's due date, as well as the process to assert such a
claim.
O. Prevention of Significant Deterioration and Title V Permitting
The pollutants subject to regulation in this final rulemaking are
VOC and GHGs (which are regulated in this rule in the form of methane
limitations). As explained in section XV of this preamble, we are
finalizing provisions to NSPS OOOOb and EG OOOOc, analogous to what was
included in the 2016 NSPS OOOOa and other rules regulating GHGs from
electric utility generating units, to address some of the potential
implications this final rulemaking could have on the CAA Prevention of
Significant Deterioration (PSD) preconstruction permit program and the
CAA title V operating permit program.
XI. Significant Comments and Changes Since Supplemental Proposal for
NSPS OOOOb and EG OOOOc
This section of the preamble presents in each subsection a summary
of any changes since the December 2022 Supplemental Proposal for the
topic being addressed in that subsection, as well as significant
comments on that topic and the EPA's response thereto. For final NSPS
standards and requirements and final EG presumptive standards and
requirements that have not changed since the December 2022 Supplemental
Proposal, the supporting rationales for the EPA's BSER determinations
are not reiterated in this preamble. The rationale for these standards
and requirements can be found in the preamble to the December 2022
Supplemental Proposal and in the TSD for the December 2022 Supplemental
Proposal. The EPA's full response to comments on the November 2021
Proposal and December 2022 Supplemental Proposal, including any
comments not discussed in this preamble, can be found in the EPA's RTC
document for the final rule.\203\
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\203\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
---------------------------------------------------------------------------
A. Fugitive Emissions From Well Sites, Centralized Production
Facilities, and Compressor Stations
1. Fugitive emissions at Well Sites and Centralized Production
Facilities
In section X.A.1 of this document, the final NSPS OOOOb and EG
OOOOc requirements for fugitive emissions components at well sites and
centralized production facilities are summarized. The BSER analysis for
fugitive emissions components at well sites and centralized production
facilities is unchanged from what was presented in the December 2022
Supplemental Proposal (see 87 FR 74729-39, section IV.A.1: Fugitive
Emissions at Well Sites and Centralized Production Facilities).
Significant comments were received on the December 2022 Supplemental
Proposal on the following topics: (1) the definition of fugitive
emissions component, (2) the EPA's assumption regarding the
effectiveness of OGI and AVO, (3) the order of evaluating AVO in the
BSER analysis, (4) subcategorization of well sites, and (5)
miscellaneous other changes. For each of these topics, a summary of the
proposed rule (where relevant), the comments, the EPA responses, and
changes made in the final rule (if applicable), are discussed here.
These comments and the EPA's responses to these comments generally
apply to the standards proposed in both the NSPS OOOOb and EG OOOOc.
The instances where the comment and/or response only applies to the
NSPS OOOOb or EG OOOOc are noted. The EPA's full response to comments
on the November 2021 Proposal and December 2022 Supplemental Proposal,
including any comments not discussed in this preamble, can be found in
the EPA's RTC document for the final rule.\204\ This section of this
document presents a summary of significant comments received on
fugitive emissions components affected or designated facilities located
at well sites and centralized production facilities and the EPA's
response to those comments, as well as changes the EPA has made to the
well site fugitive emissions requirements of NSPS OOOOb and EG OOOOc
since the December 2022 Supplemental Proposal.
---------------------------------------------------------------------------
\204\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
---------------------------------------------------------------------------
a. Fugitive emissions component definition
Comment: Commenters suggested various revisions to the proposed
definition of fugitive emissions components. A commenter \205\ asked
that the EPA exclude yard piping from the definition because this
inclusion would expand the definition in an unprecedented way.
According to the commenter, cracks and holes in piping have never been
considered fugitive components in any other rule for LDAR in any
industry sector by the Agency. The commenter asserted that the EPA has
not explained how leak detection should be conducted for yard piping,
as compared to other fugitive emissions components where there are
identifiable leak points (such as valve stems or flange interfaces)
that are the target of monitoring. The commenter also noted that cracks
and holes represent potential loss of containment and are already
repaired and corrected per industry practice and code. Another
commenter \206\ asked that the EPA exclude buried yard piping from the
definition of fugitive emissions components because buried components
are difficult or impossible to monitor.
---------------------------------------------------------------------------
\205\ EPA-HQ-OAR-2021-0317-2428.
\206\ EPA-HQ-OAR-2021-0317-2326.
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Another commenter \207\ supported the EPA's inclusion of yard
piping in the definition. This same commenter asked that the EPA also
include certain equipment types like separators in the definition so
monitoring of separator dump valves and components on all other
equipment would clearly be required. The commenter noted that separator
dump valves are a known source of large fugitive emissions events. In
response to the November 2021 Proposal, the commenter \208\ had made a
similar case for inclusion of separator dump valves in the definition
in order to ensure that these components are monitored.
---------------------------------------------------------------------------
\207\ EPA-HQ-OAR-2021-0317-2433.
\208\ EPA-HQ-OAR-2021-0317-0844.
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Response: In the final NSPS OOOOb and EG OOOOc rules, the EPA has
retained yard piping \209\ in the definition of fugitive emissions
components. A definition of yard piping was added for clarity. As
discussed in the December 2022 Supplemental Proposal, pipes can
experience cracks or holes, which can lead to fugitive emissions. The
inclusion of yard piping in the definition of fugitive emissions
components will help ensure that fugitive emissions from
[[Page 16903]]
these sources do not go undetected during fugitive emissions monitoring
and that issues found from the pipe itself leading to the fugitive
emissions are addressed. If industry is already conducting checks for
leaks as standard practice and code, this would further assist in
ensuring that fugitive emissions are minimized. AVO and OGI can be used
to detect fugitive emissions from cracks and other defects in yard
piping by scanning along the length of the piping. However, the EPA
acknowledges that EPA Method 21 does not include instructions for
monitoring yard piping; therefore, the EPA is providing directions in
this final rule on how to monitor yard piping while conducting an EPA
Method 21 monitoring survey. Lastly, the EPA recognizes the difficulty
of monitoring yard piping that is buried, as it may require disturbing
the surface, which could inadvertently cause emissions; therefore, the
final NSPS OOOOb and EG OOOOc rules only require monitoring of yard
piping and associated fugitive components (e.g., connectors) that are
at or above ground level.
---------------------------------------------------------------------------
\209\ The EPA recognizes that the terms ``yard piping'' and ``in
yard piping'' were used interchangeably in the December 2022
Supplemental Proposal. The final rule uses the term ``yard piping''
consistently.
---------------------------------------------------------------------------
Regarding a commenter's request that the definition of fugitive
emissions components explicitly include separators, the EPA agrees
that, although the list of components in the definition is not
exhaustive, it is worthwhile to eliminate any ambiguity as to whether
separator dump valves are fugitive emissions components. The EPA is
finalizing a definition of fugitive emissions components in NSPS OOOOb
and EG OOOOc that specifically includes separator dump valves, thus
clarifying that the separator dump valve is subject to monitoring by
OGI, AVO, or other detection methods. In addition, because
malfunctioning separator dump valves are a known source of large
emissions (as the commenter noted) and because sometimes there is
visual evidence of the malfunction, the EPA is requiring in the final
rule that, during the regular AVO monitoring surveys (either quarterly
or bimonthly depending on the site), a visual inspection must be
conducted of all separator dump valves to ensure that they are free of
debris and not stuck in an open position, and any dump valve not
operating as designed must be repaired.
b. OGI and AVO Effectiveness
Comment: Some commenters claimed that the EPA's assumptions for OGI
and AVO effectiveness in both NSPS OOOOb and EG OOOOc are overstated
and need to be adjusted. Specifically, these commenters were concerned
the upper bound assumption of the percentage of leaks that will be
detected by either method should be adjusted to reflect that these
methods will not find all leaks during a survey. These commenters
suggested that not all leaks, even large ones, would be observed during
the monitoring survey, so not all the leaks would be repaired.
One commenter \210\ specifically objected to the EPA's reliance on
emissions information from the 2021 Rutherford, et al., study \211\
because the commenter believes the study ``cherry-picks'' data. This
same commenter believes that the EPA ignores relevant information from
the U.S. DOE marginal well study \212\ and urged the use of DOE
emissions data in FEAST modeling to evaluate programs for low
production and existing sites.
---------------------------------------------------------------------------
\210\ EPA-HQ-OAR-2021-0317-2446.
\211\ Rutherford, J.S., Sherwin, E.D., Ravikumar, A.P., et al.
``Closing the methane gap in U.S. oil and natural gas production
emissions inventories.'' Nat Commun 12, 4715 (2021). https://doi.org/10.1038/s41467-021-25017-4.
\212\ Bowers, Richard L. ``Quantification of Methane Emissions
from Marginal (Low Production Rate) Oil and Natural Gas Wells.''
https://doi.org/10.2172/1865859.
---------------------------------------------------------------------------
Conversely, one commenter \213\ asserted that the EPA's assumptions
about the effectiveness of OGI are supported by recent data and FEAST
modeling. One commenter \214\ believes that all inputs used by the EPA
are reasonable, are appropriate, and ensure that advanced technologies
deliver emissions reductions commensurate with OGI across diverse
basins.
---------------------------------------------------------------------------
\213\ EPA-HQ-OAR-2021-0317-2433.
\214\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------
Other commenters \215\ expressed overall support of the use of
FEAST modeling and recommended some adjustments. One commenter \216\
noted that intermittency of emissions should be represented in
modeling. As it specifically relates to AVO, one commenter \217\
indicated that there is limited availability of information and studies
on the effectiveness of AVO inspections for emissions with variable
rates, intermittent emissions, emissions elevated above ground level,
[varying] emission point aperture sizes, and emissions occurring in
varying ambient conditions (e.g., wind, rain, and other ambient
equipment/process/compressor noise that may obstruct detection). The
commenter recommended that the EPA perform or seek out studies of AVO
effectiveness across this range of conditions before incorporating it
into the FEAST model for calculation of emissions reductions for
purposes of equivalency demonstration for alternative monitoring
solutions. Another commenter \218\ noted that leak detection and repair
data collected in Colorado show both different annual rates for leaks
requiring repair as well as few leaks requiring repair as detected by
AVO.\219\
---------------------------------------------------------------------------
\215\ EPA-HQ-OAR-2021-0317-2286, -2433, -2446.
\216\ EPA-HQ-OAR-2021-0317-2387.
\217\ EPA-HQ-OAR-2021-0317-2333.
\218\ EPA-HQ-OAR-2021-0317-2286.
\219\ Commenter refers to Colorado's 2021 LDAR Annual Report;
e.g., in 2021, only 1,546 leaks were detected during 564,427 AVO
inspections (https://cdphe.colorado.gov/oiland-gas-and-your-health/oil-gas-compliance-and-recordkeeping).
---------------------------------------------------------------------------
Response: As discussed in the December 2022 Supplemental Proposal
preamble and noted by the commenters, the revised approach for
estimating the fugitive emissions under different monitoring scenarios
at well sites uses a FEAST modeling approach based on the presence of
specific types of equipment at well sites. The modeling uses built-in
emissions data from various emissions measurement campaigns which were
supplemented with additional study data to provide an empirical
emissions dataset for the model simulations. The EPA used the FEAST
model to evaluate potential fugitive emissions monitoring and repair
programs at well sites (87 FR 74725). The effectiveness of fugitive
emissions monitoring and repair programs are simulated within the FEAST
model based on the probability of detection (PoD) curves (or surfaces)
for each monitoring method and frequency, which indicate the
probability that a leak of a given size will be detected within a given
survey. Survey times (frequencies) are accounted for as finite time
periods. The model quantifies emissions occurring at a site over a
period of time (e.g., we used a 5-year simulation and evaluated the
emissions in the fifth year of the simulation), accounting for
simulated leak generation, identification, and repair rates. Emissions
reductions are calculated by comparing the simulated fugitive emissions
program against a baseline scenario where no program is implemented.
The emissions data used in the FEAST model included data from
direct measurement campaigns. Despite some shortcomings of the data in
studies analyzed in the Rutherford, et al., study, the study is useful
because it analyzes and reconciles multiple sources of data and
multiple methods of estimating emissions to arrive at a more robust and
validated model of component-level emissions from well sites. The EPA
chose to use the Rutherford, et al., study and the U.S. DOE marginal
well study to help inform assumptions necessary to establish a baseline
emissions scenario
[[Page 16904]]
in the FEAST model because they represent credible compilations of
relevant emissions data at the well site level. The set-up of the FEAST
model was further validated by finding that the results generated by
FEAST regarding the effectiveness of different OGI monitoring
frequencies align well with other values reported in literature. The
EPA found that the FEAST results align with the EPA's historical
assumptions of 40, 60, and 80 percent, for annual, semiannual, and
quarterly OGI monitoring, respectively,\220\ and these percent
efficiencies compare well to those discussed in the TSD for the 2020
Technical Rule.\221\
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\220\ Specifically, for large well sites at a 0.5 percent leak
generation rate, FEAST estimates reductions of 47, 67, and 78
percent, for annual, semiannual, and quarterly monitoring,
respectively. For multi-wellhead only well sites at a 0.5 percent
leak generation rate, FEAST estimates reductions of 44, 67, and 78
percent, for annual, semiannual, and quarterly monitoring,
respectively. For single wellhead only well sites, FEAST estimates
reductions of 48, 68, and 77 percent, for annual, semiannual, and
quarterly monitoring, respectively.
\221\ See section 2.4.1 of ``Oil and Natural Gas Sector:
Emission Standards for New, Reconstructed, and Modified Sources
Background Technical Support Document for the Final Reconsideration
of the New Source Performance Standards 40 CFR part 60, subpart
OOOOa.'' August 2020. EPA-HQ-OAR-2017-0483-2290.
---------------------------------------------------------------------------
For the December 2022 Supplemental Proposal, the FEAST modeling
conducted generally assumed a 100 percent probability of OGI camera
operators' seeing all leaks above a certain size threshold. Following
the December 2022 Supplemental Proposal, the EPA investigated the
effect of lowering the probability of detection, based on public
comments received asserting that not all leaks would necessarily be
detected (and subsequently lower emissions reductions would be
achieved). The EPA modeled ground-based surveys with maximum
probability of detection of 70, 90, and 100 percent detection limits. A
complete discussion of the EPA's assessment of the maximum probability
of detection is presented in a memorandum \222\ available in the
rulemaking docket. The results of this additional modeling suggest that
lowering the maximum probability of detection would not appreciably
change either the control effectiveness of various fugitive emissions
monitoring and repair programs or the conclusion regarding the cost-
effective monitoring programs.\223\ Therefore, the EPA maintains that
the OGI percent reduction efficiencies obtained via the FEAST modeling
that was conducted for the December 2022 Supplemental Proposal (see
tables 11-13 of the December 2022 Supplemental Proposal (87 FR 74732-
34), which align with previous assumptions and existing literature, are
representative.
---------------------------------------------------------------------------
\222\ Memorandum from Jeff Coburn, RTI International. Summary of
Additional FEAST Modeling Runs. September 25, 2023.
\223\ As observed in this analysis, cost-effective monitoring
frequencies when using a lower maximum probability of detection
would be at least as frequent when assuming a 100 percent maximum
probability of detection for large leaks. Id.
---------------------------------------------------------------------------
With respect to AVO effectiveness, the EPA did use an upper level
of detection of 90 percent for AVO monitoring. The EPA acknowledges
that the level of detection for AVO will be more variable than for OGI
because leaks detected by olfactory methods (smell) will largely rely
on other constituents present in the natural gas. However, the modeling
runs when using AVO alone provided reasonable agreement with the
emissions from oil and gas production sites that rely primarily on AVO
inspections as reported in the U.S. DOE marginal well study data.\224\
Therefore, the EPA concluded that the modeling assumptions regarding
the effectiveness of AVO monitoring were reasonable.
---------------------------------------------------------------------------
\224\ Memorandum from Jeff Coburn, RTI International. Summary of
Additional FEAST Modeling Runs. September 25, 2023.
---------------------------------------------------------------------------
With respect to the recommendation to include intermittent
emissions events in the FEAST model, the EPA has not done so for the
following reasons. First, in order to model intermittent emissions
events, assumptions would have to be made regarding the fraction of
fugitive emissions that exhibit intermittent behavior and the typical
duration of active emissions and of periods of low or zero emissions.
Because the EPA has limited data from which to make these necessary
assumptions, to include intermittent emissions events in the model
would introduce great uncertainty to the model. Second, the EPA notes
that intermittent emissions events are largely reported with respect to
``super-emitters,'' which the EPA is addressing through the Super
Emitter Program established in this final rule.\225\ For the reasons
stated, the EPA has not included intermittent emissions events in the
model.
---------------------------------------------------------------------------
\225\ See sections X.C and X.I for details on the Super Emitter
Program.
---------------------------------------------------------------------------
c. Order of AVO evaluation in the BSER
Comment: One commenter \226\ believes that the EPA should have
developed its regulatory strategy by first evaluating AVO and
determining its cost effectiveness; then, the EPA should have assessed
the impact of adding OGI monitoring. The commenter believes that
evaluating whether additional OGI monitoring is appropriate and at what
frequency should have come after the evaluation of AVO inspection in
the EPA's BSER analysis for NSPS OOOOb and EG OOOOc. According to the
commenter, this is particularly relevant for multi-wellhead only well
sites (where the proposed requirement was semiannual OGI and quarterly
AVO) as the EPA acknowledged that large leaks from a wellhead could be
detected with AVO. Commenters claimed that the EPA did not provide
adequate justification as to why having two or more wellheads requires
the use of OGI. Industry commenters believe that the NSPS OOOOb and EG
OOOOc BSER for multi-wellhead only sites should be quarterly AVO
inspections only (bimonthly AVO inspections only at most). Another
commenter \227\ similarly expressed that using AVO inspections to find
large fugitive emissions at single wellhead only sites is appropriate
and should also apply to multi-wellhead only well sites. Quarterly AVO
inspections are appropriate to detect fugitive emissions at multi-
wellhead only well sites, according to the commenter. A commenter \228\
stated that wellhead only sites generally have fewer fugitive emissions
components, and wellheads are constructed with thicker, higher-
pressure-rated iron, causing flanges to be larger such that AVO
inspections are able to reliably detect any leaks that may occur. The
commenter believed quarterly AVO inspection of wellhead only sites
would be an effective and economic means to monitor for leaks at
wellhead only sites. Another commenter \229\ expressed support for AVO
for these sites but did not support OGI, due to its cost and because
the incremental benefit of using OGI on top of AVO would not
meaningfully reduce emissions.
---------------------------------------------------------------------------
\226\ EPA-HQ-OAR-2021-0317-2446.
\227\ EPA-HQ-OAR-2021-0317-2428.
\228\ EPA-HQ-OAR-2021-0317-2326.
\229\ EPA-HQ-OAR-2021-0317-2202.
---------------------------------------------------------------------------
Response: The EPA disagrees with the comment that it should have
first evaluated AVO and determined its cost effectiveness and then
assessed whether to add OGI monitoring for multi-wellhead only well
sites and well sites with major production and processing
equipment.\230\ While OGI's superiority
[[Page 16905]]
over AVO is clear, the EPA nevertheless offered a detailed explanation
in the December 2022 Supplemental Proposal (87 FR 74727). As the EPA
explained, AVO is a simple sensory method that can detect large
releases such as emissions from open thief hatches; however, not all
fugitive emissions components have large releases and, therefore, their
emissions cannot always be detected by AVO. AVO's reliability also
depends on other factors, including whether the background noise is
sufficiently low to allow a person to hear leaks such as the hissing
sound from a high-pressure leak, whether the gas is of a mixture that
would allow detection by smell, or whether the leaks result in dripping
or puddles that can be detected visually. In contrast, OGI can reliably
detect fugitive emissions that AVO cannot. Therefore, in the November
2021 Proposal, the EPA proposed monitoring fugitive emissions using OGI
at well sites with baseline emissions at or greater than 3 tpy and no
monitoring for those with baseline emissions below that level; the EPA
solicited comment on ``simple AVO checks that could be performed in
conjunction with the periodic OGI monitoring surveys to help identify
potential large emission events'' (86 FR 63197). In the December 2022
Supplemental Proposal, the EPA proposed four subcategories of well
sites and monitoring regime for each subcategory based on numbers and
types of equipment. For example, single wellhead only well sites have
few pieces of simple equipment and therefore few fugitive emissions
components,\231\ but they have been found to have large emissions that
result from fugitive emissions components, such as an open valve on a
well case casing; because the number of components is small and the
large releases could be detected with AVO, OGI monitoring does not seem
necessary at a single wellhead only well site.\232\ That is not the
case with multi-wellhead only well sites, which are the focus of the
comments summarized above. As the number of wellheads increases, so
does the number of fugitive emissions components, including those
associated with smaller emissions that are difficult to detect with
AVO; however, OGI can detect fugitive emissions from those components
in addition to the large releases. Accordingly, in the December 2022
Supplemental Proposal, the EPA proposed adding AVO monitoring to
routine OGI monitoring requirements in order to identify large
emissions that could occur in between scheduled OGI surveys at multi-
wellhead only well sites and well sites with major production and
processing equipment (see 87 FR 74722).
---------------------------------------------------------------------------
\230\ As explained in the December 2022 Supplemental Proposal
and reiterated later in this response, the EPA did not propose OGI
monitoring for single wellhead only well sites based on information
showing that these emissions are large releases that can be detected
using AVO (87 FR 74729). Similarly, the EPA did not propose OGI
monitoring for a small wellsite; the EPA utilized the same model
results as provided for a single wellhead only well site (87 FR
74731). As defined, a small well site can only include one piece of
certain major production and processing equipment, which cannot be a
controlled storage vessel, a control device, or a natural gas-driven
process controller or pump (Ibid). As such, the equipment and
associated fugitive emissions components at a small site are more
comparable to a single wellhead only well site than to the other two
subcategories of well sites (see Id. at 74726, table 7).
\231\ See Id. at 74726, table 7.
\232\ Id. at 74727.
---------------------------------------------------------------------------
As discussed in the December 2022 Supplemental Proposal, multi-
wellhead only well sites feature both large emission sources that can
be identified with AVO as well as additional, generally smaller sources
of emissions that are more challenging to identify using AVO. In order
to capture both large and small emissions from multi-wellhead only well
sites, the EPA proposed semiannual OGI monitoring and quarterly AVO
surveys for NSPS OOOOb and EG OOOOc. The EPA agrees with commenters
that periodic AVO surveys are less costly than OGI surveys. However,
cost is not the only factor in determining the BSER, and other
considerations, such as effectiveness at reducing emissions from both
large and small releases, must be considered. As part of its BSER
analysis for reducing fugitive emissions at well sites, the EPA
analyzed the costs and emission reductions associated with various
combinations of OGI and AVO monitoring options for the four categories
of well sites. The EPA summarized its analysis for multi-wellhead only
well sites in table 12 and explained how it evaluated the various
options (see 87 FR 74733, table 12). The EPA found semiannual OGI and
quarterly AVO to be cost-effective and therefore to be the BSER for
multi-wellhead only well sites.
d. Subcategorization of Well Sites
Comment: Several commenters requested that the EPA consider
maintaining an exemption for low production wells as it pertains to the
NSPS OOOOb and EG OOOOc. These commenters noted that industry has
consistently advocated for such an exemption in previous rulemakings.
Commenters also asserted that exempting low production wells would
provide meaningful reductions in compliance burden and cost for small
businesses, with minimal potential impact. Commenters \233\ argued that
the proposed monitoring requirements and schedule are excessive for
these sites, provide little environmental benefit, and are prohibitive
for small owners and operators and will result in the end of their
operations. One commenter \234\ noted that the U.S. DOE marginal well
study provides data showing that marginal well sites overwhelmingly
have methane emissions below 3 tpy. One commenter \235\ urged the EPA
to modify the rule to include a production rate threshold that would
exempt wells making less than 6 boe per day. One commenter \236\
recommended that the EPA create an intermediate well site category that
combines production throughput and components, opining that this would
be a simpler approach that avoids inappropriate results. According to
the commenter, under the current proposal, some low-producing sites
would be classified as large sites and be subject to quarterly OGI
monitoring with bimonthly AVO inspections. The commenter asserted that
the data from the U.S. DOE marginal well study shows that this category
of sites has lower total emissions than sites with larger production
volumes and therefore should not be subject to monitoring requirements
as stringent as those for larger-producing sites. The commenter
proposed that intermediate well sites historically considered to be
``low production'' be permitted to utilize industry practices to
identify leaks. The commenter asserted that the EPA's proposal places
an economic burden on owners/operators of low production wells that is
not justified or supported.
---------------------------------------------------------------------------
\233\ EPA-HQ-OAR-2021-0317-2179, -2248, -2310, -2713.
\234\ EPA-HQ-OAR-2021-0317-2403.
\235\ EPA-HQ-OAR-2021-0317-2179.
\236\ EPA-HQ-OAR-2021-0317-2446.
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Response: Following the December 2022 Supplemental Proposal, the
EPA received the underlying dataset for the U.S. DOE marginal well
study, which was previously not available, and the EPA further
evaluated the methane emissions data obtained during the field
campaigns of the U.S. DOE marginal well study. Specifically, in
response to comments that the EPA should have incorporated the DOE
emissions dataset into the FEAST modeling because the baseline
emissions estimated by the EPA were overstated and that lower baseline
emissions should be used, the EPA added U.S. DOE marginal well study
data to the previous FEAST model simulations to evaluate whether this
was the case.
The EPA also evaluated how the leaks measured in the U.S. DOE
marginal well study compared with the leaks measured in the other
studies included in the FEAST model as used to support the supplemental
proposal. The EPA determined that the U.S. DOE marginal
[[Page 16906]]
well study data agrees well with the emissions data included in FEAST
as modeled for the December 2022 Supplemental Proposal when comparing
the different equipment component leak data used. The EPA also ran
several individual monitoring options using the equipment component
data from the December 2022 Supplemental Proposal, using the component
data from the December 2022 Supplemental Proposal augmented with U.S.
DOE marginal well study data, and also using only the U.S. DOE marginal
well study data. The FEAST model was run using these three sets of
equipment component leak input data for multi-wellhead only well sites.
The results demonstrated that varying the specific equipment component
leak input data had minimal impact on the model results, and the FEAST
model simulation results did not vary significantly when U.S. DOE
marginal well study data was included. The full results of the
additional FEAST modeling the EPA performed following the December 2022
Supplemental Proposal are presented in a memorandum \237\ available in
the rulemaking docket. In conclusion, the addition of U.S. DOE marginal
well study data did not show results that are significantly different
than what the EPA presented in the December 2022 Supplemental Proposal.
---------------------------------------------------------------------------
\237\ Memorandum from Jeff Coburn, RTI International. Summary of
Additional FEAST Modeling Runs. September 25, 2023.
---------------------------------------------------------------------------
Moreover, the U.S. DOE marginal well study concludes that the
frequency and magnitude of emissions from well sites are more strongly
correlated with equipment counts than with production rates. See the
EPA's response in section XII.A for additional details and data.
The EPA therefore does not have compelling information that
suggests low production levels at well sites should provide the basis
for adding a new subcategory to the fugitive emissions requirements.
Many factors can affect the profitability of marginal wells and the
decision to shut in and plug a well, making it difficult to determine
the full impact of regulation on the financial status of marginal well
owners, as discussed in chapter 6 of the final rule TSD. While the EPA
does not have data on the distribution of ownership based on firm size,
there are small owners and operators who own marginal oil and natural
gas wells. The EPA remains mindful of how the fugitive emissions
monitoring requirements will affect small entities and describes steps
taken to include regulatory flexibility and streamline recordkeeping
requirements in section 4.4 of the RIA. While developing the fugitive
emissions monitoring program, the EPA limited monitoring,
recordkeeping, and reporting requirements to include only what is
necessary to meet BSER and demonstrate compliance. These streamlined
requirements benefit owners and operators of well sites (including
small entities).
e. Delay of Repair Due to Parts Unavailability
Comment: A commenter \238\ noted that NSPS OOOO and OOOOa allow for
delay of repair beyond a unit shutdown if ``valve assembly supplies
have been depleted, and valve assembly supplies had been sufficiently
stocked before the supplies were depleted.'' The commenter notes that
in the November 2021 Proposal (86 FR 63174), the EPA recognized that
operators of older equipment may experience delays in obtaining
replacement parts. Given current supply chain issues and the larger
number of well sites, centralized production facilities, and compressor
stations, the EPA should expand the current delay-of-repair
requirements to include delays because of parts unavailability.
---------------------------------------------------------------------------
\238\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------
Response: Based on this comment and those summarized later in
section XI.A.2.b on compressor stations, the EPA is allowing delay of
repair of fugitive emissions components due to unavailability of
replacement components (or parts thereof) in certain circumstances at
well sites, centralized production facilities, and compressor stations.
Specifically, delay of repair is allowed if replacement is required but
cannot be acquired and installed within the repair timeline due to
either of the following conditions: (1) replacement valve supplies have
been sufficiently stocked but are depleted at the time of repair; or
(2) a replacement fugitive emissions component or a part thereof
requires custom fabrication. See section XI.A.2.b for our reasons for
allowing delay of repair under these specified conditions, our response
to the major comments on this issue, and additional details on this
provision.
f. Other Changes
The EPA has made certain corrections to the regulatory text of NSPS
OOOOb and EG OOOOc since the December 2022 Supplemental Proposal.
The EPA is correcting the definition of ``major production and
processing equipment'' to add certain equipment that were inadvertently
excluded in the December 2022 Supplemental Proposal. In the preamble to
the December 2022 Supplemental Proposal, the EPA specifically proposed
to identify natural gas-driven pneumatic controllers, natural gas-
driven pneumatic pumps, and control devices as ``major production and
processing equipment'' in the context of defining well site
subcategories for the fugitive emissions monitoring and repair program
of NSPS OOOOb and EG OOOOc and justifying requiring quarterly OGI
monitoring where this equipment is present (87 FR 74723 and 74735).
Following the publication of the December 2022 Supplemental Proposal,
the EPA noticed that the draft regulatory text for NSPS OOOOb and EG
OOOOc accompanying the proposal would have inadvertently adopted,
without change, the definition of ``major production and processing
equipment'' in NSPS OOOOa, which has a different fugitive emissions
monitoring program for well sites than that of NSPS OOOOb and EG OOOOc;
as a result, natural gas-driven pneumatic controllers, natural gas-
driven pneumatic pumps, and control devices were inadvertently excluded
from the definition of ``major production and processing equipment'' in
the proposed NSPS OOOOb and EG OOOOc. The following edits were made to
align the regulatory text with the EPA's intent as stated in the
Supplemental Proposal:
Added ``natural gas-driven pumps'' to the list of major
equipment that puts a well site into the third subcategory (well sites
with major production and processing equipment or centralized
production facilities) at 40 CFR 60.5397b(g)(1)(iv)(C) and 40 CFR
60.5397c(g)(1)(iii)(C);
Added ``natural gas-driven pumps'' to the list of major
equipment that cannot be present at a small well site at 40 CFR
60.5430b and 40 CFR 60.5430c; and
Added ``control devices, natural gas-driven process
controllers, natural gas-driven pumps'' and ``tank batteries'' to the
definition of major production and processing equipment at 40 CFR
60.5430b and 40 CFR 60.5430c.
Similarly, in the December 2022 Supplemental Proposal, the EPA
proposed as part of the fugitive emissions standards and presumptive
standards an equipment standard such that thief hatches and other
openings on a storage vessel that are fugitive emissions components
must remain closed and sealed at all times except during sampling,
adding process material, or attended maintenance operations (87 FR
74731). However, this proposal was not reflected in the
[[Page 16907]]
regulatory text accompanying the December 2022 Supplemental Proposal.
The EPA is finalizing this requirement, which has been added to the
regulatory text (see 40 CFR 60.5397b(g)(1)(ii) and (iv) and 40 CFR
60.5397c(g)(1)(i) and (iii)).
Lastly, the EPA added to the final rules definitions of single
wellhead only well sites and multi-wellhead only well sites at 40 CFR
60.5430b and 40 CFR 60.5430c to avoid confusion.
2. Fugitive Emissions at Compressor Stations
In section X.A.2 of this document, the final NSPS OOOOb and EG
OOOOc requirements for fugitive emissions components at compressor
stations are summarized. The BSER analysis for fugitive emissions
components at compressor stations is unchanged from what was presented
in the December 2022 Supplemental Proposal (see 87 FR 74739-40, section
IV.A.2: OGI Monitoring at Compressor Stations). In the December 2022
Supplemental Proposal, the EPA proposed the BSER as monthly AVO
combined with quarterly OGI (or EPA Method 21) monitoring requirements
for fugitive emissions components affected facilities located at
compressor stations, which would take the form of a work practice
standard. However, significant comments were received on the December
2022 Supplemental Proposal on the following topics: (1) the monthly AVO
monitoring requirement and (2) delay of repair for parts
unavailability. Comments on these topics and the EPA's responses are
discussed here. These comments and the EPA's responses to these
comments generally apply to the standards proposed in both the NSPS
OOOOb and EG OOOOc. The EPA's full response to comments on the November
2021 Proposal and December 2022 Supplemental Proposal, including any
comments not discussed in this preamble, can be found in the EPA's RTC
document for the final rule.\239\
---------------------------------------------------------------------------
\239\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
---------------------------------------------------------------------------
a. Monthly AVO Monitoring
Comment: Some commenters claim that the monthly AVO requirement for
compressor stations is unnecessary. One commenter \240\ indicated that
to require monthly AVO and quarterly OGI or EPA Method 21 monitoring
and recordkeeping is overly burdensome and unnecessary for compressor
stations. This commenter believes that existing equipment and
monitoring methods have proven effective and have minimized emissions,
and believes a baseline threshold for low-volume compressor stations
and periodic AVO inspections and documentation would effectively
achieve the goals of the proposed requirements. Another commenter \241\
argued that, compared to state-of-the-art continuous monitoring
systems, the proposed requirement for monthly AVO inspections and
quarterly OGI inspections provides neither the greatest emissions
reduction nor the most economical solution. This commenter encouraged
the EPA to also allow continuous monitoring technology solutions as the
BSER for compressor stations. On the other hand, a commenter \242\
recommended that monthly AVO inspections in addition to quarterly
instrument-based leak detection and repair inspections should be
required at gathering and boosting and transmission stations.
---------------------------------------------------------------------------
\240\ EPA-HQ-OAR-2021-0317-2211.
\241\ EPA-HQ-OAR-2021-0317-2440.
\242\ EPA-HQ-OAR-2021-0317-2180.
---------------------------------------------------------------------------
Response: For the reasons explained here, the EPA found
unpersuasive those comments suggesting that the proposed fugitive
emissions monitoring requirements at compressor stations, in particular
monthly AVO inspections, are unnecessary or burdensome. As explained in
the December 2022 Supplemental Proposal (87 FR 74739), regular AVO
inspections at compressor stations can be conducted by any staff at the
site without the need for any special expertise. In fact, AVO
inspection was added in the December 2022 Supplemental Proposal in
response to recommendations by some commenters 243 244 on
the November 2021 Proposal recommending AVO as a low-cost method that
is effective at identifying emissions, even for small-company
compressor stations. The commenters specifically noted that even though
small-company compressor stations are not manned 24 hours per day, they
are visited weekly, if not daily. The EPA found the comments persuasive
and did not see a need to confirm the commenters' assertions by
conducting its own cost analysis for conducting monthly AVO inspections
for compressor stations. The EPA notes that no commenter disputed or
otherwise questioned the comments described above regarding the low
cost of AVO monitoring, which the EPA relied upon in its December 2022
Supplemental Proposal. With regard to the comment suggesting that OGI
monitoring is unnecessary because AVO surveys during these frequent
visits would effectively achieve the EPA's emission reduction goals,
the EPA disagrees that AVO surveys alone (i.e., without quarterly OGI
monitoring) qualify as the BSER because OGI is needed to detect
fugitive emissions that are not detectable by AVO. In addition, the EPA
received no information that caused it to change its assessment that
quarterly OGI monitoring at compressor stations is not cost-effective.
Accordingly, the EPA is finalizing its determination that monthly AVO
monitoring and quarterly OGI monitoring, in combination with repair
requirements, represents the BSER for fugitive emissions components at
both new and existing compressor stations.
---------------------------------------------------------------------------
\243\ EPA-HQ-OAR-2021-0317-0585.
\244\ EPA-HQ-OAR-2021-0317-0814.
---------------------------------------------------------------------------
The EPA supports the use of continuous monitoring systems to detect
fugitive emissions at compressor stations. Although at this point the
EPA does not have sufficient information to include this new but
rapidly advancing technology in its BSER analysis, the EPA is
finalizing a pathway for owners and operators to utilize continuous
monitoring technologies at well sites, centralized production
facilities, and compressor stations as part of the advanced methane
detection technology provisions of the rule.
b. Delay of Repair Due to Parts Unavailability
Comment: Several commenters requested that a delay of repair be
allowed when parts are unavailable to do the required repairs and note
that the EPA requested feedback in the November 2021 Proposal (86 FR
63174) on whether to allow delay of repair due to parts unavailability.
One commenter \245\ noted that delay of repair due to unavailability of
valve assembly replacement supplies was included for onshore natural
gas processing plants in the December 2022 Supplemental Proposal, but
questions why it was not included for other natural gas industry
segments that include similar arrays of high-pressure gas valves and
rely on the same types of replacement supplies. Another commenter \246\
notes the same difference and adds that the array of large valves that
require special service for parts or replacement for compressor
stations may be more complicated than at some natural gas processing
plants. Additionally, the same commenter says that supply chain delays
have lengthened delivery times for
[[Page 16908]]
replacement parts and that operators can ensure that replacement parts
are ordered in a timely manner but cannot control how quickly the parts
will arrive. Both commenters discuss the timelines for delivery of
replacement valves, which ranged between 16 and 40 weeks, depending on
size, at the time of the comments.
---------------------------------------------------------------------------
\245\ EPA-HQ-OAR-2021-0317-2366.
\246\ EPA-HQ-OAR-2021-0317-2483.
---------------------------------------------------------------------------
A commenter \247\ also asserted that larger, older compressor
stations were expanded over time with different compressor sizes,
types, and vintages, resulting in a large array of unique valves at
compressor stations. The commenter continued, saying that parts are not
interchangeable between different manufacturers, models, or even
different vintages of the same equipment and that if a part breaks on
an older piece of equipment, the comparable part that is used for new
compressors may not be the right size or configuration for the older
equipment. In such cases, the appropriate parts for that equipment will
need to be custom fabricated; manufacturers do not maintain an
inventory of expensive parts, unique parts, or parts for older
equipment. The commenter estimated that the timeline for custom
fabrication of station valves can require 4 to more than 12 months,
depending on the size and uniqueness of the part. Another commenter
\248\ explained that in their experience, the parts most likely to be
in short supply are large, unique valves used for compressor isolation
or isolating sections of a facility or pipeline; these valves are not
standard items, and they come in many configurations. The commenter
explained that, given the size and unique specifications of each valve,
it is not practical or economical to maintain a significant inventory
of such items. They added that such items may require special
fabrication with lead times of many months. As an example, the
commenter described a recently identified leak on a 16-inch valve. Upon
investigation, they determined that repair (e.g., replacing
subcomponents of the large valve) was not possible and an exact
replacement valve could not be ordered because the valve was obsolete.
Investigation into a new replacement indicated a lead time on the order
of at least 18 weeks.
---------------------------------------------------------------------------
\247\ Id.
\248\ EPA-HQ-OAR-2021-0317-0782.
---------------------------------------------------------------------------
Commenters also recommended that delay of repair due to parts
unavailability should extend to parts other than valves. One commenter
\249\ stated that compression includes an array of parts associated
with the compression driver, the compressor, and associated valving,
piping, and other processing equipment. A valve is one example of a
part type that may not be available for repair or replacement, but
other large, unique legacy parts associated with other legacy process
equipment may need to be machined or more major components may need to
be constructed.
---------------------------------------------------------------------------
\249\ EPA-HQ-OAR-2021-0317-2366.
---------------------------------------------------------------------------
Conversely, another commenter \250\ contended that the availability
of parts is not a valid concern because replacement parts could be
easily procured, and operators could stockpile fugitive emission
components and parts thereof prior to this rule's requirements coming
into effect.
---------------------------------------------------------------------------
\250\ EPA-HQ-OAR-2021-0317-0844.
---------------------------------------------------------------------------
Commenters also responded to the EPA's solicitation of input on the
timeline for repair upon receipt of the part and any associated
documentation. One commenter \251\ suggested that repairs must be
completed within 30 days following the receipt of the replacement part,
provided that conducting the repair would not require a unit or
wellhead shutdown and that, if shutdown was required, the repair should
occur during the next scheduled maintenance shutdown. Similarly,
another commenter \252\ requested that the EPA provide in the
regulatory text that, where no shutdown or blowdown is needed, the
operator should repair the leak within 30 days after receiving the
parts. The commenter requested that where a repair requires a shutdown
or blowdown, the regulatory text allow the repair to be performed
during the next scheduled shutdown for maintenance after receipt of the
requisite parts, not to exceed 2 years. The commenter stated that this
will avoid unnecessary blowdown emissions. One commenter \253\
recommended that the required recordkeeping follow current NSPS OOOOa
criteria, where the operator documents the delay basis and repair
schedule. Another commenter suggested that the operator be required to
support the necessity of delay of repair due to parts unavailability
through rigorous documentation, including but not limited to: a
reasonable explanation of why the operator did not have a spare part on
hand; a justification of why the equipment failure was not foreseeable
at any point from the date of the proposed regulations until the date
of failure; proof that such failures are not common at similar
compressor stations of similar age; maintenance and inspection records
supporting the non-foreseeability of the failure; proof and date that
the replacement part was ordered immediately upon detection; and proof
that the part was installed as quickly as possible upon receipt.
---------------------------------------------------------------------------
\251\ EPA-HQ-OAR-2021-0317-1289.
\252\ EPA-HQ-OAR-2021-0317-0815.
\253\ EPA-HQ-OAR-2021-0317-0782.
---------------------------------------------------------------------------
Response: In response to these comments, the EPA is allowing delay
of repair that requires replacement where the replacement cannot be
acquired and installed within the repair timeline due to either of the
following conditions: (1) Replacement valve supplies have been
sufficiently stocked but are depleted at the time of repair; or (2) a
replacement fugitive emissions component or a part thereof requires
custom fabrication. In either situation, the required replacement must
be ordered within 10 calendar days after the first attempt at repair.
The repair must be completed within 30 calendar days after receipt of
the replacement or during the next scheduled shutdown for maintenance
after the replacement is received (if the repair requires a shutdown).
Operators must document the date the leak was added to the delay-of-
repair list, the date the replacement fugitive emissions component or
part thereof was ordered, the anticipated delivery date, and the actual
delivery date as part of their fugitive emission survey records.
The EPA acknowledges that during the 2016 rulemaking promulgating
NSPS OOOOa and the 2021 amendments, the EPA received comments
requesting that the EPA allow delay of repair due to parts
unavailability. The EPA declined to do so in 2016, explaining that
``[t]he EPA does not agree that unavailability of supplies or custom
parts is a justification for delaying repair (i.e., beyond the 30 days
for repair provided in this final rule) since the operator can plan for
repair of fugitive emission components by having stock readily
accessible or obtaining the parts within 30 days after finding the
fugitive emissions.'' 81 FR 35824, 35858. In 2021, the EPA similarly
expressed that it ``does not agree a lack of parts is a sufficient
justification to delay.'' \254\
---------------------------------------------------------------------------
\254\ Oil and Natural Gas Sector: Emission Standards for New,
Reconstructed, and Modified Sources Reconsideration 40 CFR part 60,
subpart OOOOa, Response to Public Comments on Proposed Rule (83 FR
52056, October 15, 2018), at 8-199.
---------------------------------------------------------------------------
However, regarding the comment noting that the standards (and
presumptive standards) for onshore natural gas processing plants in the
proposed NSPS OOOOb and EG OOOOc would have allowed delay of valve
repair due to depletion of valve supplies and requesting that the EPA
allow the same in the fugitive emissions standards
[[Page 16909]]
for well sites and compressor stations, the EPA concludes that well
sites and compressor stations face some of the same valve assembly
supply constraints as onshore natural gas processing plants and that
operators can ensure timely ordering of replacement fugitive components
or parts thereof but cannot control replacement delivery timelines.
Thus, the EPA is including similar delay-of-repair provisions for valve
assembly supplies that had been sufficiently stocked but are depleted
at the time of the required repair for wellsite and compressor station
fugitives as for onshore natural gas processing plants in this rule.
The final fugitive emissions standards for well sites and compressor
stations under NSPS OOOOb (and presumptive standards under EG OOOOc)
allow delay of repair due to depletion of supplies for valves only.
This is consistent with the standards for onshore natural gas
processing plants, which have provided such allowance for valves only
since the standards were first promulgated in 1985, and the EPA has not
received information showing difficulty of repair due to well-stocked
supplies of other fugitive emissions components or parts thereof that
were depleted before repair could be completed.
In addition to allowing delay of repair of valves due to depletion
of supplies as described above, the final rule allows delay of repair
where repair requires replacement of a custom-made fugitive emissions
component or a part thereof. The comments on the November 2021 Proposal
and December 2022 Supplemental Proposal also include supporting
information on exceptional, infrequent circumstances where a
replacement part requires custom fabrication. Specifically, the
information includes insight into the quantity and variety of vintage
equipment at compressor stations, the unlikelihood of manufacturers'
stocking replacement parts for vintage equipment and thus the need for
custom fabrication of replacement supplies, and the timeline for
fabrication and delivery of custom supplies. Recent examples of
extensive supply chain delays have highlighted that a delay of repair
may be needed for circumstances beyond an owner or operator's
control.\255\ In light of the information on the challenges and the
time needed to acquire parts that require custom fabrication and the
current supply chain issue, we are including in the final NSPS OOOOb
and the model rule in EG OOOOc provisions for delay of repair where
replacement is required and the replacement fugitive emissions
component or a part thereof requires custom fabrication. As described
above, for delay of repair under either of the two specified
conditions, the final rule prescribes specific timeframes for ordering
and installing the parts to ensure that repair is completed in a timely
manner, as well as the specific records that must be kept to
demonstrate compliance with these requirements.
---------------------------------------------------------------------------
\255\ EPA-HQ-OAR-2021-0317-2483.
---------------------------------------------------------------------------
B. Advanced Methane Detection Technology Work Practices
In the December 2022 Supplemental Proposal, the EPA proposed a
revised alternative fugitive emissions monitoring and repair program
for new, modified, or reconstructed fugitive emissions sources (i.e.,
collection of fugitive emissions components located at well sites,
centralized production facilities, and compressor stations). This
program was intended to provide owners and operators with the
flexibility to use advanced methane detection technologies in lieu of
the ground-based OGI and AVO surveys that the EPA had proposed for
fugitive emissions sources. Among other things, the December 2022
Supplemental Proposal included a proposed ``matrix'' that would specify
different screening frequencies corresponding to a range of minimum
detection thresholds, in contrast to the single screening frequency and
detection level proposed in the November 2021 Proposal. In addition,
the EPA proposed to allow owners and operators the option of using
continuous monitoring technologies as another alternative to ground-
based OGI and AVO surveys and proposed long- and short-term emission
rate thresholds that would trigger corrective action. The EPA also
proposed monitoring plan requirements for owners and operators that
chose to implement the alternative fugitive emissions monitoring
approach and proposed a clear and streamlined pathway for technology
developers and other entities to seek the EPA's approval for the use of
advanced methane detection technologies under this alternative option.
This section of this document presents a summary of significant
comments received on advanced methane detection technologies and the
EPA's response to those comments, as well as certain changes in the
final standards for using advanced methane detection technologies for
monitoring fugitive emissions components at new and existing facilities
and for conducting continuous inspection and monitoring for covers and
closed vent systems. For other comments on the proposed program and the
EPA's response thereto, see chapter 5 of the RTC document, Advanced
Methane Detection Technologies.\256\ For final standards and
requirements that have not changed since the December 2022 Supplemental
Proposal, the supporting rationales are not reiterated in this
preamble. The rationale for those standards and requirements can be
found in section IV of the preamble for the December 2022 Supplemental
Proposal (87 FR 74702 at 74722-810, December 6, 2022).
---------------------------------------------------------------------------
\256\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
---------------------------------------------------------------------------
1. Periodic Screening
a. Matrix Table and Screening Frequency
Comment: The EPA received considerable support for the flexibility
to use advanced methane detection technologies in lieu of using OGI,
EPA Method 21, or AVO to monitor fugitive emissions components in
response to the December 2022 Supplemental Proposal. One commenter
\257\ supported the proposed frequencies in the matrix, noting that
their independent equivalency modeling matched the results of the EPA's
FEAST modeling across a variety of scenarios, and supported the EPA's
choices of model inputs that made assumptions based on nationally
applicable factors and considerations, as these inputs apply across the
country to sources in different oil and gas producing regions and
basins. Other commenters 258 259 raised concerns that the
EPA's FEAST modeling overestimates the effectiveness of AVO and OGI,
resulting in matrix frequencies that are overly stringent. Another
commenter \260\ discussed the potential use of an alternative emission
rate distribution in the model, from a study that included a larger
range of emission rates than was used in the EPA's modeling.
---------------------------------------------------------------------------
\257\ EPA-HQ-OAR-2021-0317-2433.
\258\ EPA-HQ-OAR-2021-0317-2387.
\259\ EPA-HQ-OAR-2021-0317-2428.
\260\ EPA-HQ-OAR-2021-0317-2405.
---------------------------------------------------------------------------
A commenter \261\ considered the minimum detection thresholds and
monitoring frequencies in the proposed matrix to be insufficiently
differentiated between the tiers with respect to detection levels.
Several
[[Page 16910]]
commenters 262 263 raised concern that the 30 kg/hr periodic
screening tier provides a less stringent work practice for emissions
reduction and urged the EPA to remove the 30 kg/hr detection tier.
---------------------------------------------------------------------------
\261\ EPA-HQ-OAR-2021-0317-1686, -2345.
\262\ EPA-HQ-OAR-2021-0317-2405.
\263\ EPA-HQ-OAR-2021-0317-2430.
---------------------------------------------------------------------------
Another commenter \264\ stated that advanced methane detection
technologies are evolving rapidly and are a key component of the
commenter's strategy for broader emission reductions. The commenter
believed that these technologies have the potential to be more
effective at finding leaks on a broader scale, allowing for faster
detection and mitigation, leading to a greater reduction in methane
emissions. This commenter was concerned that there may be inadvertent
disincentives that are contrary to the intent of the EPA, which is to
encourage innovation resulting in meaningful emissions reductions. The
commenter was concerned that disincentives may encourage operators to
simply continue their existing OGI survey programs as the default
option, which could hinder broad development and adoption of advanced
methane detection technologies.
---------------------------------------------------------------------------
\264\ EPA-HQ-OAR-2021-0314-2360.
---------------------------------------------------------------------------
Response: Regarding the modeling conducted to develop the periodic
screening matrices in the December 2022 Supplemental Proposal, while
the EPA acknowledges there are alternative inputs available for the
models, we incorporated the best available information from recent
studies to characterize a distribution for both common leaks and super-
emitters. The results of our fugitive emissions modeling fell within
the ranges observed in other literature assessments. As mentioned
above, we received supportive comments for our modeling. The commenters
who expressed otherwise provided limited additional peer-reviewed data
with which we could revise our model assumptions; much of the data
focused on studies collected using a singular technology (e.g., aerial
survey), and the emission distribution appeared to be weighted toward
emissions this specific methane detection technology could identify.
While the EPA's emission distribution in our model also was developed
using studies conducted with aerial surveys, we augmented that
distribution with ground-level studies to get a more complete emission
distribution, including the lower-level emissions. Therefore, we
believe the results from the modeling conducted for the December 2022
Supplemental Proposal are well-supported.
With the continued development and deployment of advanced methane
detection technology, we expect further study on the distribution of
methane emissions from this sector, in particular after promulgation of
this rule providing a pathway for the use of advanced technologies. As
additional studies are conducted on emission distributions across this
sector, it is possible that the underlying emissions rate distribution
in our modeling could potentially be updated in the future. However,
the inputs in the modeling conducted for the December 2022 Supplemental
Proposal were based on the best information available to the EPA during
this rulemaking. Therefore, we continue to believe that the modeling
results are well-supported and appropriate for the development of the
periodic screening matrices.
In this final rulemaking, the EPA finalized the proposed matrices
tables (tables 3 and 4 in NSPS OOOOb and EG OOOOc) with some
adjustments in response to comments. Several commenters questioned
whether an annual OGI survey is necessary in order for the use of
certain periodic screening technologies to be equivalent to the
fugitive emissions monitoring requirements discussed in section XI.A of
this document. Based on the comments we received, the EPA reviewed the
modeling results, reexamined the effectiveness of an annual OGI survey
on the matrix tiers, and evaluated the uncertainty in the modeling
results. We found that for the lower tiers of the matrix tables
(corresponding to the most sensitive advanced methane detection
technologies), the effectiveness of the annual OGI survey in reducing
methane emissions in the FEAST model was minimal. Further, we found
that at the highest tiers of the matrix (corresponding to the least
sensitive advanced methane detection technologies), the annual OGI
survey accounted for the bulk of the modeled emission reductions, and
the periodic screening itself yielded relatively small reductions in
emissions. Based on this additional review, we are revising the
periodic screening matrices tables in the final rule by removing the
proposed highest tier corresponding to the least sensitive technologies
(<=30 kg/hr) and by removing the proposed requirement to conduct an
annual OGI survey at the lowest detection threshold tier (i.e., 1 kg/
hr) in table 1 (which applies to well sites, centralized production
facilities, and compressor stations subject to AVO inspections with
quarterly OGI monitoring surveys). We have also made a small adjustment
in the monthly survey.
The EPA is finalizing the proposed matrices (with some adjustments
as described above), which the EPA believes reflect at least the same
levels of emission reductions as those from complying with the required
fugitive emissions work practice standards for well sites, centralized
production facilities, and compressor stations. In addition, in
response to comments on the importance of incentivizing the use of
advanced methane detection technologies, the EPA is including in the
final rule an interim matrix in lieu of table 1 that will apply for the
next 2 years. The EPA agrees with the comments that advanced methane
detection technologies have the potential to be more effective at
finding leaks more quickly than traditional ground-based fugitive
emission surveys; therefore, it is important to develop a framework
that encourages innovation and the continued development of advanced
methane detection technologies. The EPA acknowledges that these
technologies will only continue to develop if owners and operators have
a desire to implement them. Based on our current understanding of the
state of advanced methane detection technologies, while there are some
technologies that can measure at the lowest detection threshold levels
in the periodic screening matrices under certain conditions, we
currently do not have available data on any technologies that can
achieve these minimum detection thresholds at all sites and in all
conditions. Because these technology developers have had less than a
year (since publication of the December 2022 Supplemental Proposal) to
understand and test the proposed target detection thresholds the
technologies need to meet, there has not been adequate time to develop
data that push the detection thresholds down to the lowest levels of
the proposed periodic screening matrix (at 1 to 2 kg/hr). For the
reason explained above, it is understandable that there may be some
reluctance at this time to use such technologies to comply with NSPS
OOOOb at these very low detection thresholds until more data is
generated to confirm their detection capabilities. We believe that, if
given opportunities to use the advanced technologies, over time users
will show that these technologies can meet the minimum detection
thresholds in these lowest levels of the periodic screening matrix in
table 1. We therefore agree with the commenter that it is
[[Page 16911]]
critically important to incentivize the early adoption of these
alternative technologies. To that end, as part of the final rule, we
have developed an interim periodic screening that will apply in lieu of
the matrix table for well sites, centralized production facilities, and
compressor stations subject to AVO inspections with quarterly OGI
monitoring surveys (table 1 in NSPS OOOOb) for the next 2 years (i.e.,
until March 9, 2026). Under this interim periodic screening matrix, the
lowest detection threshold is <=3 kg/hr, and it requires quarterly
screening frequency. While we are increasing the minimum detection
threshold to <=3 kg/hr in this interim 2-year period to incentivize the
use of advanced technologies, the EPA expects that these technologies
will be able to achieve much better (i.e., lower) detection thresholds
in many use cases, which will be reflected in the records once a
technology has been approved by the EPA as an alternative and deployed
for purposes of NSPS OOOOb. At the end of the interim 2-year period,
the periodic screening matrix in table 1 of NSPS OOOOb, which sets
survey frequencies for lower detection thresholds (<=1 kg/hr and <=2
kg/hr), will apply. The EPA has chosen not to provide an interim
periodic screening in lieu of the matrix table for well sites,
centralized production facilities, and compressor stations subject to
AVO inspections with semiannual OGI monitoring surveys (table 2 in NSPS
OOOOb). The periodic screening matrix for these sources already allows
using an advanced methane detection technology with a detection
threshold of <5 kg/hr level. Because we anticipate owners and operators
will conduct the screenings of all their sites (those subject to table
1 and those subject to table 2) on the same schedule and table 2
already accommodates the interim periodic screening level for table 1,
EPA has determined that it is unnecessary to create an interim periodic
screening for sites subject to table 2.
Comment: Several commenters 265 266 asked that the EPA
allow NSPS OOOOa sources to comply with the advanced methane detection
technology provisions in NSPS OOOOb. One of these commenters requested
that the EPA consider mechanisms to enable sources subject to NSPS
OOOOa to demonstrate compliance with the fugitive emission requirements
in NSPS OOOOa using any advanced methane detection technologies
approved in NSPS OOOOb prior to the effective date of state or Tribal
plans approved under EG OOOOc. Another commenter raised concerns that
the time needed to seek approval to use these advanced methane
detection technologies for existing sources through the AMEL process
and EG OOOOc state plan implementation could take years.
---------------------------------------------------------------------------
\265\ EPA-HQ-OAR-2021-0317-2430.
\266\ EPA-HQ-OAR-2021-0317-2428.
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Response: The EPA agrees with the suggestion to allow a mechanism
outside of the AMEL process to allow existing facilities subject to
NSPS OOOOa to use advanced methane detection technologies. We agree
that a comprehensive periodic screening program that uses an advanced
methane detection technology approved by the EPA under NSPS OOOOb in
which all the emissions detected are repaired in accordance with NSPS
OOOOb will result in emission reductions similar to or better than the
reductions under the existing fugitive emissions work practice at well
sites and compressor stations in NSPS OOOOa. However, the periodic
screening matrices in NSPS OOOOb and in EG OOOOc reflect the overall
fugitive emissions reductions equivalent to the reductions that would
be achieved for that site in the standard fugitive emissions work
practice using OGI and AVO under NSPS OOOOb (and presumptive standards
under EG OOOOc), which includes equipment not included in the
definition of ``fugitive emissions component'' in NSPS OOOOa. The EPA
can only determine that the same or better emission reductions are
achieved if an owner or operator complies with the advanced methane
detection technology work practices in NSPS OOOOb by repairing all
fugitive emissions, including emissions from equipment not included in
the definition of ``fugitive emissions component'' in NSPS OOOOa, such
as uncontrolled tanks, and performing required investigative analyses.
Therefore, as discussed in section IX.C of this preamble, we are
amending the regulatory text in NSPS OOOOa to include a provision that
compliance with the advanced methane detection technology work
practices approved under NSPS OOOOb will be deemed compliance with the
applicable fugitive emissions standards for the same facility in NSPS
OOOOa.
b. Technology Flexibility
Comment: Commenters 267 268 encouraged the EPA to
incorporate a pathway into the final rule to allow for the use of a
combination of technologies, both traditional and advanced, to achieve
equivalent emissions reductions. The EPA received several comments
requesting additional flexibility in the matrix, including the
allowance to use multiple technologies at a single site in a layered or
tiered fashion. Commenters \269\ were concerned that by not conducting
equivalency modeling for a combination of alternative technologies, the
proposed matrix would fail to provide sufficient flexibility for owners
and operators that find it necessary to apply multiple advanced
technologies due to equipment limitations, operating conditions, or
economic factors. Several commenters 270 271 discussed that
the matrix should account for the occasional need to deploy different
monitoring technologies due to seasonal environmental conditions,
noting that inclement weather, including wind, rain, and ground snow
cover, can adversely affect methane detection performance. A commenter
recommended allowing OGI surveys during the months when advanced
detection technologies cannot be deployed.
---------------------------------------------------------------------------
\267\ EPA-HQ-OAR-2021-0317-2360.
\268\ EPA-HQ-OAR-2021-0317-2388.
\269\ EPA-HQ-OAR-2021-0317-2391.
\270\ EPA-HQ-OAR-2021-0317-2405.
\271\ EPA-HQ-OAR-2021-0317-2235.
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Some commenters \272\ suggested that continuous monitoring
technologies may fit within the periodic screening framework and urged
the EPA to consider such technologies within that context. Another
commenter recommended that continuous monitoring be incorporated with
periodic screening to create a single framework for alternative methane
detection technology.
---------------------------------------------------------------------------
\272\ EPA-HQ-OAR-2021-0317-2448.
---------------------------------------------------------------------------
Response: The EPA agrees that the rule should allow for the use of
multiple technologies at a single site and finds that this approach
would provide valuable flexibility for owners and operators while
continuing to achieve a degree of monitoring performance that is
equivalent to the fugitive emissions monitoring requirements in this
rule. Therefore, in the final rule we are allowing the use of one or
more alternative test methods for advanced methane detection technology
to conduct periodic screening. The frequency for conducting periodic
screening events will be based on the methane detection technology with
the highest sensitivity. For example, if an owner or operator uses
methane detection technology with a detection threshold of <=10 kg/hr,
the owner or operator may choose when conducting bimonthly screening
events to use any methane detection technology with a detection
threshold of <=10 kg/hr. We also agree that environmental
[[Page 16912]]
conditions can adversely affect some methane detection technologies. In
the final rule we allow the owner or operator to conduct an OGI survey
in place of a periodic screening event at any time. The planned use of
multiple technologies, including OGI, must be incorporated into the
site-specific monitoring plan.
The EPA also agrees that continuous monitoring technologies can fit
within the periodic screening framework, especially those technologies
that may not be able to comply with the requirements in the continuous
monitoring framework. While it was not explicitly stated in the
December 2022 Supplemental Proposal, we intended for continuous
monitoring technology to be considered as a candidate for the periodic
screening approach. The EPA continues to consider the periodic
screening approach a valid pathway for continuous methane detection
technology.
c. Spatial Resolution
Comment: Several commenters 273 274 discussed that some
measurement technologies have tighter spatial resolution which may
enable the detection of equipment-specific emissions, and as such, use
of these technologies may not require a follow-up OGI survey of the
entire site. One commenter mentioned that one may be able to
conclusively identify the fugitive emissions component with certain
measurement technologies. Another commenter \275\ urged the EPA to
require follow-up OGI surveys only within the general area of detection
from a periodic screening event.
---------------------------------------------------------------------------
\273\ EPA-HQ-OAR-2021-0317-2406.
\274\ EPA-HQ-OAR-2021-0317-2366.
\275\ EPA-HQ-OAR-2021-0317-2432.
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Response: The EPA finds these comments compelling and in the final
rule is incorporating the concept of spatial resolution of measurement
technology into the follow-up actions an owner or operator must take
when a periodic screening event results in a confirmed detection. We
have included three classifications for spatial resolution in the final
rule: (i) facility-level spatial resolution, meaning an alternative
test method with the ability to identify emissions within the boundary
of a well site, centralized production facility, or compressor station;
(ii) area-level spatial resolution, meaning a technology with the
ability to identify emissions within a radius of 2 meters of the
emissions source; and (iii) component-level spatial resolution, meaning
a technology with the ability to identify emissions within a radius of
0.5 meters of the emissions source. Entities requesting an alternative
test method for advanced methane measurement technology would identify
and verify the spatial resolution of the measurement technology as part
of the request.
In the final rule, for periodic screening events conducted with
technologies that have facility-level spatial resolution, we have
maintained the follow-up actions an owner or operator must take in
response to a confirmed detection that were outlined in the December
2022 Supplemental Proposal. However, for periodic screening events
conducted with technologies that have area-level or component-level
spatial resolution, we have targeted the follow-up actions the owner or
operator must take. The follow-up monitoring that must be conducted for
a confirmed detection during a periodic screening event using a
technology with area-level spatial resolution includes a monitoring
survey of all the fugitive emissions components located within a 4-
meter radius of the location of the confirmed detection and, if the
confirmed detection occurred in a portion of a site with a storage
vessel or closed vent system, inspection of all covers and closed vent
systems that are connected to all storage vessels and closed vent
systems that are within a 2-meter radius of the location. The follow-up
monitoring that must be conducted for a confirmed detection during a
periodic screening event using a technology with component-level
spatial resolution includes a monitoring survey of all the fugitive
emissions components located within a 1-meter radius of the location of
the confirmed detection and, if the confirmed detection occurred in a
portion of a site with a storage vessel or closed vent system,
inspection of all covers and closed vent systems that are connected to
all storage vessels and closed vent systems that are within a 0.5-meter
radius of the location. The EPA is requiring inspection of the entire
closed vent system in order to identify a potential cause of the
failure. The EPA has also incorporated the requirement to verify the
spatial resolution of a measurement technology as part of the
alternative test method provisions.
d. Root Cause Analysis
Comment: Several commenters 276 277 supported the
requirement that an owner or operator investigate the source and
cause(s) of significant emissions found through periodic screening
events. However, many commenters took exception to the proposed use of
``root cause analysis'' for investigating potential causes of
emissions. One commenter \278\ noted that the concept of ``root cause
analysis'' is embedded in numerous other regulatory and non-regulatory
programs and has varied meaning and purpose in each application.
Another commenter \279\ asserted that the phrase ``root cause
analysis'' has connotations that lead to a much more involved process
than the EPA appears to envision in this rule. Many of these commenters
suggested that ``root cause analysis'' be replaced by ``investigative
analysis,'' broadly meaning the owner or operator must determine what
caused the emissions event to occur and take steps to ensure that it
will not happen again.
---------------------------------------------------------------------------
\276\ EPA-HQ-OAR-2021-0317-2428.
\277\ EPA-HQ-OAR-2021-0317-2363.
\278\ EPA-HQ-OAR-2021-0317-2402.
\279\ EPA-HQ-OAR-2021-0317-2298.
---------------------------------------------------------------------------
Response: The EPA agrees with the concern raised by commenters and
in the final rule requires an investigative analysis as opposed to a
root cause analysis. For the purpose of this final rule, an
investigative analysis is the determination of the underlying primary
and other contributing cause(s) of the emissions event. For a control
device, the investigative analysis must include a determination that
the control device is operating in compliance with the applicable
requirements, and if not, what actions are necessary to bring the
control device into compliance and prevent future failures of the
control device from the same underlying cause(s). For a cover or closed
vent system, the investigative analysis must include a determination of
whether the system was operated outside of the engineering design
analysis and whether updates are necessary for the cover or closed vent
system to prevent future emissions from the cover or closed vent
system.
2. Continuous Monitoring
a. Continuous Monitoring System Criteria
Comment: Several commenters 280 281 requested that the
framework for continuous monitoring set action levels based on the
concentration of emissions as an alternative to the action levels based
on the mass rate of emissions in order to allow owners and operators to
use a broader range of continuous monitoring systems. One commenter
\282\ supported the EPA's inclusion of health checks for devices within
the continuous monitoring system but
[[Page 16913]]
suggested that the health checks rely on functionality instead of
connectivity. Several commenters \283\ requested more flexibility as to
how often these systems must transmit data. Other commenters \284\
contended that flexibility in the downtime requirement is necessary, as
typical downtime can be 4 or more days per month for remote locations.
---------------------------------------------------------------------------
\280\ EPA-HQ-OAR-2021-0317-2340.
\281\ EPA-HQ-OAR-2021-0317-2235.
\282\ EPA-HQ-OAR-2021-0317-2363.
\283\ EPA-HQ-OAR-2021-0317-2248.
\284\ EPA-HQ-OAR-2021-0317-2409.
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Response: The EPA agrees that it is important to facilitate the use
of a broad range of continuous monitoring systems in the advanced
methane detection technology provisions of this rule, because they
allow more rapid detection of leaks and thus an enhanced ability to
promptly respond and prevent emissions. As such, we have expanded the
definition of a continuous monitoring system to allow systems beyond
those that determine mass emission rate only by noting these systems
must determine the ``mass emission rate or equivalent.'' The EPA also
agrees with the commenter that the health checks of the system can be
based on function rather than connectivity and that more flexibility in
the transmission of data is appropriate. In the final rule we require
data to be transmitted at least once every 24 hours.
The EPA does not agree that additional flexibility in the downtime
requirements is appropriate, even for remote locations. In order to
demonstrate that a continuous monitoring system is equivalent to the
required OGI/AVO monitoring for fugitive emissions component affected/
designated facilities, it is important for these systems to collect and
analyze data with a limited amount of downtime. If the downtime is too
great, we cannot ensure that the emissions reductions achieved by the
alternative continuous monitoring method are equivalent to those from
the work practice that has been determined to be BSER. If a continuous
monitoring system cannot meet the operational downtime in the final
rule and an owner or operator does not want to conduct surveys with OGI
or EPA Method 21, the owner or operator may choose to use a continuous
monitoring system that does meet the downtime requirement in the rule
or may choose to use the alternative periodic screening option.
b. Detection Threshold
Comment: Several commenters 285 286 did not agree with
the requirement in the December 2022 Supplemental Proposal that
continuous monitoring systems be capable of measuring emissions at an
``order of magnitude'' lower than (i.e., 1/10 of) the proposed action
levels. One commenter \287\ mentioned that this requirement is overly
prescriptive and appears to be technology-specific rather than outcome-
based and technology-agnostic.
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\285\ EPA-HQ-OAR-2021-0317-2235.
\286\ EPA-HQ-OAR-2021-0317-2333.
\287\ EPA-HQ-OAR-2021-0317-2336.
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Response: The EPA agrees with the commenters and in the final rule
requires a detection threshold of 0.40 kg/hr (0.88 lb/hr) above a
baseline, which is based on one-third the action level. The
requirements in the December 2022 Supplemental Proposal were based on
the method detection limit requirements for alternative test methods in
the fenceline monitoring program in the refinery rule.\288\ Requiring
alternative measurement technologies used in the refinery fenceline
monitoring program to measure an order of magnitude below the action
level is appropriate because in that program, the difference between
the high and low sample results during a measurement period are used to
calculate the site's benzene concentration difference; therefore it is
important to be able to differentiate the low-concentration
measurements for benzene we expected around some refineries. In this
final rule, the requirement for technology to be able to detect methane
an order of magnitude below the action level is unnecessarily
restrictive for real-time systems measuring methane mass emission
rates, which may use concentration, meteorology, and modeling to
calculate these rates, all of which have uncertainty built into the
detection limit. Because these systems will be measuring a mass
emission rate and not a concentration difference, it is less important
to differentiate between the measurements across the site. It is only
important that the technology be able to measure methane at background
levels in order to be able to develop a site-specific baseline for
methane, and methane is ubiquitous in the atmosphere at levels that
should not present a concern for detection. For these reasons, we are
requiring continuous monitoring alternative methane detection
technologies to have a sensitivity of one-third of the lowest action
level, 0.4 kg/hr (0.88 lb/hr). We note this requirement is also
consistent with the EPA's approach for setting emission limits that are
at least three times the representative detection limit. Such an
approach ensures that the standard is at a level that addresses
measurement variability and is in a range that can be measured with
reasonable precision. Requiring the detection limit of continuous
monitoring technologies to be at least one-third of the action level
will ensure that measurements made near the action level are of
reasonable precision.
---------------------------------------------------------------------------
\288\ 40 CFR 63.658(k)(3).
---------------------------------------------------------------------------
c. Site-Specific Emissions Baseline
Comment: Several commenters \289\ raised concerns over the long-
term 1.2 or 1.6 kg/hr action levels, because these emission rates are
well below the baseline emissions for many sites. Other commenters
290 291 believed it critical that the follow-up response
actions are tied not to detection limits but to action levels and that
those action levels be levels that account for the site's baseline
emission rates. One commenter \292\ noted that other regulated sources
can contribute to substantial temporal variability in the baseline
emission rate and provided the example of methane slip from gas-fired
compressors, which can vary depending on compressor operating setpoints
and maintenance. An additional commenter \293\ suggested that the
concept of a baseline be used to establish an emissions profile and
action levels be incremental to that baseline. The commenter further
suggested that since the baseline is meant to capture normal emissions
from the facility, while responses to the long-term and short-term
action levels are meant to reduce fugitive emissions, the baseline
period should be 90 days.
---------------------------------------------------------------------------
\289\ EPA-HQ-OAR-2021-0317-2433.
\290\ EPA-HQ-OAR-2021-0317-2346.
\291\ EPA-HQ-OAR-2021-0317-2433.
\292\ EPA-HQ-OAR-2021-0317-2333.
\293\ EPA-HQ-OAR-2021-0317-2307.
---------------------------------------------------------------------------
Response: The EPA agrees that the action level should be
incremental to the site-specific baseline emissions. In the final rule,
we are revising the action level to be a mass emission rate that is
above the site-specific baseline emissions. Based on the
recommendations of the commenters, we are also establishing
requirements for how and when the determination of the site-specific
baseline is performed. The baseline emissions must be established after
the initial installation of a continuous monitoring system or when
there is a major change in the processing equipment at the site. The
owner or operator must inspect and repair all fugitive components,
covers, and closed vent systems and verify that control devices are in
compliance with applicable requirements prior to starting the baseline
determination period.
The EPA disagrees with the suggested 90-day baseline period. We
consider 30
[[Page 16914]]
days sufficient time to measure the variability of a site. Therefore,
the baseline emissions are determined as the mean emission rate for 30
operating days, minus any time periods where maintenance events are
conducted. This site-specific baseline emission rate must be no more
than 10 times the site's applicable 90-day action level (i.e., 16 kg/hr
for well sites with major production and processing equipment
(including small well sites), centralized production facilities, and
compressor stations, or 12 kg/hr for wellhead only well sites).
d. Mass Emission Rate Reduction Plan
Comment: One commenter \294\ mentioned that the December 2022
Supplemental Proposal was not clear on how operators would deal with
subsequent increases to the rolling average if corrective action had
already been taken for the initial event.
---------------------------------------------------------------------------
\294\ EPA-HQ-OAR-2021-0317-2326.
---------------------------------------------------------------------------
Response: The EPA agrees with the commenter that the December 2022
Supplemental Proposal was not clear on how to handle this situation. In
the final rulemaking, owners and operators who conduct continuous
monitoring with advanced methane detection technologies will initially
(prior to conducting continuous monitoring) develop a site-specific
baseline that accounts for normal process fluctuations. This site-
specific baseline will be subtracted from the monitored emissions when
determining whether there is an exceedance of an action level. As such,
the EPA anticipates that there should not be instances where the
rolling average emissions continue to increase once the primary and
underlying causes of the original exceedance of the action level is
addressed.
3. Alternative Test Method
a. Administrator Delegation
Comment: Several commenters \295\ expressed that the alternative
test method approval process should enable expeditious and thorough
review of advanced technologies. An additional commenter \296\
supported the EPA's proposal to allow operators to utilize the matrix
to comply with CAA section 111(h)(l) and to approve alternative test
methods under 40 CFR 60.8(b)(3), as this process enables operators to
deploy technologies meeting the specifications of the matrix and
encourages greater use of alternative technologies that can better
detect emissions, resulting in greater emission reductions.
---------------------------------------------------------------------------
\295\ EPA-HQ-OAR-2021-0317-2355.
\296\ EPA-HQ-OAR-2021-0317-2342.
---------------------------------------------------------------------------
Response: The EPA agrees that the alternative test method review
process should be expeditious without sacrificing thoroughness. To that
end, the EPA proposed a process for approving alternative test methods
in 40 CFR 60.5398b(d), which is similar to the process in 40 CFR
60.8(b)(3) but specifically tailored towards the types of advanced
technologies that are in use or under development in the oil and
natural gas sector.
b. Super-Emitter Technology
Comment: The EPA received several comments 297 298 on
the December 2022 Supplemental Proposal regarding the lack of criteria
for remote sensing technologies used in the Super Emitter Program. One
of these commenters believed these criteria should be based on the same
proposed tenets as those for the advanced methane detection
technologies, including detection limits based on a probability of
detection curve and quantification accuracy. Another commenter stated
that the EPA should use the alternative test method approval process to
approve technologies for use in the Super Emitter Program. Another
commenter \299\ maintained that third parties who are certified under
the Super Emitter Program should not face a higher barrier to
monitoring than operators themselves.
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\297\ EPA-HQ-OAR-2021-0317-2366.
\298\ EPA-HQ-OAR-2021-0317-2483.
\299\ EPA-HQ-OAR-2021-0317-2433.
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Response: The EPA agrees with these comments. In this final rule,
the EPA has included provisions to approve technologies used in the
Super Emitter Program in 40 CFR 60.5398b(d), which are the same
provisions that will be used to approve alternative methane detection
technologies used by owners and operators. The EPA pre-approving the
remote sensing technologies used by third parties under the Super
Emitter Program will provide additional confidence in the data being
provided by the third parties to the EPA, which will allow for
expedited review of the data and help to ensure the data provided to
the owner or operator is accurate and actionable.
c. Request for Alternative Test Methods
Comment: One commenter \300\ requested we remove the requirement
that an alternative test method, such as a continuous monitoring
system, must be ``commercially available'' to be approved for use under
the rule, as this unintendedly prevent in-house technology developed by
an owner or operator from being used. Several commenters
301 302 requested that the EPA clarify the information
companies must include in a request for an alternative test method. One
commenter added that this clarification is necessary to support the
EPA's ability to efficiently review and approve complete applications
that demonstrate equivalent or better methane detection and reductions.
Another commenter \303\ suggested that technology vendors include proof
of results in their applications, including an accredited third party's
validation, as they relate to detecting methane leak events, including
field-proven evidence and technology validation accurately capturing
events for a given range of detection and quantification thresholds.
Several commenters requested that the EPA clarify what is meant by
commercial availability of alternative leak detection technologies.
---------------------------------------------------------------------------
\300\ EPA-HQ-OAR-2021-0317-2409.
\301\ EPA-HQ-OAR-2021-0317-2348.
\302\ EPA-HQ-OAR-2021-0317-2226.
\303\ EPA-HQ-OAR-2021-0317-2340.
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Response: Based on the comments received, in the final rule the EPA
has changed the term describing the alternative technology from
``commercially available'' to ``readily available.'' We have also
provided clarification that readily available technology includes
equipment or technology developed by an owner or operator for internal
use and/or use by external partners. The EPA has also clarified the
information that must be included in a request for an alternative test
method for advanced methane detection technology. In the final rule,
the request for an alternative test method must include contact
information, description of the measurement technology, scientific
theory of the measurement, potential limitations, how the measurement
is translated to a mass emission rate, detailed workflow, information
on any models used, a-priori methods, how all data are collected and
transformed from measurement to end user, supporting information
verifying that the technology meets the claimed detection threshold(s)
as applied in the field, including published reports produced by the
candidate or outside entity, standard operating procedures, formal
alternative test method procedures, and information on the spatial
resolution of the measurement technology. Requests for an alternative
test method for advanced methane detection technology must be submitted
to the EPA through the alternative methane detection
[[Page 16915]]
technology portal at https://www.epa.gov/emc/oil-and-gas-alternative-test-methods.
C. Super Emitter Program
In the December 2022 Supplemental Proposal we proposed the Super
Emitter Program to establish a pathway by which an EPA-certified entity
(i.e., third-party notifier) may provide credible, well-documented
identification of a super-emitter emissions event using one of several
permitted remote-sensing technologies and approaches to the responsible
owner or operator. Once notified of the event at a site they own or
operate, owners and operators would be required to perform a root cause
analysis to identify the source of the super-emitter event and take
corrective actions to address the emissions source. As described in
this section, the EPA received comments on the following aspects of the
Super Emitter Program: (1) Statutory authority for the program, (2)
remote sensing methane detection technology, (3) certification of third
parties, (4) notifications by third parties, and (5) requirements for
owners and operators. In response to these comments, the EPA has made
targeted changes to the Super Emitter Program, which are described in
detail in section X.C of this document.
Provided in this section are some of the significant comments on
the proposed program and the EPA's response thereto. For other comments
on the proposed program and the EPA's response thereto, see chapter 14
of the RTC document, Super Emitter Program.\304\
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\304\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
---------------------------------------------------------------------------
1. Statutory Authority
In the December 2022 Supplemental Proposal, the EPA had proposed
for comment two legal frameworks in support of the Super Emitter
Program (87 FR 74752). Under the first legal framework, the EPA would
treat a super-emitter event as a separate and distinct affected
facility under NSPS OOOOb (or a designated facility under EG OOOOc),
and the proposed BSER for this affected facility/designated facility
was the requirement that an owner or operator, upon receiving a notice
of a super-emitter event from an EPA-certified third party, must take
action to identify and address the source of the super-emitter event.
Under the second legal framework, the Super Emitter Program functioned
as an additional compliance assurance measure for affected facilities/
designated facilities subject to numeric performance standards. Under
that second framework, for fugitive emissions component affected
facilities/designated facilities, the Super Emitter Program was
proposed as part of the BSER for the fugitive emissions standard at
well sites and compressor stations, which would include a requirement
to repair components that have been identified as the source of a
super-emitter event. As discussed below, in response to the comments on
both legal frameworks, the EPA has revised the Super Emitter Program
since the December 2022 Supplemental Proposal. The final Super Emitter
Program, which the EPA is establishing pursuant to the authorities
provided by CAA sections 111 and 114(a), is based on the second legal
framework; however, as revised, it will be the EPA, not a third party,
that will notify owners and operators of super-emitter events, and such
notification will be based on data submitted by EPA-certified third
parties using EPA-approved detection technology, and will be issued
only after the EPA has reviewed the data and deemed it to be complete
and accurate. In addition to the responses to comments below, please
also see section X.C of the preamble for a more detailed discussion of
the legal frame for the final Super Emitter Program.
Comment: A number of commenters question the legality of the first
proposed legal framework, which defines a super-emitter event as an
affected facility/designated facility. One commenter \305\ notes that
the EPA may only regulate two types of sources under CAA section 111(b)
and (d): new sources (including modified sources) and existing sources;
however, a super-emitter source is created by an event, not
construction or modification, and therefore is neither a new nor
existing source under CAA section 111. Another commenter \306\
similarly questions the legality of a super-emitter affected facility/
designated facility, noting that it is created by a third-party
notification and could not be said to exist prior to such notification.
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\305\ EPA-HQ-OAR-2021-0317-2398.
\306\ EPA-HQ-OAR-2021-0317-2202.
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Response: Because the EPA is finalizing the program based on the
second legal framework, the legal concerns raised by these commenters
regarding the creation of a new super-emitter affected/designated
facility under the first legal frame are now moot.
Comment: One commenter \307\ states that the EPA's focus on
compliance assurance fits particularly well with the goals of the
program and with the problem of super-emitters. Emissions events
exceeding 100 kg/hr indicate major problems at the site resulting from
either noncompliance or serious operational issues. The commenter
stated that the EPA has broad authority under CAA section 114 to accept
and use third-party monitoring data for purposes related to CAA section
111, including ensuring compliance. The commenter asserted that the
Super Emitter Program does not and should not replace obligations on
the part of owners and operators to reduce methane emissions from
affected and designated facilities under the rules. Rather, the
commenter views the Super Emitter Program as an additional backstop to
ensure that the unique problems posed by super-emitters are timely
addressed.
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\307\ EPA-HQ-OAR-2021-0317-2433.
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Another commenter,\308\ however, states that the proposed Super
Emitter Program is not lawful. According to the commenter, Congress did
not under the CAA to convey to the EPA the authority to delegate the
monitoring of regulated facilities to third[hyphen]party members of the
public for use by the EPA for compliance, supervision and enforcement.
The commenter claims that, in effect, the EPA would be delegating to
groups with unverified qualifications and technical expertise,
according to the commenter an unprecedented action. The commenter
claims that this provision of the proposed rules is also a violation of
the separation of powers of the U.S. Constitution where the EPA is
seeking to legislate and grant legal authority to itself to delegate
regulatory authority to third[hyphen]party members of the public to
monitor and report on regulated facilities, a legislative act that
resides solely with Congress.
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\308\ EPA-HQ-OAR-2021-0317-2227.
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Other commenters \309\ similarly observe that the program as
proposed would be the first time that the EPA has asserted authority
under the CAA to create regulatory obligations for affected facilities
based on monitoring conducted by unaffiliated third parties and without
playing any role at all in verifying the information before imposing
legal obligations on other private parties. In support of this unusual
delegation of regulatory authority, these commenters asserted, the EPA
characterizes the program as
[[Page 16916]]
simply a BSER requiring monitoring and correction of unintentional
releases, akin to LDAR,\310\ but evades the central concern that it is
private parties--not the EPA, states, or regulated entities--who would
be monitoring, notifying, and triggering the associated regulatory
obligations.
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\309\ EPA-HQ-OAR-2021-0317-2301, -2483.
\310\ Id. at 74752 (``[T]he EPA believes that super-emitter
emissions events from unintentional releases tend to occur as a
result of equipment malfunctions and/or poor operations; therefore,
the BSER for super-emitter emissions events would be to correct the
malfunction or operational issues and resume normal operations
consistent with the standards or requirements applicable to the
source(s) of the super-emitter emissions event in this proposed
rule.'').
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Another commenter \311\ agrees with the EPA on the importance of
identifying and addressing large emissions events. The commenter
acknowledges that emissions from such events have the potential to be
much greater than those from normal operations at a given facility and
shares the EPA's interest in seeking to reduce the incidence of such
large emissions events. However, like other commenters mentioned above,
this commenter similarly observed that the proposed program was unique
in that it would be the first time under the CAA that the EPA asserts
authority to create regulatory obligations for affected facilities
based on monitoring conducted by unaffiliated third parties. Claiming
that the EPA did not explain the legal basis for establishing such a
requirement, the commenter states that an explanation from the EPA is
essential to understanding whether such a novel provision is legally
viable.
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\311\ EPA-HQ-OAR-2021-0317-2428.
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Response: In light of the comments above and discussed elsewhere in
this section regarding other aspects of the proposed Super Emitter
Program, the EPA has made targeted revisions to the Super Emitter
Program since the December 2022 Supplemental Proposal. The final Super
Emitter Program, which the EPA is establishing pursuant to CAA sections
111 and 114(a), is based on the second proposed legal framework.\312\
First, as one commenter observes, the EPA has broad authority under CAA
section 114(a) to accept and use third-party monitoring data for
purposes related to CAA section 111, including better understanding the
sources of large emitting events and assuring compliance with its
regulations. CAA 111(a) authorizes the EPA to obtain any information
necessary for the implementation of the CAA from any person ``the EPA
believes may have information necessary for the purposes of
[implementing the CAA].'' While the Super Emitter Program does not
specifically require or request any third party to provide information
on super-emitter events to the EPA, anyone can voluntarily provide such
information to the EPA. It is the EPA's long-standing position that
``information will be considered to have been provided . . . under
section 114 of the Act . . . if its submission could have been required
under section 114. . . .'' 40 CFR 2.301(b)(2). Also, as discussed in
detail in section X.C and further below, CAA 114(a) authorizes the EPA
to require the owners and operators of the source of the super-emitter
event to investigate and report the conclusions of that investigation
to the EPA. As explained below, the final Super Emitter Program
requires such actions from owners and operators upon their receipt of
an EPA notice of a super-emitter event based on data submitted by EPA-
certified third parties using EPA-approved technology. The EPA will
send such notices only after having reviewed and deemed the data to be
complete and accurate.
---------------------------------------------------------------------------
\312\ Please see X.C of the preamble for a detailed discussion
on this legal framework.
---------------------------------------------------------------------------
Second, for super-emitter events caused by regulated sources, the
EPA has separate authority under CAA section 111 to ensure compliance
with its regulations where a notification and subsequent investigation
reveal noncompliance with those regulations. Much of the equipment
likely to cause a super-emitter event is or will be subject to
regulation under CAA section 111 (i.e., NSPS OOOO, OOOOa, OOOOb, or
state/Federal plans pursuant to EG OOOOc). For example, a super-emitter
event might be caused by a regulated thief hatch that is open despite
the EPA's requirement that thief hatches remain closed. In these cases,
the Super Emitter Program serves an additional compliance assurance
measure for the regulated equipment by notifying owners and operators
of data demonstrating super-emitter events and requiring that they
investigate and identify the source of the super-emitter event.
Specifically, the Super Emitter Program serves as additional monitoring
to inform and aid owners and operators in complying with the relevant
NSPS or standards in state and Federal plans. Further, the EPA proposed
and is finalizing the requirement under its fugitive emissions
standards that where the source of the super-emitter event was a
fugitive emissions component under NSPS OOOOb or a state or Federal
Plan implementing EG OOOOc, the owner and operator must follow the
repair requirements in the fugitive emissions work practice standards
in NSPS OOOOb or the applicable state or Federal plan. As explained in
the December 2022 Supplemental Proposal, the EPA considered this as
part of the BSER for fugitive emissions at well sites and compressor
stations.
In response to comments questioning the legality of allowing third
party monitoring and notifications to directly trigger regulatory
obligations, the EPA has revised the proposed program such that the EPA
will play an essential oversight role in the final Super Emitter
Program. Specifically, it will be the EPA, not third parties, that will
notify owners and operators of super-emitter events after reviewing
third-party notifications. Further, the EPA will only accept data
submitted by EPA-certified third parties and collected using EPA-
approved technologies. Upon receiving data submitted by a certified
third party, the EPA will review the data for completeness and
accuracy; the EPA will post such data and notify the identified owner
or operator only after it has reviewed and deemed the information to be
complete and accurate. Accordingly, the EPA plays a central role at
every step: certifying (and de-certifying) the third parties who will
be able to submit notifications under this program, approving the
technology such parties may use, reviewing the notifications to ensure
the information therein is accurate and complete, notifying owners and
operators of such information, receiving and reviewing responses from
owners and operators, and determining when to post information and
responses publicly.
The final Super Emitter Program sets forth criteria that a third
party must meet in order to be certified to submit data on super-
emitter events to the EPA. These criteria ensure that the data
submitted to the EPA are collected by a qualified third party with
access to an EPA-approved technology and the technical expertise and
capability to use such technology to detect and collect data on super-
emitter events. The final rule also lists circumstances under which a
third-party certification will be revoked, such as repeated submissions
of data with significant errors, or engagement in an unlawful action
(e.g., trespass) when monitoring for super-emitter events.
Upon receiving data submitted by a certified third-party, the EPA
will review the data for completeness and accuracy; the EPA will post
such data and notify the identified owner or operator only after it has
reviewed and deemed the information to be complete and accurate.
As finalized, the Super Emitter Program does not ``delegate'' any
regulatory or enforcement role to third
[[Page 16917]]
parties. Rather, the Super Emitter Program merely serves as a mechanism
for the EPA to receive reliable data on super-emitter events from
qualified third parties with access to and expertise in using EPA-
approved advanced technology to detect super-emitter events. The Super
Emitter Program also provides a structured process for the EPA to use
that data to notify the owner or operator of a regulated facility of
the existence of a super-emitter event that may indicate a lapse in
compliance at the facility, or a source of fugitive emissions that this
rule requires to be promptly repaired. There is no sense in which this
framework ``delegates'' governmental authority of any kind to any third
party. No action is required of an owner or operator solely on the
basis of an action of a third party. In addition, the process by which
the EPA receives data and issues notifications under the Super Emitter
Program is separate from and unrelated to the EPA's enforcement
functions.
This structure, where the EPA reviews and determines the
reliability of reported data on super-emitter events, is similar to
other, longstanding programs where citizens and other entities can
report concerns about regulatory compliance to the Agency. For example,
the EPA's Office of Enforcement and Compliance Assurance administers a
program where citizens and other entities can report suspected
environmental violations. See https://echo.epa.gov/report-
environmental-violations#:~:text=Stop-,Stop,%2D800%2D424%2D8802. The
Super Emitter program likewise functions to allow third parties to
share with the EPA monitoring data, and then allows the EPA to
determine the reliability of the data, and engage with the relevant,
regulated party to determine if there is a need for further action to
ensure compliance with the EPA's regulations. The third parties
reporting super-emitter events do not have an independent enforcement
role as a function of the Super Emitter Program. Instead, the EPA
retains its traditional enforcement authority.
As explained in the December 2022 Supplemental Proposal (87 FR
74752) and noted by one commenter,\313\ the Super Emitter Program
serves as a backstop to addressing emissions from super-emitter events
that were not prevented from other requirements in the rule. However,
the EPA did not propose and does not require in the final program any
specific investigation to be conducted to identify the source of the
super-emitter event. Because the relevant investigations for
identifying the source(s) of the super-emitter event may vary depending
on what the third-party data reveals, the final rule defers to the
owner and operator in deciding the appropriate investigation(s).
However, where there are NSPS affected facilities (or designated
facilities subject to a state or Federal plan implementing EG OOOOc) or
associated equipment onsite, the owner and operator may conclude that
they are unable to identify the source of the super-emitter event only
after having conducted the applicable investigation listed in the final
rule for such regulated source.
---------------------------------------------------------------------------
\313\ EPA-HQ-OAR-2021-0317-2433.
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The EPA further notes that the obligation to investigate and report
the source of super-emitter events (separate and apart from the
obligation to take steps to address the super-emitting event) is not
limited to NSPS affected facilities (or designated facilities subject
to a state or Federal plan implementing EG OOOOc) and associated
equipment; it also extends to other equipment onsite that an owner and
operator suspects could be the source of a super-emitter event. As one
commenter observes, the EPA has broad authority to require emissions
reporting under CAA section 114(a). Among other things, CAA section
114(a) authorizes the EPA to require ``any person who owns or operates
any emission source'' (except mobile sources) \314\ to provide
information necessary for purposes of carrying out the CAA. In this
case, section 114(a) authorizes the EPA to require the reporting of
information on super-emitter events, so that the EPA may evaluate
whether such large emissions can be adequately addressed under the EPA
regulations to date or whether more needs to be done in the future
(e.g., during the next periodic review of the NSPS under CAA section
111). Therefore, the EPA expects the owner and operator to investigate
all equipment onsite that they suspect could be the source of a super-
emitter event, whether or not such equipment is subject to NSPS
regulation or a state or Federal Plan implementing EG OOOOc. Where the
super-emitter event was caused by equipment not subject to NSPS OOOO,
OOOOa, or OOOOb, or a state or Federal plan implementing EG OOOOc, the
owner and operator must report such finding. However, there is no
requirement for the owner or operator to take action to eliminate or
mitigate the emissions from the super-emitter event caused by sources
not subject to an NSPS or a state or Federal plan implementing EG
OOOOc.
---------------------------------------------------------------------------
\314\ The EPA has similar information collection authority with
respect to mobile sources under CAA section 208.
---------------------------------------------------------------------------
While there are comments expressing concerns with the proposed
program as described above, the EPA received comments expressing strong
support for the program from several states,315 316
environmental groups \317\ and industry.318 319 One industry
commenter concurs with the EPA on the importance of identifying and
addressing large emissions events and shares the EPA's interest in
seeking to reduce the incidence of such large emissions events. The
commenter also agrees with the EPA that data transparency is valuable
and shares the EPA's goal of disseminating information to mitigate
emissions events. The EPA believes that the final Super Emitter
Program, which has been significantly revised in response to comments,
will serve its goal of reducing emissions from super-emitter events
that were not prevented by other requirements in the rule.
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\315\ EPA-HQ-OAR-2021-0317-2296.
\316\ EPA-HQ-OAR-2021-0317-2422.
\317\ EPA-HQ-OAR-2021-0317-2433.
\318\ EPA-HQ-OAR-2021-0317-2428.
\319\ EPA-HQ-OAR-2021-0317-2499.
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2. Certification of Third Party
This section of this document presents a summary of significant
comments received on certification of third-party notifiers as part of
the Super Emitter Program and the EPA's response to those comments, as
well as changes the EPA has made to the requirements since the December
2022 Supplemental Proposal.
The EPA received many comments regarding how advanced methane
detection technology has been incorporated into our proposed standards,
including the lack of clarity on which remote sensing technology would
be considered for the program, how the remote sensing technology could
be considered for the program, what an approval process could look
like, and how best to make this program transparent.
Comment: Several commenters 320 321 expressed concern
with the lack of standard methods for the example technologies that the
EPA identified in the proposed rule as compared to test method
requirements (i.e., validated test methods) that underpin compliance
determinations for NSPS or national emissions standards for hazardous
air pollutants (NESHAP) standards. One of these commenters suggested
that the proposed programmatic requirements (i.e., alternative test
methods) be
[[Page 16918]]
applied to the Super Emitter Program. Another of these commenters
recommended that the EPA develop guidance on test and monitoring
methods to use to define super-emitter emissions events.
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\320\ EPA-HQ-OAR-2021-0317-2366.
\321\ EPA-HQ-OAR-2021-0317-2483.
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Several commenters 322 323 urged the EPA to not overly
restrict the technologies that may qualify and suggested that the EPA
should use the alternative test method approval process already under
development to approve advanced methane detection technologies for
monitoring fugitive components, covers, and closed vent systems in this
rule for use in the Super Emitter Program. One of these commenters
provided that such an approach could allow for additional technologies
that could operate within the requirements of this program. Another
commenter urged the EPA to use the already proposed alternative test
method to remove any potential barriers on the third party to evaluate
technology and to bring the measurement to the same level as that of
the owner or operators while improving objectivity.
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\322\ EPA-HQ-OAR-2021-0317-2410.
\323\ EPA-HQ-OAR-2021-0317-2394.
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Some commenters 324 325 raised safety concerns regarding
individuals engaged in third-party monitoring. One of these commenters
raised concerns that certain monitoring technologies used by third
parties to identify super-emitter emissions events that need to be
operated in the close vicinity of a site, and that individuals
conducting that monitoring may not be aware of important safety
concerns regarding that site. Another one of these commenters provided
examples of such safety concerns associated with members of the public
accessing sites without proper notice. For example, some sites can
contain hydrogen sulfide (H2S), a gas that could result in
serious health impacts for members of the public entering a site
without proper protection. The commenters raised concerns that
individuals may not be aware of such hazards or have the appropriate
personal protection equipment (PPE) and training to mitigate them.
---------------------------------------------------------------------------
\324\ EPA-HQ-OAR-2021-0317-2326.
\325\ EPA-HQ-OAR-2021-0317-2360.
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Response: Regarding the comments on the use of remote sensing
technology and the lack of approved or validated methods for use in the
Super Emitter Program, we agree with the commenters that the remote-
measurement approaches used for this program should be evaluated in the
same manner as any compliance measurement used in this rule. The EPA
also agrees with the commenters' recommendations that we use the
alternative test method approval process already under development to
approve advanced methane detection technologies for monitoring fugitive
components, covers, and closed vent systems in this rule. Therefore, in
the final rule we are requiring that third parties participating in the
Super Emitter Program use an alternative test method that has been
approved under 40 CFR 60.5398b(d) of the final rule and we have revised
the scope of the alternative test method program to now include the
approvals for the Super Emitter Program.
Comment: Several commenters 326 327 ask that the EPA
clarify its intent as to which advanced methane detection technologies
can be utilized for the Super Emitter Program. Several commenters
328 329 maintained that the EPA must provide a clear pathway
for communities and third parties to participate and engage in the
Super Emitter Program. They also said that the EPA must ensure that
data from approved monitoring technologies are accessible to all,
including by allowing the use of OGI cameras in this program. These
commenters urged the EPA to expand what they characterized as the
overly restrictive technology standards proposed for the Super Emitter
Program, which would currently work to limit the participation of NGOs
and communities that lack access to remote detection technologies.
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\326\ EPA-HQ-OAR-2021-0317-2249.
\327\ EPA-HQ-OAR-2021-0317-2410.
\328\ EPA-HQ-OAR-2021-0317-2394.
\329\ EPA-HQ-OAR-2021-0317-2410.
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Response: In the December 2022 Supplemental Proposal, the EPA
identified satellites, aircraft, and other mobile monitoring
measurement systems that can quantify an emission rate of 100 kg/hr of
methane or greater. These examples were intended to make clear that
third parties would only use technology that could be used at a
reasonably safe distance, well away from a well site, central tank
battery, or compression station, to ensure the integrity of these sites
and the safety of the individuals or organizations collecting the
measurements. Nothing in this rule should be construed as authorizing
third parties to enter well sites or any other affected facility or
designated facility to take measurements. Also, we recognize that
mobile monitoring platforms could be interpreted broadly; this language
is the EPA's effort to account for the continuing advancement of
methane detection technology, and the qualification to meet the mobile
monitoring platform is that we would allow any un-fixed measurement
technology operating offsite from a well site, central tank battery, or
compression station that can quantify an emission rate of 100 kg/hr of
methane or greater. For the final rule, the EPA is maintaining the
proposed criteria regarding which measurement technologies can be used
in the Super Emitter Program. While the minimum threshold remains 100
kg/hr, the EPA would consider the use of remote technologies with
higher detection thresholds in this program. However, those
technologies would be limited to reporting emissions events above their
detection threshold.
Lastly, we acknowledge the desire of certain third-party groups to
use OGI as part of this program. However, the current generation of
this technology does not have the quantification ability required as
part of this rule. More importantly, this technology cannot be operated
at a distance and creates more potential for users getting too close to
the site and creating risks to themselves or to the site. We recognize
that a number of the technology vendors focusing on OGI are developing
systems capable of quantification, and as these systems come online,
this determination may change if there is a mechanism to ensure that
the monitoring is only done at a reasonable and safe distance away from
an applicable well site, central tank battery, or compression station.
The EPA further notes that direct monitoring is not the only way
that communities can participate in or benefit from the Super Emitter
Program. The EPA anticipates that a broad range of entities, including
community organizations that are not themselves certified, might
partner with a certified third party to identify locations of
particular concern for monitoring attention. The EPA will also be
posting the super-emitter event data shortly after it is received,
which provides communities with information that could be relevant to
local health and air quality, and could also be useful to communities
seeking to advocate on their own behalf.
Comment: Several commenters 330 331 raised concerns that
the December 2022 Supplemental Proposal offered little clarity about
the necessary demonstrated expertise for third parties. Many of these
commenters also stated that the EPA should develop detailed criteria
for the certification of these third-party notifiers. Furthermore,
[[Page 16919]]
according to another commenter,\332\ the Agency should make transparent
and publicly disclose what other qualified parties have been certified.
Some commenters raised a concern that some third-party notifiers may be
inadequately trained to detect methane leaks; these same commenters
recommended that third-party notifiers be required to have appropriate
training/certification to validate emissions events. Another commenter
stated that a third party must complete an approval certification
process by the EPA for inclusion in the Super Emitter Program; also
this commenter suggested that third parties notify the EPA of planned
monitoring, including submittal of a monitoring plan.
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\330\ EPA-HQ-OAR-2021-0317-2399.
\331\ EPA-HQ-OAR-2021-0317-2403.
\332\ EPA-HQ-OAR-2021-0317-2428.
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One commenter \333\ questioned how effectively a third party would
be able to identify an owner or operator of a site or be able to
contact the right people if the facility is covered by NSPS OOOOb. The
same commenter mentioned the importance for notifications to be sent to
the correct person at the operating company. Another commenter \334\
agreed that the qualifications of third-party reporters are important
and that approved third-party reporters should show proficiency and
accuracy in identifying super-emitter leaks.
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\333\ EPA-HQ-OAR-2021-0317-2406.
\334\ EPA-HQ-OAR-2021-0317-2216.
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Several commenters 335 336 provided recommendations on
how to improve the process for revoking certifications for third
parties. A few of these commenters argue that the three-time threshold
for inaccurate event notifications from a third party is too high and
should not be limited to multiple notifications at the same facility
owned by the same operator. Another commenter \337\ recommended that
the criteria for revocation explicitly state that revocation would
occur upon a third party's third submission of verifiably false data
from any combination of operators or sites, or upon trespass or
otherwise unlawful or unauthorized entry to a facility.
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\335\ EPA-HQ-OAR-2021-0317-2428.
\336\ EPA-HQ-OAR-2021-0317-2168.
\337\ EPA-HQ-OAR-2021-0317-2446.
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Response: The EPA agrees with the commenters that the final rule
should more completely define the certification process and criteria
these third parties must meet. Therefore, in the final rule we have
amended the regulatory text to include the procedures an entity must
follow when seeking certification, what information they must submit to
the EPA as part of this certification process, and a set of standards
an approved third-party notifier must continue to follow.
The final rule now provides direction for any entity requesting
certification to be a third-party notifier to submit the required
information to the Leader, Measurement Technology Group, Mail Drop:
E143-02, 109 T.W. Alexander Drive, P.O. Box 12055, Research Triangle
Park, NC 27711. The required submission information includes general
information on the organization requesting the certification,
qualifications for the certifying official, which measurement
technologies will be used, standard operating procedures for data
review, records management processes, and a Quality Management plan.
The required information is not intended to be onerous, however these
basic requirements are consistent with the EPA's internal data review
process and are in place to ensure that notifications being provided to
the EPA are actionable and accurate. We are also requiring third-party
notifiers to maintain the relevant records from surveys conducted or
sponsored by the third party, including data used to evaluate the
validity of a super-emitter event but which is not required to be
submitted as part of the notification.
In addition, the final rule defines the Administrator's authority
to approve or disapprove certifications as a third-party notifier,
clarifies when third parties must be certified, and provides greater
detail on the process to revoke certifications. The EPA agrees with
commenters' points that the program should be run transparently, and
the identification of all certified third-party notifiers shall be
posted on the EPA website at https://www.epa.gov/emc-third-party-approvals with a corresponding third-party notifier ID. The EPA
disagrees with the comment that third parties must be recertified at a
specific frequency; instead, the final rule requires third parties to
amend their certification (i.e., recertification) to account for any
significant changes in their technology or other elements of their
certification. The EPA considers it important to require third parties
to amend their certification to account for the advancement in the
methane detection technology and will structure the program to quickly
evaluate these amendments.
Finally, the EPA agrees with the commenters that the Agency should
expand the circumstances in which a third party can be removed from the
list of approved notifiers. With the EPA's central role in handling
super-emitter notifications, we have expanded the circumstances to
include removal of a third party that has made material changes to
their process without amending their certification, if a certified
third-party notifier has repeatedly submitted data with significant
errors, or if the third-party notifier engages in an illegal activity
during the assessment of a super-emitter event (e.g., trespassing). We
are also finalizing the proposed provision that the Administrator
revoke a certification upon receiving a petition from an owner or
operator documenting that it has received three or more notices with
materially erroneous information on a super-emitter event at the same
well site, centralized production facility, or compressor station,
submitted to the EPA by the same third-party notifier. Since the 2022
Supplemental Proposal, the EPA has improved the robustness of the Super
Emitter Program by establishing specific and detailed criteria to
ensure the qualifications of third parties who can be certified and the
quality and accuracy of the data that the EPA will accept from the
certified third parties; further, the EPA will review the submitted
data for completeness and accuracy before issuing any notice of a
super-emitter event to an identified owner or operator. The EPA
believes that these safeguards will minimize, if not eliminate,
issuance of clearly erroneous notices; however, there may be errors in
the submitted information that cannot be readily discerned by the
third-party notifier or the EPA, at least not without more time, which
would undermine the Program's objective to provide owners and operators
timely information to identify and address super-emitter events. In
light of the above, the EPA believes that revoking a third-party's
certification after three times of submitting data with material errors
on the same facility is an appropriate balance between providing owners
and operators timely notifications of super-emitter events at their
facilities and minimizing the likelihood and therefore burden of owners
and operators having to respond to notices with material erroneous
information.
3. Notifications by the Third Party and Requirements
We received several comments on ways to improve the notification
process in the Super Emitter Program. This section of this document
presents a summary of significant comments received on the handling of
notifications and the EPA's response to those comments, as well as
changes the EPA has made to account for those comments, including a
central role for the EPA in collecting and reviewing
[[Page 16920]]
third-party reports of super-emitter events and providing
notifications.
Comment: Several commenters 338 339 expressed that
super-emitter data should be published by the EPA and that the EPA
should manage all data that is to be public and establish a protocol
for when and what types of specific details of a potential super-
emitter emissions event are published. Another commenter suggested that
the EPA should maintain a public database of all super-emitter
notifications by certified third-party reporters. Still another
commenter strongly disagreed that the EPA should promptly make such
reports available to the public online and recommended that the EPA
should provide time to verify or authenticate the information from
third parties and allow owners or operators to review and respond to
the information.
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\338\ EPA-HQ-OAR-2021-0317-2409.
\339\ EPA-HQ-OAR-2021-0317-2399.
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Several commenters \340\ stated that notifiers should be required
to provide proof of the event such as time, date, location, and visual
evidence of leak origin. One commenter \341\ said that the EPA should
show discretion in accepting information provided by third parties as
proof that a super-emitter exists, including quantification of the
super-emitter. Still other commenters \342\ were concerned that the
notifications are based on a snapshot in time, which they asserted was
not sufficient, and that the EPA should establish criteria for the
third party to demonstrate that excessive rates of methane are
occurring for an extended period of time.
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\340\ EPA-HQ-OAR-2021-0317-2453.
\341\ EPA-HQ-OAR-2021-0317-2399.
\342\ EPA-HQ-OAR-2021-0317-2483.
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Several commenters 343 344 345 expressed concern that
the December 2022 Supplemental Proposal did not state the amount of
time required for notifications following the detection of a super-
emitter. Many of these commenters discussed how the time required may
be dependent on the type of remote sensing technology, the ability to
identify the relevant operator, and the capabilities of the third-party
notifier. In these individuals' comments, the commenters provided a
range of potential suggested requirements for providing notifications,
from 1 day to a few weeks. Some of these commenters identified that
timely notification would lead to earlier mitigation, but more
importantly that some of these super-emitter events are intermittent
and investigation into their cause is more effectively performed closer
to the event and would aid in prevention. An additional commenter \346\
raised concern that information received several months after a
detection will likely be challenging for operators to utilize
effectively.
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\343\ EPA-HQ-OAR-2021-0317-2202.
\344\ EPA-HQ-OAR-2021-0317-2301.
\345\ EPA-HQ-OAR-2021-0317-2409.
\346\ EPA-HQ-OAR-2021-0317-2221.
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Finally, one commenter \347\ suggested that third parties should
attest that the notifier is an EPA-approved entity for providing the
notification and that the information was collected and interpreted as
described in the notification. The commenter went on to explain that a
signed certification provides fidelity to the requirement that the
information is coming from a verified source. The commenter believes
that this can be in the form of a weblink that traces back to the EPA's
website hosting the list of third-party notifiers.
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\347\ EPA-HQ-OAR-2021-0317-2428.
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Response: The EPA agrees that the program will be more effective
with the EPA in a centralized role to accept and review third-party
submittals and make the notifications to an owner or operator in a
timely manner, and so we are revising the final rule to include a
substantial oversight role for the EPA. The EPA also agrees with those
commenters who assert that it is important that these data should be
public, and to address these comments, the EPA is developing a Super
Emitter Program Portal to be found at the following URL, https://www.epa.gov/super-emitter. The Portal will serve to manage the data
associated with the Super Emitter Program, including data coming into
the system from EPA-certified third parties, providing notifications
from the EPA to affected owners or operators, responses back from the
owner or operators, and display of the super-emitter data. This portal
and the underlying data management system from which it is built will
allow the EPA to quickly review incoming data for accuracy and
completeness, allowing for timely notification of verified data to
owner or operators.
The EPA does not agree with the commenters that verified data
should not be public until such time that an owner or operator has a
chance to review and respond to the information, and the EPA believes
it is important that this program is operated transparently. However,
the EPA is conscious of these commenters' concerns that many of the oil
and gas basins are dense with sites and that uncertainty in the spatial
resolution of some of the remote sensing platforms may make correct
identification of the owner or operator challenging. Therefore, the EPA
will not identify the attribution of the super-emitter source until the
notified owner or operator of a site has the opportunity to respond;
this will be further discussed later in this section.
The EPA agrees with those commenters that the third-party notifiers
must be able to provide proof of a super-emitter event and therefore
the final rule has defined the information that must be submitted by
the third party into the Super Emitter Program Portal. Only those
individuals and organizations that have been certified will be able to
access the notification portion of the portal. The required information
that must be supplied with the notification are the: third-party
notifier ID; date of detection of the super-emitter event; location in
latitude and longitude; owner, or operator of a well site within 50
meters of the identified latitude and longitude, if available;
detection technology used; documentation (e.g., imagery) of the super-
emitter event and from which it is detected; quantified emission rate;
and associated uncertainties. The EPA also agrees with those commenters
that the EPA super-emitter data must be supplied in a timely manner and
therefore in this final rule we are requiring that notifications must
be supplied to the EPA within 15 days after the detection event; we
believe this is a reasonable amount of time within which to acquire the
data, verify the data, and identify an owner or operator, consistent
with the importance of quick notification. In the final rule, to ensure
that the EPA is providing actionable information to the owners or
operators, the EPA will not review and/or provide any notifications to
an owner or operator unless the third-party notification is received
within 15 days after detection of the super-emitter event. Furthermore,
the EPA agrees that a third party must attest to the accuracy of their
notification and in the final rule we now include an attestation
statement to be signed by the certifying official.
Information that is received within 15 days after detection and is
attested, complete, and found to be accurate to a reasonable degree of
certainty will be assigned a unique notification number, provided to
the identified owner or operator as quickly as possible, and the
notification will be made public at https://www.epa.gov/super-emitter
at the same time. However, the initial public notification will not
include the identity of the owner or operator, so that the notified
owner or operator has an opportunity to respond before attribution is
posted.
[[Page 16921]]
4. Requirements for Owners and Operators
We received several comments on the December 2022 Supplemental
Proposal on the required actions when owners or operators receive
notification of a super-emitter event as part of the Super Emitter
Program. This section of this document presents a summary of
significant comments received regarding the follow-up investigations,
requirements for any necessary repairs, and reporting the results of
those investigations to the EPA, and the EPA's response to those
comments. This section also details changes the EPA has made in the
final rule to account for those comments, changes in the final rule
concerning the EPA's central role in handling responses from the owner
or operator, and changes in the final rule reflective of this program
as a compliance assurance program.
We received several comments 348 349 350 supporting the
requirement that owners or operators investigate the source and
cause(s) of significant emissions events that are brought to an
operator's or owner's attention. More than a few of these commenters
took issue with our proposed use of ``root cause analysis'' for
investigating potential causes of super-emitter events. Specifically,
one comment argued that the concept of ``root cause analysis'' is
embedded in numerous other regulatory and non-regulatory programs and
has varied meaning and purpose in each application, and another
commenter asserted that the phrase ``root cause analysis'' has
connotations that lead to a much more involved process than the EPA
appears to have envisioned in the December 2022 Supplemental Proposal.
Many of these commenters suggest that ``root cause analysis'' be
replaced by ``investigative analysis,'' broadly meaning the owner or
operator must determine whether an emissions event has occurred and
take steps to ensure that it will not happen again.
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\348\ EPA-HQ-OAR-2021-0317-2627.
\349\ EPA-HQ-OAR-2021-0317-2483.
\350\ EPA-HQ-OAR-2021-0317-2326.
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We received several comments discussing the suitability of the
timelines provided in the December 2022 Supplemental Proposal. Several
commenters 351 352 indicated the proposed 5 days to initiate
root cause and 10 days to complete corrective action are inadequate, as
some locations are remote in nature or, in some instances, may require
longer timeframes to obtain equipment or schedule service companies to
complete the corrective action. Some of these commenters recommended
that the EPA provide owners or operators with 14 business days to
conduct an analysis of the incident and provide the EPA with
recommended actions to avoid future occurrences; one commenter also
suggested that if analysis cannot be conducted within 14 business days,
the owner or operator should notify the EPA and let the Agency know
when the analysis will be available, which in no event may exceed 90
days.
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\351\ EPA-HQ-OAR-2021-0317-2305.
\352\ EPA-HQ-OAR-2021-0317-2409.
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The EPA also received several comments regarding the potential
causes for super-emitters and what the appropriate steps should be for
investigating super-emitter events. One commenter \353\ reasoned that
many of the super-emitter events of this magnitude are caused by unlit
flares and tank malfunctions and that in those cases owners and
operators should be able to fix the underlying issue quickly. Another
commenter \354\ identified that super-emitter emissions may be caused
by an anticipated, short-duration event such as operations and
maintenance activity at the site. Several commenters 355 356
raised that for sites with validated continuous monitoring systems,
these systems will very likely already have noted and mitigated super-
emitter events before even receiving a notification.
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\353\ EPA-HQ-OAR-2021-0317-2433.
\354\ EPA-HQ-OAR-2021-0317-2326.
\355\ EPA-HQ-OAR-2021-0317-2284.
\356\ EPA-HQ-OAR-2021-0317-2333.
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Regarding whom is subject to the Super Emitter Program, the EPA
received some comments that no investigative analysis should be
required if the emissions are not associated with an affected facility
under NSPS OOOOb. Another commenter \357\ contends that the EPA has
broad authority under CAA section 114 to accept and use third-party
monitoring data for purposes related to CAA section 111, including
ensuring compliance.
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\357\ EPA-HQ-OAR-2021-0317-2433.
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The EPA received several comments on how best to manage super-
emitter event reporting after receipt of a super-emitter notification.
A commenter \358\ explores the possibility that an owner or operator
should only be reporting to the EPA when the facility owner or operator
confirms the super-emitter event; this commenter also discussed the
EPA's developing a document repository for the notices to operators it
receives as well as the reports sent by the owners and operators in
response. A few commenters 359 360 representing state and
Tribal authorities request that all subsequent reports and submittals
should also be copied to the state, to aid states' compliance efforts
under the Super Emitter Program and to provide information that states
can use in their own compliance and enforcement efforts. Several
commenters raised concerns regarding either the misidentification of an
operator's facility or inaccurate quantification of super-emitter
emissions. Another commenter requested that we maintain the language
referenced in the December 2022 Supplemental Proposal preamble to allow
that owners and operators would have the opportunity to rebut any
information in a notification provided by the qualified third parties
in their written report to the EPA, by explaining where appropriate
that: there was a demonstrable error in the third-party notification;
the emissions event did not occur at a regulated facility; or the
emissions event was not the result of malfunctions or abnormal
operation that could be mitigated.
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\358\ EPA-HQ-OAR-2021-0317-2193.
\359\ EPA-HQ-OAR-2021-0317-2241.
\360\ EPA-HQ-OAR-2021-0317-2177.
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The EPA is finalizing the Super Emitter Program as primarily a
compliance assurance program and is not maintaining the root cause
analysis and corrective action requirements from the December 2022
Supplemental Proposal. The EPA acknowledges the commenters' concern
with the use of the ambiguous root cause and corrective action language
for this sector and is in the final rule defining a set of
investigations that an owner or operator must perform when provided
with a super-emitter notification. The EPA is maintaining the
requirement from the supplemental proposal that the owner or operator
of a well site, centralized production facility, or compressor station
must initiate an investigation within 5 calendar days after a
notification, and based on comment we are extending the period to
conduct the investigation to 15 calendar days. These time periods are
appropriate given the very large emissions associated with super-
emitter events; it is important that owners and operators respond
quickly to these very large emissions events and take immediate action
to stop them. Many operators have noted to the EPA that prompt notice
of super-emitter events is important to them exactly for this reason.
The EPA has defined a series of required investigations in the
final rule, designed to target these very large emissions events as
part of a compliance assurance program. In response to
[[Page 16922]]
comments, the investigations are designed to minimize the time and
resources associated with conducting these investigations. Upon
receiving a super-emitter notification by the EPA, a recipient is first
required to determine if it is the owner or operator a well site,
centralized production facility, or compressor station within a radius
of 50 meters from the latitude and longitude provided in the
notification, and if not, the recipient's investigation is complete. If
the recipient does own a well site, centralized production facility, or
compressor station within a 50-meter radius, it must determine the
applicability of any equipment under 40 CFR part 60, subpart OOOO,
OOOOa, or OOOOb, and/or a state or Federal Plan implementing subpart
OOOOc, and is required to perform the investigations as defined in that
applicable subpart. However, for ease of use, the investigations in
each of these subparts are identical. We agree with the commenters that
the largest potential for super-emitters is from maintenance events and
failure of controls and, as such, have incorporated elements into the
investigations under the requirements for maintenance and controls to
identify potential causes. Specifically, the investigation incorporates
the review of any maintenance events (e.g., liquid unloading) conducted
from the date of detection until the start date of the investigations;
and the review of process monitoring data (e.g., SCADA systems) from
control devices to identify any potential causes of a super-emitter
event. We also agree with the commenters that methane monitoring
surveys and/or continuous emissions monitoring conducted from the date
of detection until the start date of the investigations would have
identified the presence or absence of a super-emitter event and when an
event is identified the owner or operator could quickly identify the
cause(s). All these investigations are designed to leverage actions
potentially being performed or recorded as part of daily operation of a
site and are effective tools for identifying large emissions events.
The EPA also recognizes that all sites will not have continuous
monitoring systems and that the owner or operator is likely not to have
conducted fugitive monitoring between the date of detection and the
notification; in those events we are requiring the owner or operator to
conduct screening for a super-emitter event using either OGI, EPA
Method 21, or an approved alternative test method(s) approved per 40
CFR 60.5398(d).
The EPA has restructured the reporting requirements for owners and
operators in the final rule to be consistent with the change in the
program to focus on compliance assurance and to account for the revised
investigation requirements in the rule. While some commenters suggested
that only confirmed super-emitter events should require reports, it is
important for an owner or operator to report the results of their
investigation in any case, as the absence of a super-emitter event is
equally as important as the confirmation for the EPA, the state, local,
or Tribal authority, and the general public. As such, we are requiring
any owner or operator who receives a notification to report the finding
of their investigation. The EPA agrees with these comments requesting
that these owner or operator super-emitter reports be readily
accessible, so the EPA is requiring that these reports be submitted
through the Super Emitter Program Portal to aid in the public display
of data. The EPA also agrees with those state and Tribal authorities
that super-emitter reports should be available to the states at the
time of reporting, and the Super Emitter Program Portal will include a
function to notify a state, local, or Tribal authority when
notifications and/or reports from their jurisdiction are received. The
EPA is requiring that owners or operators report the findings within 15
days after receiving a notification of a super-emitter event; this
marks the final day of the investigation period and is a timeline that
is consistent with criteria in the December 2022 Supplemental Proposal
for reporting initial corrective action. We acknowledge that we
received comment from industry requesting longer timelines for
corrective actions. Due to the large size of these emission events, the
EPA considers the 15 days requirements a reasonable timeframe within
which to conduct and report the required investigations to determine if
the emission event is ongoing is consistent with the objective of this
program to provide actionable information to owners or operators of
facilities experiencing large emissions events, so they can investigate
and perform repair if needed. The super-emitter program does not place
any additional requirements or timeline to repair (i.e., corrective
actions) the source of these large emission events that are not already
included in the rule, however the final rule does include reporting
requirements if the emission events are ongoing at the time of the
initial report submittal.
The level of reporting required by the owner or operator is
dependent on the results of the investigation and the super-emitter
event. The owner or operator of a site within 50 meters from the
latitude and longitude in the notification is required to provide the
super-emitter event notification ID, general identification of the
facility, whether the equipment on the site is subject to regulation
under the applicable subpart, and whether you were able to identify the
super-emitter event. If the owner or operator is able to identify a
super-emitter event, the owner or operator would also report if the
equipment was subject to an applicable regulation (including the
applicable subpart), whether or not the super-emitter event is ongoing
at the time of reporting, and, if the super-emitter event is not
ongoing at the time of reporting, the actual or estimated date and time
when the event ended. If the super-emitter event is ongoing at the time
of reporting, the owner or operator would provide a short narrative of
the plan to end the super-emitter event, including an expected end date
of the event, and the owner or operator would be required to update the
initial report within 5 days after the actual end date of the super-
emitter event.
Finally, we acknowledge the commenters' concerns that a third party
may either misidentify a site's owner or operator or provide inaccurate
data, and we agree with the commenters that owners and operators should
have the opportunity to refute the information provided by the third
party. The revised program in this final rule will give the owner or
operator the opportunity to respond before the emissions event is
attributed to a particular owner or operator, through posting of the
report that the owner or operator submits to the EPA though the Super
Emitter Portal.
5. Recordkeeping and Reporting Requirements for Process Controllers Not
Included in the Affected Source
Comment: Commenters pointed out that 40 CFR 60.5420b(b)(7) requires
owners and operators to submit an identification of all process
controllers that are not powered by natural gas in the initial annual
report, and such controllers are not covered by the definition of the
affected facility for process controllers for NSPS OOOOb. The
commenters recommended that owners or operators only be required to
maintain records and submit information sufficient to determine
compliance with the regulations. The commenters contend that having
requirements for equipment that is not
[[Page 16923]]
part of an affected facility exceeds the EPA's authority granted under
CAA section 111 and add that there is no environmental benefit to
keeping or submitting information for equipment that cannot have
emissions. The commenters recommended that the EPA delete any reporting
or recordkeeping requirements for these controllers from the final
regulations.
Response: After considering this comment, we have determined that
it is appropriate in this instance to require identification of the
equipment that is included in the affected facility, rather than the
equipment that is not part of the affected facility. The process
controllers included in the affected facility are those that are
subject to the emissions standards, whereas process controllers not
included in the affected facility are not subject to the emissions
standards in the final rule and also mostly have no potential to emit
methane or VOCs. Therefore, we have revised the recordkeeping
requirements to require identification only of controllers that meet
the finalized definition of an affected facility, which are those
process controllers that are driven by natural gas and that are not
ESDs.
D. Process Controllers
Process controllers are among the largest sources of methane and
VOC emissions in the source category. In the December 2022 Supplemental
Proposal, the EPA proposed for both the NSPS OOOOb and EG OOOOc to
define the process controller affected facility, and designated
facility, as the collection of all natural gas-driven process
controllers at a site. The December 2022 Supplemental Proposal, like
the November 2021 Proposal, proposed two different standards for
process controllers. For affected facilities that are not located in
Alaska, the EPA proposed a zero-emissions standard and explained that
it could be achieved with any one of several available technology
options that many owners and operators are already deploying to varying
degrees, including the use of electric controllers or compressed air
systems (powered by the grid or by an onsite generator), solar-powered
controllers, and natural gas-driven controllers that are self-contained
or that are routed to a process. For affected facilities that are
located in Alaska and do not have access to grid power, the EPA
proposed a low-bleed emissions standard for continuous vent process
controllers and a requirement that intermittent process controllers be
periodically monitored for leaks and malfunctions using OGI.
A number of comments were received on aspects of the proposed NSPS
OOOOb and EG OOOOc zero-emissions standard. This included comments on
the costs and emissions estimates that supported the BSER analysis.
These comments and the EPA responses are provided in section XI.D.1 of
this document. The EPA received other comments related to the zero-
emissions standard, including comments regarding access to reliable
electricity and the technical feasibility of solar-powered controllers,
routing emissions from natural-gas driven controllers to a control
device, the potential impacts on small businesses, and the secondary
emissions from the use of onsite generators. These comments and the
EPA's responses are provided in section XI.D.2 of this document.
Section XI.D.3 summarizes the refreshed BSER analysis and conclusions
for the final rule. Comments were received regarding the compliance
dates for both the NSPS and the EG. These comments and the EPA's
responses are provided in section XI.D.4 of this document. The EPA also
received comments regarding proposed recordkeeping and reporting
requirements for process controllers not included in the affected
facility and the criteria that would determine whether a process
controller was modified or reconstructed. These comments, along with
the EPA responses and the resulting rule changes, are provided in
sections XI.D.5 and D.6 of this document. The EPA's full response to
comments on the November 2021 Proposal and December 2022 Supplemental
Proposal, including any comments not discussed in this preamble, can be
found in the EPA's RTC document for the final rule.\361\
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\361\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
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In addition to the changes made to the final NSPS and EG to address
these comments, one other change in terminology was made to address
confusion in comments related to the types of equipment that may be
used to perform the functions of process controllers. That change is
discussed in section XI.D.7 of this document.
1. BSER Cost Analysis
As described in the December 2022 Supplemental Proposal,\362\ the
EPA reviewed a range of technologies (control options) for limiting or
avoiding GHG (methane) and VOC emissions from process controllers. The
EPA concluded that adequately demonstrated zero-emissions pneumatic
controller systems were available throughout the production and the
transmission and storage segments. To evaluate the costs of these
systems, the BSER analysis for the December 2022 Supplemental Proposal
was performed for three model plant sizes in both the production and
the transmission and storage segments. These model plant sizes were
based on the number of natural gas-driven pneumatic controllers at a
site: 4 controllers for the ``small'' model plant, 8 controllers for
the ``medium model plant,'' and 20 controllers for the ``large'' model
plant. For new sources, these controllers were broken down by low-bleed
and intermittent vent. For existing sources, there was also one high-
bleed controller for each model plant size. The zero-emissions options
analyzed for each model plant were: electric controllers powered by the
grid, electric controllers powered by solar energy, compressed air
systems powered by the grid, and compressed air systems powered by an
onsite generator. As a result, the EPA's cost analysis considered sites
both with and without electrical service (grid power). Based on this
analysis, the EPA concluded that there was at least one option for each
model plant size with a cost effectiveness value that is within the
range the EPA considers to be reasonable for the purposes of this
rulemaking.\363\
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\362\ 87 FR 74764 and 74765, December 6, 2022.
\363\ 87 FR 78768, December 6, 2022.
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The EPA received and considered comments that resulted in updates
to its cost analysis. These updates focused on model plants as well as
the capital recovery periods for several options, and the option of
using a generator to power electric controllers at sites without grid
electricity was added. Each of these issues is discussed in more detail
below.
Comment: One commenter \364\ recommended that the EPA gather
additional information to create a representative gathering and
boosting compressor station model plant. They indicated that gathering
and boosting compressor stations typically have many more than 20
controllers and require air compressors larger than 20 horsepower, as
the EPA assumed in the ``Large Model Plant'' for production sites.
Another commenter \365\ indicated that some multi-well sites, central
production facilities, and compressor
[[Page 16924]]
stations may contain 100-200 controllers.
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\364\ EPA-HQ-OAR-2021-0317-2399.
\365\ EPA-HQ-OAR-2021-0317-0808.
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One commenter \366\ indicated that the EPA's small, medium, and
large model plants do not reflect the actual average size of
transmission and storage facilities based on the average size reported
in EPA's GHGI, and that the EPA should increase the size of its model
plants to accurately reflect average plant sizes.
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\366\ EPA-HQ-OAR-2021-0317-2433.
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A commenter \367\ noted that intermittent controllers represent
most of the pneumatic devices in operation within the petroleum and
natural gas system segments today.
---------------------------------------------------------------------------
\367\ EPA-HQ-OAR-2021-0317-2446.
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Response: In response to these comments, the EPA made the following
updates to the controller model plants.
Two new ``midstream'' model plants were added to represent
gathering and boosting stations. The small midstream model plant
contains 20 pneumatic controllers, and the large midstream model plant
contains 100 pneumatic controllers.
The three transmission and storage model plants used in
the supplemental analysis were replaced by a small transmission and
storage model plant (30 pneumatic controllers) and a large transmission
and storage model plant (50 pneumatic controllers).
The breakdown of controllers at the new small production
model plants was updated to reflect a higher percentage of intermittent
vent controllers. For new sources, the supplemental analysis assumed
two low bleed and two intermittent vent controllers. This was updated
to one low bleed and three intermittent vent controllers.
Comment: One commenter \368\ pointed out that for electric-powered
compressed air systems, the EPA applied an annualization period of 15
years as opposed to the 6-year period in the 2021 Carbon Limits study.
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\368\ EPA-HQ-OAR-2021-0317-2428.
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Response: The EPA agrees with the commenter that, while the EPA
correctly applied the cost estimates from the 2021 Carbon Limits study,
the EPA incorrectly applied an annualization period of 15 years instead
of the 6-year period in the Carbon Limits cost estimates. This
realization caused the EPA to review all the capital recovery
annualization periods for the zero-emissions options. This led to the
following updates for the capital recovery annualization periods in the
analysis.
For electric controllers powered by the grid, from 15
years to 6 years.
For solar-powered electric controllers, from 15 years to
10 years.
For instrument air systems powered either by the grid or
from generator from 15 to 6 years.
Comment: Commenters submitted information to support the EPA's
understanding that zero-emitting options for process controllers are
technologically and economically reasonable. As a result of comments
submitted in response to the December 2022 Supplemental Proposal, the
EPA engaged in a clarification discussion with EQT regarding its
process controller replacement program.\369\ The EPA learned that EQT
Corporation, one of the largest producers of natural gas in the U.S.,
successfully implemented a program to replace over 8,000 natural gas-
driven controllers at their sites.\370\ EQT announced the replacement
initiative in June 2021, and has completed the project. While EQT
explored a variety of zero-emitting options, the option they found most
effective was the use of generators to power electric controllers.
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\369\ See June 7, 2023, meeting memorandum in EPA-HQ-OAR-2021-
0317.
\370\ https://www.eqt.com/responsibility/pneumatic-device-replacement/.
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Response: Although the EPA evaluated the use of generators to power
compressed air systems for process controllers at sites without grid
electricity, the EPA did not consider the use of generators to power
electric controllers at sites without grid electricity in the December
2022 Supplemental Proposal. Using available information, the EPA
estimated costs for systems using electric controllers powered by a
generator. The EPA estimates the capital costs for these types of
systems to range from just under $29,000 for the smallest production
model plant to over $350,000 for the largest midstream model plant and
the annual costs to range from around $8,500 for the smallest
production model plant to over $55,000 for the largest midstream model
plant. For summary information on the cost effectiveness of the
analyzed available control options, see tables 18 and 19. For more
complete information on the cost analyses conducted for process
controllers, see the TSD for the final rule.
2. Zero-Emissions Standard
Comment: Several commenters remarked that it would be difficult for
some sites to comply with the zero-emissions standard for process
controllers due to a lack of access to electrical power at rural
locations. Several commenters noted that sites are sometimes miles away
from the existing electrical grid, and others mentioned that there can
be challenges to connecting to a nearby grid, such as with right-of-way
issues for placement of power lines.
Response: The commenters appear to suggest that the zero-emissions
standard is only feasible if electrical grid power is available to
sites. The EPA disagrees that grid power is necessary to comply with
the zero-emissions standard for process controllers. The zero-emissions
standard is technology-neutral and does not require that energy from
the electrical grid be used to power controllers. There are many other
technologically feasible and cost-effective options that are available
to owners or operators to achieve zero emissions from process
controllers, including self-contained controllers, solar-powered
controllers, controllers powered by electric generators, and
controllers that have their emissions routed to a process. As noted
here, these options that are not powered by electricity from the
commercial power grid are cost-reasonable. These options are discussed
further in the December 2022 Supplemental Proposal (87 FR 74763).
Comment: The December 2022 Supplemental Proposal included
discussion of the technical viability of solar-powered process
controllers.\371\ While many commenters on the November 2021 Proposal
expressed the opinion that solar-powered process controllers were not a
viable option due to perceived technical limitations, one commenter
cited a study by Carbon Limits \372\ that demonstrated solar-powered
controls installed at well sites in remote and cold locations such as
Northern Alberta and British Colombia have been proven to operate
properly without major reliability issues. Several commenters on the
December 2022 Supplemental proposal continued to state that solar-
powered process controllers would not be feasible in some situations
and specifically addressed the EPA's reliance on the Carbon Limits
report. For example, one commenter indicated that the Carbon Limits
report focuses on the reliability of solar power systems in colder
climates, not areas with limited sun exposure. As a result, the
commenter points out, the Carbon Limits study does not address the
reliability of solar-powered systems in areas with limited sun
exposure, such as West Virginia, or in canyons and mountain valleys.
[[Page 16925]]
Commenters also noted that other factors limit the feasibility of
including solar-powered systems at sites that have significant numbers
of foggy or cloudy days, or high amounts of ice or snowfall, and in
cold locations where battery storage could be negatively impacted. The
commenters state that reliance on solar power leaves sites subject to
the weather and possibly effectively shut down for days. One commenter
noted that solar power may not be feasible for gathering and boosting
operations, which have larger footprints and substantially greater
power needs than other types of operations.
---------------------------------------------------------------------------
\371\ 87 FR 74764, December 6, 2022.
\372\ EPA-HQ-OAR-2021-0317-1451.
---------------------------------------------------------------------------
Response: Some commenters contend that solar power is not a
feasible option to use for controllers at some sites because of
perceived technical limitations. Considering that the electrical power
needed by each controller is relatively low,\373\ the EPA reasonably
expects that a solar power system can be sized with the appropriate
number of panels and batteries to power process controllers at most, if
not all, sites. The EPA does not agree with commenters' claim that
powering process controllers with solar power is technically
infeasible. The EPA has examined these claims from commenters and finds
that solar technology has advanced such that it has overcome previous
technical limitations and is now a technically viable control option.
Further, the use of solar power is not required by this rule. Another
control option determined to be cost-effective at all sites, based on
the EPA's BSER analysis, is the use of a generator to power electric
process controllers, and the use of a generator to power a compressed
air system was cost-effective at larger sites. Other options available
to meet the zero-emissions standard at sites without grid power and
without using solar power include self-contained process controllers,
or routing emissions from controllers to a process, although costs were
not evaluated for these two options.
---------------------------------------------------------------------------
\373\ Estimate of 0.08 amps/controller in Carbon Limits. (2016)
Zero emission technologies for pneumatic controllers in the USA--
Applicability and cost effectiveness.
---------------------------------------------------------------------------
Regarding the suggestion that compliance with the zero-emissions
standard is infeasible at sites requiring a large electricity demand
because solar power would not adequately supply this amount of power,
we note that most gathering and boosting stations and transmission and
storage sites already have electrical grid power at the site. However,
as evidenced by the tables below in this section that summarize the
cost analyses, sites that are not connected to the grid have one or
more cost-effective alternatives other than using solar power (using a
generator to power electric controllers or a compressed air system),
and the owner/operator is able to choose their preferred compliance
option for each site.
Comment: Several commenters requested that the EPA allow owners or
operators to route emissions from process controllers to a control
device that achieves 95 percent control. The commenters report that
this would be a cost-effective emissions reduction method for the many
sites that have control devices onsite already. Other commenters remark
that they are already routing emissions from process controllers to
control devices and that requiring a zero-emissions standard for units
already controlled by 95 percent or more requires the same capital and
annual investment, but with little additional emission reduction over
the baseline.
Response: We evaluated the use of control devices achieving 95
percent pollution control in our analyses for the December 2022
Supplemental Proposal.\374\ This control option was determined not to
be the BSER for new or existing sources and was not used to develop the
process controller standards for the NSPS or the presumptive standards
in the EG. Zero emissions from new and existing process controllers was
shown in our analyses to be technically achievable through several
available options, including the use of self-contained controllers,
electrical controllers powered by electricity from the grid or solar
power systems, or controllers powered by compressed air using
electricity from the grid or from electric generators, and by routing
emissions to a process. The EPA has also shown that at least some of
these available options are cost-effective for different types of
facilities (model plants). Since these options achieve a rate of zero
GHG (methane) and VOC emissions, compared to an emission rate of up to
5 percent of the baseline emissions through the use of a control
device, we have not changed our determination that a zero-emissions
option is the BSER. The baseline that the EPA used for the BSER
analysis did not assume that emissions from the collection of process
controllers was already being controlled at a 95 percent reduction
because EPA does not have information indicating that any sizable
portion of the industry is already being controlled at that level.
While the EPA acknowledges that some process controllers may be subject
to state-level regulations that result in such controls (95 percent
reduction compared to uncontrolled emissions), the EPA does not have
information indicating how prevalent such controls are for existing
sources and therefore could not reasonably assume that such level of
control reflected an accurate representation of a typical industry
source, or even a typical source in a particular state or geographic
region. While some state regulations may include a provision that could
require certain process controllers to reduce emissions by 95 percent
or more, those same regulations also include various exemptions,
variances, and applicability thresholds that make it unclear which
sources are actually achieving the 95 percent reductions. The EPA did
not have sufficient information on this issue to alter the BSER
analysis. The Agency was not presented with data or any empirical
evidence to show how many, or which, sources are currently being
controlled to this extent. The Agency was not compelled to alter the
BSER analysis because of the anecdotal accounts provided by commenters.
However, when developing state plans for the implementation of the EG
for existing sources, states have the ability through RULOF to apply a
less stringent standard with an appropriate demonstration in accordance
with the requirements of 40 CFR part 60, subpart Ba.
---------------------------------------------------------------------------
\374\ 87 FR 76765. December 6, 2022.
---------------------------------------------------------------------------
Comment: Several commenters request that the EPA consider allowing
the use of low-bleed or intermittent-bleed pneumatic controllers at low
production/small sites. The commenters noted that some older facilities
currently have very little throughput, and therefore low emissions from
pneumatics due to infrequent activation. They also noted that low-
producing wells could be close to the end of their production cycle
life and may only contain a limited number of controllers. The
commenters add that the complete retrofit of a low-producing facility
is likely cost-prohibitive based on well economics and could result in
many low production wells or stripper well sites shutting in
production.
Response: As demonstrated in analyses conducted for the December
2022 Supplemental Proposal and the refreshed analysis conducted for the
final rule (see section XI.D.3 below), we found zero-emissions options
to be cost-effective even at small sites (i.e., four process
controllers at the site in our smallest model plant scenario). The
emission factors used in the analyses are average emission factors,
which are based on emissions from many sites
[[Page 16926]]
with varying actuation frequencies. There is considerable evidence that
malfunctioning natural gas-driven intermittent vent controllers are a
significant source of emissions and the emissions from an intermittent
controller that is malfunctioning and venting continuously are not
related to the actuation frequency. While sites with controllers that
actuate infrequently may have lower than the average emissions, the
cost effectiveness values for at least some zero-emissions control
options (i.e., electric controllers powered by the grid, by solar
power, and by power created by an onsite generator) are comfortably
within the range that the EPA considers to be acceptable (see 87 FR
74762), such that even if emissions were less than one-quarter of the
average (which the EPA can reasonably expect to be rare), the EPA would
still consider the costs acceptable given the emissions reductions that
would be achieved.
Further, while the emissions from natural gas-driven pneumatic
controllers at a small site may be low in comparison to those from a
central production facility or gathering and boosting station, the
sheer number of small sites means that the cumulative methane emissions
from these sites are significant. The EPA estimates that 47 percent of
the total nationwide emissions from pneumatic controllers occurs from
sites with less than four controllers. In a study funded by DOE's
National Energy Technology Laboratory (DOE-NETL), GSI Environmental
Inc. (2022) estimates that marginal natural gas and oil wells account
for 59 percent and 37 percent of cumulative methane emissions from oil
and natural gas production, respectively, and roughly half of
cumulative methane emissions from combined oil and natural gas
production. Similarly, Omara, et al. (2022), estimate that low
production well sites account for roughly half (37-75 percent) of all
oil and natural gas well site methane emissions. When considering the
costs of the various control options in conjunction with the associated
emission reduction of those same control options, the EPA found even
for sites with relatively few process controllers, it was cost-
effective to achieve a zero-emissions standard. For additional
discussion of marginal wells, see chapter 6 of the Final Rule TSD.
Lastly, when developing state plans for the implementation of the EG
for existing sources, states have the ability through RULOF to apply a
less stringent standard with an appropriate demonstration in accordance
with the requirements of 40 CFR part 60, subpart Ba.
Comment: Several commenters are concerned about the secondary
emissions that will be created if natural gas-fired generators are used
to power process controllers. The commenters are concerned that the
operation of generators could result in increased cumulative nitrogen
oxide (NOX) and VOC emissions as well as criteria pollutants
and hazardous air pollutants (HAP). The commenters indicated that these
emissions could potentially offset the emissions reductions from the
methane and VOC, and these emissions from sites in ozone non-attainment
areas could prevent those areas from gaining ozone attainment status.
Response: The EPA recognizes that if owners and operators elect to
comply by installing and operating a generator, there will be secondary
emissions generated from the fuel combustion; however, we have
estimated the emissions that would be created by generators and found
that they are far outweighed by the VOC and GHG (methane) emissions
reduction that would be achieved by using process controllers that are
not driven by natural gas. For the December 2022 Supplemental Proposal,
while we did recognize that a commenter had provided estimates of these
emissions, we did not separately analyze the secondary emissions that
would be created if a generator was used to power this equipment.
We have now conducted that analysis and estimate that for a natural
gas-fired generator to power this equipment, the secondary criteria
pollutant emissions would be 43 pounds per year (lb/yr) CO, 306 lb/yr
NO2, 6 lb/yr PM, and 3 lb/yr PM2.5 for a 5 HP
compressor and 172 lb/yr CO, 1,222 lb/yr NO2, 26 lb/yr PM,
and 13 lb/yr PM2.5, for a 20 HP compressor. The secondary
GHG emissions generated as a result of this electricity generation are
estimated to be 11,654 lb/yr CO2, 0.2 lb/yr methane, and
0.02 lb/yr N2O for a 5 HP compressor and 46,618 lb/yr
CO2, 0.9 lb/yr methane, and 0.09 lb/yr N2O for a
20 HP compressor. Considering the global warming potential of these
GHGs, the total CO2 Eq. emissions would be 11,667 lb/yr
CO2 Eq. from a 5 HP compressor and 46,666 lb/yr
CO2 Eq. from a 20 HP compressor. With the total
CO2 Eq. emissions from process controllers at a small site
estimated to be 303,000 lb/yr and 7.5 million lb/yr for a large site,
the total CO2 Eq. reduction from the use of zero-emissions
process controllers powered by a generator running a compressed air
system would be more than 95 percent when compared to the uncontrolled
methane emissions from natural gas-driven controllers. No other
secondary impacts are expected. Considering this information regarding
secondary emissions, we continue to find that the BSER for reducing
methane and VOC emissions from natural gas-driven controllers in the
production and the transmission and storage segments of the industry to
be the use of controllers that have methane and VOC emission rates of
zero.
3. Final BSER Conclusions
Based on the updates discussed above in section XI.D.2, the EPA
refreshed the BSER cost analysis for new sources. This analysis
estimates the cost and emission reductions for the following zero-
emissions options. For sites with access to electricity, the zero-
emissions options include electric controllers and pneumatic
controllers powered by compressed air systems. For sites without access
to electricity, the zero-emissions options include solar-powered
electric controllers, electric controllers powered by a generator, and
pneumatic controllers driven by a compressed air system powered by an
onsite generator. The results of these updated analyses are shown in
table 18. For more detailed information on these cost estimates, see
the TSD for the final rule.
[[Page 16927]]
Table 18--Summary of Process Controller Systems Not Driven by Natural Gas Cost Effectiveness Analysis for New
Sources
----------------------------------------------------------------------------------------------------------------
Cost effectiveness ($/ton) \a\
---------------------------------------------------------------
Location type model plant controller system Single pollutant Multipollutant
---------------------------------------------------------------
Methane VOC Methane VOC
----------------------------------------------------------------------------------------------------------------
Sites With Electricity
----------------------------------------------------------------------------------------------------------------
Small Production:
Electric controllers........................ $378 $1,360 $189 $680
Compressed air.............................. 2,316 8,330 1,158 4,165
Medium Production:
Electric controllers........................ 289 1,039 144 520
Compressed air.............................. 1,270 4,569 635 2,285
Large Production:
Electric controllers........................ 235 847 118 423
Compressed air.............................. 865 3,112 433 1,556
Small Midstream:
Electric controllers........................ 235 847 118 423
Compressed air.............................. 865 3,112 433 1,556
Large Midstream:
Electric controllers........................ 210 754 105 377
Compressed air.............................. 485 1,745 243 872
Small T&S:
Electric controllers........................ 566 2,036 283 1,018
Compressed air.............................. 2,007 7,219 1,003 3,609
Large T&S:
Electric controllers........................ 533 1,917 266 959
Compressed air.............................. 1,951 7,018 975 3,509
----------------------------------------------------------------------------------------------------------------
Sites Without Electricity
----------------------------------------------------------------------------------------------------------------
Small Production:
Electric controllers--Solar................. 276 991 138 496
Electric controllers--Generator............. 1,393 5,012 697 2,506
Compressed air--Generator................... 4,199 15,106 2,100 7,553
Medium Production:
Electric controllers--Solar................. 215 774 108 387
Electric controllers--Generator............. 795 2,860 398 1,430
Compressed air--Generator................... 2,085 7,500 1,042 3,750
Large Production:
Electric controllers--Solar................. 179 643 89 322
Electric controllers--Generator............. 665 2,394 333 1,197
Compressed air--Generator................... 1,396 5,020 698 2,510
Small Midstream:
Electric controllers--Solar................. 179 643 89 322
Electric controllers--Generator............. 665 2,394 333 1,197
Compressed air--Generator................... 1,396 5,020 698 2,510
Large Midstream:
Electric controllers--Solar................. 162 581 81 291
Electric controllers--Generator............. 370 1,333 185 666
Compressed air--Generator................... 511 1,837 255 919
Small T&S:
Electric controllers--Solar................. 435 1,566 218 783
Electric controllers--Generator............. 1,327 4,775 664 2,388
Compressed air--Generator................... 2,725 9,804 1,363 4,902
Large T&S:
Electric controllers--Solar................. 411 1,478 205 739
Electric controllers--Generator............. 1,330 4,786 665 2,393
Compressed air--Generator................... 2,585 9,298 1,292 4,649
----------------------------------------------------------------------------------------------------------------
\a\ For the production segment, the owners and operators realize the savings for the natural gas that is not
emitted and not lost. The cost effectiveness values shown in this summary table do not consider these savings.
If the EPA were to consider these savings, then the cost effectiveness figures in the table ($/ton methane
reduced) would reduce, which would mean the options assessed would be even more cost reasonable than already
shown in this table.
For new sources, the EPA finds that all the options identified in
table 18 are adequately demonstrated options for use of process
controllers that are not driven by natural gas, thus resulting in zero
GHG and VOC emissions. For overall cost effectiveness to be considered
reasonable for new sources, either the cost effectiveness of GHG
(methane) or VOC on a single-pollutant basis must be within the ranges
considered reasonable by the EPA or the cost effectiveness of both
methane and VOC on a multipollutant basis must be within the ranges
considered reasonable by the
[[Page 16928]]
EPA. As shown in table 18, for every model plant in all sectors, there
are two or more options for new sources for which the cost
effectiveness is considered reasonable by the EPA. This is true for
sites with electricity from the grid, as well as sites without this
electrical service. For example, for a medium sized model plant in the
transmission and storage segment at sites without access to grid
electricity, the single-pollutant cost effectiveness values for solar-
powered electric controllers are $435 per ton of methane and $1,566 per
ton of VOC, and the single-pollutant cost effectiveness values for
electric controllers powered by a generator are $1,327 per ton of
methane and $4,775 per ton of VOC. All of these values are within the
range that the EPA considers to be reasonable. For a compressed air
system powered by a generator for this model plant, the single
pollutant values are $2,725 per ton of methane and $9,804 per ton of
VOC. While these values exceed the levels typically considered
reasonable by the EPA, the multipollutant cost effectiveness values of
$1,363 per ton of methane and $4,902 per ton of VOC are within the
ranges considered reasonable by the EPA. Therefore, the EPA considers
the costs of all three zero-emissions options for this model plant to
be reasonable given the associated 100 percent emission reduction
achieved.
As discussed above in section XI.D.2, some commenters contend that
solar-powered controller systems are not a technically feasible
emission control option. The EPA disagrees with this comment, as the
successful use of solar-powered controllers has been demonstrated. The
EPA accepts that there may be certain situations where site-specific
conditions may not be favorable to the use of solar-powered controller
systems. However, this analysis shows that there are other demonstrated
options available for all model plant sizes at sites without
electricity with costs that are considered reasonable given the
resulting methane and VOC emission reductions. In addition, while
information was not available to fully analyze the costs, the option of
collecting the emissions from natural gas-driven pneumatic controllers
and routing them to a process and the option of self-contained natural
gas-driven pneumatic controllers also achieve 100 percent emission
reductions. Therefore, they are considered equivalent to the use of
controllers not driven by natural gas.
The options evaluated for sites without grid electricity include
the use of a generator to power either electric controllers or an
instrument air (compressed air) system. As pointed out by some
commenters, the use of these generators will create secondary air
pollution. As discussed in more detail above in section XI.D.2, on an
individual site basis the EPA concludes that the emissions that would
be created by generators are far outweighed by the methane and VOC
emissions reduction that would be achieved by using process controllers
that are not driven by natural gas.
In conclusion, based on comments received, the EPA refreshed the
BSER analysis with respect to costs and the associated emissions
reductions. The EPA also considered other comments on the BSER analysis
and the proposed zero-emissions standard for process controllers. After
this consideration, the EPA continued to conclude that BSER for new
process controllers is the use of zero-emissions process controllers
that do not emit GHG (methane) or VOC to the atmosphere. Therefore, the
final rule maintains the proposed zero-emissions standard.
The EPA also refreshed the BSER analysis for existing sources. For
each zero-emissions option, the foundation for the cost estimates for
existing sources was the same as for new sources. However, adjustments
were made to account for differences in the costs that would be
incurred for existing sources. For example, the installation costs were
assumed to be twice as high for existing sources as compared to new
sources. Another difference between the new and existing source
analysis is related to the types of controllers assumed to be onsite
for purposes of the model plants utilized in the analysis. The new
source model plants did not include any high-bleed controllers. For
existing sources, it was assumed that there was one high-bleed
controller at every model plant. Thus, the baseline emissions, and the
resulting emission reductions, were greater for existing sources as
compared to new sources. The same zero-emissions options were evaluated
for existing sources as for new sources, and, as for new sources, the
EPA finds that all the options identified are adequately demonstrated
options for use of process controllers that are not driven by natural
gas, thus resulting in zero GHG (methane) emissions. The results of the
refreshed cost analysis for existing sources is provided in table 19.
Table 19--Summary of Process Controller Systems Not Driven by Natural
Gas Methane Cost Effectiveness Analysis for Existing Sources
------------------------------------------------------------------------
Location type Cost
--------------------------------------------------------- effectiveness
\a\
---------------
Model plant controller system ($/ton methane
reduced)
------------------------------------------------------------------------
Sites With Electricity
------------------------------------------------------------------------
Small Production:
Electric controllers.................................. $449
Compressed air........................................ 2,157
Medium Production:
Electric controllers.................................. 375
Compressed air........................................ 1,232
Large Production:
Electric controllers.................................. 347
Compressed air........................................ 899
Small Midstream:
Electric controllers.................................. 347
Compressed air........................................ 899
Large Midstream:
Electric controllers.................................. 334
Compressed air........................................ 538
Small T&S:
Electric controllers.................................. 732
Compressed air........................................ 1,924
Large T&S:
Electric controllers.................................. 754
Compressed air...................................... 1,906
------------------------------------------------------------------------
Sites Without Electricity
------------------------------------------------------------------------
Small Production:
Electric controllers--Solar........................... 329
Electric controllers--Generator....................... 1,384
Compressed air--Generator............................. 4,207
Medium Production:
Electric controllers--Solar........................... 281
Electric controllers--Generator....................... 871
Compressed air--Generator............................. 2,233
Large Production:
Electric controllers--Solar........................... 264
Electric controllers--Generator....................... 845
Compressed air--Generator............................. 1,685
Small Midstream:
Electric controllers--Solar........................... 264
Electric controllers--Generator....................... 845
Compressed air--Generator............................. 1,685
Large Midstream:
Electric controllers--Solar........................... 258
Electric controllers--Generator....................... 538
Compressed air--Generator............................. 679
Small T&S:
Electric controllers--Solar........................... 564
Electric controllers--Generator....................... 1,493
Compressed air--Generator............................. 2,797
Large T&S:
Electric controllers--Solar........................... 582
Electric controllers--Generator....................... 1,653
Compressed air--Generator............................. 2,978
------------------------------------------------------------------------
\a\ For the production segment, the owners and operators realize the
savings for the natural gas that is not emitted and not lost. The cost
effectiveness values shown in this summary table do not consider these
savings. If the EPA were to consider these savings, then the cost
effectiveness figures in the table ($/ton methane reduced) would
reduce, which would mean the options assessed would be even more cost
reasonable than already shown in this table.
As shown in table 19, for every model plant in all sectors, there
are two or more options for which the cost effectiveness for methane
for existing sources is considered reasonable by the EPA. This is true
for sites with electricity from the grid, as well as sites
[[Page 16929]]
without this electrical service. For example, for the small model plant
in the transmission and storage segment at sites without access to
electricity, the cost effectiveness values ($ per ton of methane) are
$564, $1,493, and $2,797 for solar-powered electric controllers,
electric controllers powered by a generator, and compressed air powered
by a generator, respectively. While the cost effectiveness for
compressed air powered by a generator is above the level typically
considered reasonable by the EPA, the other two options are well below
the levels considered reasonable. The discussion above related to
technical feasibility of solar-powered controllers and secondary
emissions from generators for new sources is equally applicable for
existing sources. As for new sources, routing pneumatic controller
emissions to a process and using self-contained natural gas-driven
pneumatic controllers are other control options available to achieve a
zero-emissions standard.
In conclusion, based on comments received, the EPA refreshed the
BSER cost analysis for existing sources. The EPA also considered other
comments on the BSER analysis and the proposed zero-emissions
presumptive standard for process controllers. After this consideration,
the EPA continues to conclude that BSER for existing process
controllers is the use of zero-emissions process controllers that do
not emit methane to the atmosphere. Therefore, the final emission
guideline maintains the proposed zero-emissions presumptive standard.
4. Compliance Dates
Comment: Several commenters state that a 60-day compliance deadline
for new/modified sources is unrealistic due to supply chain concerns,
personnel shortages, and inflation. Due to supply chain shortages and
disruption, one commenter remarked that generators and other equipment
and parts necessary for zero-emissions systems can take up to 3 months
or longer for delivery, while another reports that they currently
experience lead times for non-natural-gas-driven pneumatic controllers,
generators, and air compressors ranging from 12 to 24 months. The
commenters note that there is no indication that this lead time will
improve in the near future and believe it can be expected to worsen as
owners and operators across the country increase demand in response to
the final rule. Commenters contend that this leaves even the most
responsible owner or operator without the ability to comply within 60
days. Some commenters recommend a compliance deadline of 24 months from
the publication date of the final rule and others propose at least a 1-
year timeframe for NSPS OOOOb compliance to allow for procurement and
installation of the systems and equipment necessary (including labor
necessary for installation).
One commenter contends that supply chain considerations do not
alter the reasonableness of the EPA's proposal. The commenter relays
that EQT, the largest natural gas producer in the U.S., retrofitted all
its sites to eliminate natural gas-driven controllers in less than 1.5
years \375\ and another oil and gas producer anticipates it will have
replaced ``nearly all'' of its controllers with zero-emitting devices
within 4 years.\376\ The commenter adds that a recent report by Datu
Research further underscores that the supply chain for the production
of zero-emitting technologies is not a barrier for industrywide
adoption of zero-emissions controllers and that, on the contrary, the
supply chain is strong enough to support implementation of the EPA's
proposed standards.\377\ According to the commenter, Datu's report
identifies 40 providers of zero-emitting controllers, and a survey of
nine of these providers demonstrates that suppliers are well-equipped
to meet anticipated demand within the EPA's proposed regulatory
timeline.\378\ The commenter remarks that some key findings of the Datu
report include the following:
---------------------------------------------------------------------------
\375\ ``EQT Eliminates Nearly 9,000 Natural Gas-Powered
Pneumatic Devices,'' PRNewswire (January 4, 2023) https://www.prnewswire.com/news-releases/eqt-eliminates-nearly-9-000-natural-gas-powered-pneumatic-devices-301713418.html.
\376\ Diamondback Energy, ``2021 Corporate Sustainability Report
8'' (2021), https://www.diamondbackenergy.com/static-files/faf5ab25-5ab5-4404-8c04-c7bd387ae418.
\377\ Data Research, ``Zero-emission Alternatives to Pneumatic
Control: How Ready are Technology Providers to Meet Increased
Demand?'' (Jan. 2023).
\378\ Id. at 5, 9.
---------------------------------------------------------------------------
Technology providers have strategies for meeting current
supply chain challenges. Though procurement delays have been a reality
for some suppliers, they have employed strategies like paying higher
prices, storing extra quantities of supplies, bringing in more
procurement personnel, going to different distributors, spot-buying on
the open market, and finding contract manufacturing sites. Larger
companies reported facing fewer hurdles.\379\
---------------------------------------------------------------------------
\379\ Id. at 3.
---------------------------------------------------------------------------
Regulatory certainty steadies demand. Even considering
supply chain concerns, providers have confidence in their ability to
expand production capacity so long as regulatory certainty helps keep
demand steady over multiple years.\380\
---------------------------------------------------------------------------
\380\ Id. at 11-12.
---------------------------------------------------------------------------
Response: Based on these comments, it appears that some equipment
necessary for the installation of zero-emitting process controllers may
not be available quickly enough, and in large enough quantities, to
enable new sources to comply with the final standard upon startup, or
within 60 days after the publication of the final NSPS. Supplemental
information submitted by one commenter provided information regarding
current equipment lead time and market conditions.\381\ According to
that information, some of the operators surveyed report that they are
experiencing delays in the availability of process controllers,
electrical transformers, generator skids, and compressor skids of up to
12 months. In addition, the zero-emissions technology supplier survey
information also indicates that some equipment providers will need to
ramp up production, and some components may not be widely available
within 60 days after the publication of the final rule.
---------------------------------------------------------------------------
\381\ API. Operator Survey of Supply Chain Delays for Equipment
Needed for EPA Proposed NSPS OOOOb Methane Rule.
---------------------------------------------------------------------------
The equipment types discussed in the information provided by these
commenters are relevant to the installation of zero-emitting
controllers. Further, the equipment types that the EPA believes are
necessary to comply with the final standards for process controllers in
NSPS OOOOb are quite different from the type of equipment used to
comply with the standards for these sources found in NSPS OOOOa. For
example, compliance with NSPS OOOOa for most sources likely does not
require electrical transformers, generator skids, or compressor skids.
Due to these considerations, the EPA is not certain that new sources
could obtain the equipment necessary to demonstrate compliance
immediately upon the effective date of the final rule and is therefore
finalizing a compliance deadline for process controllers that allows
for up to 1 year from the effective date of the final rule. This means
that new sources will have up to 1 year to come into full compliance
with the final standard of zero emissions. Until that final date of
compliance, owners and operators must demonstrate compliance with an
interim standard which mirrors the requirements for sites in Alaska
that do not have access to electrical power found at 40 CFR
60.5390b(b). In summary, the requirements for such sites allow for two
compliance options.
[[Page 16930]]
One option is to use low-bleed controllers and/or intermittent vent
controllers, and to perform monitoring of intermittent vent controllers
to ensure they do not vent during idle periods. The other option is to
route process controller emissions to a control device achieving a 95
percent reduction in emissions. As the current NSPS OOOOa requires that
low-bleed controllers be used, owners/operators of new and recently
modified or reconstructed sites will be able to readily obtain the
equipment necessary for these types of process controllers. Complying
with the interim standard described above does not require using the
equipment that commenters claimed they could not easily obtain (i.e.,
the equipment needed to meet the zero-emissions standard). Therefore,
the EPA expects no sites to have any problems complying with these
interim requirements within 60 days after publication of the final
rule. If an owner or operator opts to comply with the interim standard
during the one year following publication of the final rule, then they
must still comply with the final zero-emissions standard after the year
has passed. Owners and operators can, and are encouraged to, comply
with the final zero-emissions standard before the year has passed.
6. Modification and Reconstruction Criteria and Requirements
Under 40 CFR 60.14, any physical or operational change to an
existing facility resulting in an emissions increase is a modification.
In the December 2022 Supplemental Proposal, we stipulated that in
addition to this definition of a modification, a modification would
occur for purposes of this particular affected facility when a process
controller is added to a site, as this addition would increase
emissions from the affected facility, which is the collection of
controllers at a site.
Comment: Commenters requested that the EPA clarify that, for
purposes of the collection of process controllers at a site, a
modification would occur only when a natural gas-driven process
controller is added, rather than the addition of any type of process
controller. The commenters pointed out that the addition of a
controller not driven by natural gas would not increase emissions from
the affected source.
Response: While it was our intention in the December 2022
Supplemental Proposal to only include the addition of natural gas-
driven controllers in the conditions that would constitute a
modification, as only those controllers could potentially increase
emissions, we agree that the proposed regulatory text did not specify
this. We therefore have changed what we proposed for regulatory
language to clarify that the addition of one or more natural gas-driven
controllers to a site constitutes a modification.
Comment: Commenters also requested that the EPA clarify which
controllers would be considered in the determination of whether a
reconstruction has taken place. In the December 2022 Supplemental
Proposal, we included provisions that would allow owners and operators
to choose to determine whether a reconstruction has occurred as it is
defined in 40 CFR 60.15(b), based on the fixed capital cost of new
process controllers, or they could determine whether a reconstruction
had occurred based on the percentage of the total number of process
controllers replaced.
Response: Like the provisions for modifications, we are clarifying
in the final rule that reconstruction would be considered to occur
whenever greater than 50 percent of the number of existing onsite
natural gas-driven process controllers are replaced, rather than the
replacement of any type of process controller, as only natural gas-
driven process controllers are considered to be affected facilities for
the NSPS.
Comment: In addition to these clarifications regarding the criteria
for determining whether a modification or reconstruction has taken
place, one commenter stated that it is unclear how the notification
requirements of 40 CFR 60.15 apply for reconstruction. The commenter
noted that the proposed language in 40 CFR 60.5365b(d)(2)(ii) suggests
that reconstructed natural gas-driven process controllers would be
subject to some of the requirements included in 40 CFR 60.15, which
include 60-day notification and Administrator approval. According to
the commenter, this conflicts with information presented in table 5 of
the proposed regulatory text, which stated that 40 CFR 60.15(d) does
not apply to process controllers. The commenter believes it was the
EPA's intent to not apply the additional notification and approval,
given the number of facilities that will trigger reconstruction over
time.
Response: We agree that we did not intend for facilities to be
required to notify the Administrator of upcoming process controller
replacements that would constitute a reconstruction or for the
Administrator to be required to review the notification and determine
whether the replacements constitute a reconstruction. We have changed
what we proposed for regulatory text to not refer to the requirements
of 40 CFR 60.15(d) and have kept the information presented in table 5
of the proposed regulatory text, which states that 40 CFR 60.15(d) does
not apply to process controllers.
7. Change in Pneumatic Controller Terminology
To assist with avoiding possible confusion about which types of
``controllers'' are included in the definition of this affected
facility, and which types of controllers must be considered for
purposes of the reconstruction and modification provisions, we have
changed the terminology from ``pneumatic controllers'' (used in both
the November 2021 Proposal and the December 2022 Supplemental Proposal)
to ``process controllers'' in the final rule. When reviewing comments,
the EPA noticed that not all commenters used the same terminology, so
the Agency thought it best to clarify now. The EPA has made this change
both in the final rule preamble and the final regulatory text. The term
``process controller'' is broader in scope because it includes
pneumatic controllers as well as other types of controllers that are
not pneumatic. Only a subset of process controllers used by oil and gas
facilities are pneumatic controllers that use pressurized air
(compressed air or instrument air) or gas to perform their functions.
Other process controllers might use electricity to perform their
functions. From a technical perspective, electronic process controllers
are not true ``pneumatic'' devices, but these electronic process
controllers can be used to perform the same function as a pneumatic
controller, and they achieve the zero-emissions standard. The EPA
changed the terminology because we did not want to inadvertently convey
that misimpression that process controllers had to be pneumatic. To be
clear, the final rule applies to the collection of natural gas-driven
process controllers at a well site. Process controllers that are not
driven by natural gas are not included in the affected facility.
Further, only process controllers driven by natural gas will be counted
when determining whether a modification or reconstruction has occurred.
E. Pumps
In the December 2022 Supplemental Proposal, the EPA proposed for
both the NSPS OOOOb and EG OOOOc to define the pumps affected facility,
and designated facility, as the collection of all natural gas-driven
pumps at a site. For a limited subset of the affected pump facilities,
the EPA proposed a
[[Page 16931]]
tiered structure of standards based on conditions at the affected
facility. Among other comments, the EPA received comments regarding:
(1) the BSER analysis and conclusions, (2) the compliance dates, (3)
the requirements associated with the tiered approach for some pumps,
(4) the recordkeeping and reporting requirements for pumps not included
in the definition of the affected facility, and (5) the criteria that
would determine whether an affected pump facility was modified or
reconstructed. These comments and the EPA's responses to these comments
apply to the standards and presumptive standards in NSPS OOOOb and EG
OOOOc, respectively. A summary of the comments received and the EPA's
response to these comments, including any updates made to the final
rule, as applicable, are provided below. The EPA's full response to
comments on the November 2021 Proposal and December 2022 Supplemental
Proposal, including any comments not discussed in this preamble, can be
found in the EPA's RTC document for the final rule.\382\
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\382\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
---------------------------------------------------------------------------
In addition to the updates made to the final rule to address these
comments, one other change in terminology was made to address the types
of equipment that may be used to perform the functions of pumps. That
change is discussed further here.
1. BSER Analysis and Conclusions
The EPA received several comments regarding the proposed standards
for pumps, including requests that the BSER analyses for pumps be
revised to more closely match the analyses conducted for process
controllers, requests for technology-neutral standards, and comments
regarding the infeasibility certifications required.
Comment: One commenter states that the EPA relied on costs from the
2016 and 2021 Carbon Limits reports for process controllers, but that
the EPA used different costs and assumptions as they pertained to
converting to electric (assumed to be grid power) and solar pumps,
which are not well documented and appear to be based on old information
dating back to 2012.
Another commenter remarked that the EPA proposed a set of
requirements for natural gas-driven process controllers completely
distinct from that for natural gas-driven pumps, with sometimes
conflicting statements made to justify the EPA's decisions. The
commenter requested that the requirements for both process controllers
and pumps be streamlined for consistency, with technology-neutral
standards that do not require additional certifications and that allow
for emissions to be routed to a control device. Another commenter urged
the EPA to mirror the proposed process controller standard for pumps by
including pumps routed to a process as a compliance option and
eliminating the tiered feasibility exemption at sites without
electricity.
Response: The EPA acknowledges that the analysis for pumps in the
December 2022 Supplemental Proposal relied on costs from previous
analyses that were updated to reflect changes in prices due to
inflation. However, those cost figures used in the December 2022
Supplemental Proposal did not reflect more recent changes that have
occurred in control technology or the impact of those changes on costs,
such as a reduction in costs for solar panels and batteries. Therefore,
the EPA updated its analysis for pumps to use the more recent
information for non-natural gas-driven pump options. This included
information from the Carbon Limits reports, which addressed pump
options as well as process controllers.
A summary of the results of the updated analysis showing the cost
effectiveness of the pumps affected facility emissions control options
is shown in table 20. Further information regarding the analysis
conducted for pumps may be found in the NSPS OOOOb and EG OOOOc TSD for
this final rulemaking, which is available in the docket for this
action. The cost effectiveness values shown in table 20 are based on
the estimated total annual costs and the emissions reductions
associated with each control option. The emissions reductions for a
combustion control device are assumed to be 95 percent and are assumed
to be 100 percent for all other control options evaluated. For new
sources that will be covered by NSPS OOOOb, cost effectiveness was
calculated on a single-pollutant basis, where the total annual cost was
applied entirely to the reduction of each pollutant, and was also
calculated on a multipollutant basis, where half the cost of control is
assigned to the methane reduction and half to the VOC reduction. Table
20 shows the cost effectiveness values for GHG (methane) and VOC, which
is applicable for the determination of BSER for new sources. Table 21
provides the cost effectiveness for GHG (methane) for existing sources.
Further information regarding the cost effectiveness values for pumps
may be found in the NSPS OOOOb and EG OOOOc TSD for this rulemaking,
which is available in the docket for this action.
Table 20--Summary of Cost Effectiveness Analysis of Pump Emissions Reduction Options for New Sources
----------------------------------------------------------------------------------------------------------------
Cost effectiveness ($/ton) \a\
---------------------------------------------------------------
Location type and number of pumps at site Single pollutant Multipollutant
---------------------------------------------------------------
Methane VOC Methane VOC
----------------------------------------------------------------------------------------------------------------
Sites With Electricity
----------------------------------------------------------------------------------------------------------------
Electric pumps--production segment:
One diaphragm............................... $349 $1,256 $175 $628
Two diaphragm............................... 349 1,256 175 628
Three diaphragm............................. 349 1,256 175 628
Four diaphragm.............................. 349 1,256 175 628
Electric pumps--transmission and storage
segment:
One diaphragm............................... 267 9,650 134 4,825
Two diaphragm............................... 267 9,650 134 4,825
Three diaphragm............................. 267 9,650 134 4,825
Four diaphragm.............................. 267 9,650 134 4,825
Compressed air-driven pumps--production segment:
[[Page 16932]]
One diaphragm............................... 3,202 11,517 1,601 5,758
Two diaphragm............................... 1,711 6,156 856 3,078
Three diaphragm............................. 1,215 4,369 607 2,185
Four diaphragm.............................. 966 3,476 483 1,738
Compressed air-driven pumps--transmission and
storage segment:
One diaphragm............................... 2,451 88,469 1,225 44,235
Two diaphragm............................... 1,310 47,291 655 23,646
Three diaphragm............................. 930 33,565 465 16,783
Four diaphragm.............................. 740 26,702 370 13,351
----------------------------------------------------------------------------------------------------------------
Sites Without Electricity
----------------------------------------------------------------------------------------------------------------
Electric solar pumps--production segment:
One diaphragm............................... 395 1,421 198 711
Two diaphragm............................... 395 1,421 198 711
Three diaphragm............................. 395 1,421 198 711
Four diaphragm.............................. 395 1,421 198 711
Electric solar pumps--transmission and storage
segment:
One diaphragm............................... 302 10,918 151 5,459
Two diaphragm............................... 302 10,918 151 5,459
Three diaphragm............................. 302 10,918 151 5,459
Four diaphragm.............................. 302 10,918 151 5,459
Compressed air-driven pumps with a generator--
production segment:
One diaphragm............................... 5,130 18,453 2,565 9,226
Two diaphragm............................... 2,676 9,624 1,338 4,812
Three diaphragm............................. 1,857 6,682 929 3,341
Four diaphragm.............................. 1,448 5,210 724 2,605
Compressed air-driven pumps with a generator--
transmission and storage segment:
One diaphragm............................... 3,927 141,752 1,963 70,876
Two diaphragm............................... 2,048 73,933 1,024 36,966
Three diaphragm............................. 1,422 51,326 711 25,663
Four diaphragm.............................. 1,109 40,023 554 20,011
Route pump emissions to process through existing
VRU--production segment:
One diaphragm............................... 472 1,699 236 849
Two diaphragm............................... 472 1,699 236 849
Three diaphragm............................. 472 1,699 236 849
Four diaphragm.............................. 472 1,699 236 849
Route pump emissions to process through existing
VRU--transmission and storage segment:
One diaphragm............................... 361 13,050 181 6,525
Two diaphragm............................... 361 13,050 181 6,525
Three diaphragm............................. 361 13,050 181 6,525
Four diaphragm.............................. 361 13,050 181 6,525
Route pump emissions to existing control device--
production segment:
One diaphragm............................... 497 1,788 249 894
Two diaphragm............................... 497 1,788 249 894
Three diaphragm............................. 497 1,788 249 894
Four diaphragm.............................. 497 1,788 249 894
Route pump emissions to existing control device--
transmission and storage segment:
One diaphragm............................... 381 13,737 190 6,869
Two diaphragm............................... 381 13,737 190 6,869
Three diaphragm............................. 381 13,737 190 6,869
Four diaphragm.............................. 381 13,737 190 6,869
Route pump emissions to process through new VRU--
production segment:
One diaphragm............................... 6,985 25,127 3,493 12,563
Two diaphragm............................... 3,729 13,413 1,864 6,706
Three diaphragm............................. 2,643 9,508 1,322 4,754
Four diaphragm.............................. 2,101 7,556 1,050 3,778
Route pump emissions to process through new VRU--
transmission and storage segment:
One diaphragm............................... 5,347 193,021 2,673 96,510
Two diaphragm............................... 2,854 103,035 1,427 51,518
Three diaphragm............................. 2,023 73,040 1,012 36,520
Four diaphragm.............................. 1,608 58,043 804 29,021
[[Page 16933]]
Route pump emissions to new control device--
production segment:
One diaphragm............................... 7,971 28,673 3,985 14,336
Two diaphragm............................... 4,234 15,230 2,117 7,615
Three diaphragm............................. 2,988 10,750 1,494 5,375
Four diaphragm.............................. 2,366 8,509 1,183 4,255
Route pump emissions to new control device--
transmission and storage segment:
One diaphragm............................... 6,101 220,258 3,051 110,129
Two diaphragm............................... 3,241 116,997 1,620 58,499
Three diaphragm............................. 2,287 82,577 1,144 41,289
Four diaphragm.............................. 1,811 65,367 905 32,684
----------------------------------------------------------------------------------------------------------------
\a\ For the production segment, the owners and operators realize the savings for the natural gas that is not
emitted and not lost. The cost effectiveness values shown in this summary table do not consider these savings.
If the EPA were to consider these savings, then the cost effectiveness figures in the table ($/ton methane
reduced) would reduce, which would mean the options assessed would be even more cost reasonable than already
shown in this table.
Table 21--Summary of Cost Effectiveness Analysis of Pump Emissions
Reduction Options for Existing Sources
------------------------------------------------------------------------
Cost effectiveness ($/
ton) \a\
Location type and number of pumps at site ------------------------
Methane
------------------------------------------------------------------------
Sites With Electricity
------------------------------------------------------------------------
Electric pumps--production segment:
One diaphragm.............................. $349
Two diaphragm.............................. 349
Three diaphragm............................ 349
Four diaphragm............................. 349
Electric pumps--transmission and storage
segment:
One diaphragm.............................. 267
Two diaphragm.............................. 267
Three diaphragm............................ 267
Four diaphragm............................. 267
Compressed air-driven pumps--production
segment:
One diaphragm.............................. 3,461
Two diaphragm.............................. 1,731
Three diaphragm............................ 1,154
Four diaphragm............................. 865
Compressed air-driven pumps--transmission and
storage segment:
One diaphragm.............................. 2,649
Two diaphragm.............................. 1,325
Three diaphragm............................ 883
Four diaphragm............................. 662
------------------------------------------------------------------------
Sites Without Electricity
------------------------------------------------------------------------
Electric solar pumps--production segment:
One diaphragm.............................. 395
Two diaphragm.............................. 395
Three diaphragm............................ 395
Four diaphragm............................. 395
Electric solar pumps--transmission and storage
segment:
One diaphragm.............................. 302
Two diaphragm.............................. 302
Three diaphragm............................ 302
Four diaphragm............................. 302
Compressed air-driven pumps with a generator--
production segment:
One diaphragm.............................. 6,143
Two diaphragm.............................. 3,072
Three diaphragm............................ 2,048
Four diaphragm............................. 1,536
Compressed air-driven pumps with a generator--
transmission and storage segment:
One diaphragm.............................. 4,702
Two diaphragm.............................. 2,351
[[Page 16934]]
Three diaphragm............................ 1,567
Four diaphragm............................. 1,176
Route pump emissions to process through
existing VRU--production segment:
One diaphragm.............................. 251
Two diaphragm.............................. 251
Three diaphragm............................ 251
Four diaphragm............................. 251
Route pump emissions to process through
existing VRU--transmission and storage
segment:
One diaphragm.............................. 192
Two diaphragm.............................. 192
Three diaphragm............................ 192
Four diaphragm............................. 192
Route pump emissions to existing control
device--production segment:
One diaphragm.............................. 264
Two diaphragm.............................. 264
Three diaphragm............................ 264
Four diaphragm............................. 264
Route pump emissions to existing control
device--transmission and storage segment:
One diaphragm.............................. 202
Two diaphragm.............................. 202
Three diaphragm............................ 202
Four diaphragm............................. 202
Route pump emissions to process through new
VRU--production segment:
One diaphragm.............................. 7,719
Two diaphragm.............................. 3,985
Three diaphragm............................ 2,740
Four diaphragm............................. 2,118
Route pump emissions to process through new
VRU--transmission and storage segment:
One diaphragm.............................. 5,908
Two diaphragm.............................. 3,050
Three diaphragm............................ 2,098
Four diaphragm............................. 1,621
Route pump emissions to new control device--
production segment:
One diaphragm.............................. 7,971
Two diaphragm.............................. 4,234
Three diaphragm............................ 2,988
Four diaphragm............................. 2,366
Route pump emissions to new control device--
transmission and storage segment:
One diaphragm.............................. 6,101
Two diaphragm.............................. 3,241
Three diaphragm............................ 2,287
Four diaphragm............................. 1,811
------------------------------------------------------------------------
\a\ For the production segment, the owners and operators realize the
savings for the natural gas that is not emitted and not lost. The cost
effectiveness values shown in this summary table do not consider these
savings. If the EPA were to consider these savings, then the cost
effectiveness figures in the table ($/ton methane reduced) would
reduce, which would mean the options assessed would be even more cost
reasonable than already shown in this table.
As seen in tables 20 and 21, for sites without electricity with
three diaphragm pumps, the cost effectiveness values for all options
fall within the ranges typically considered reasonable by the EPA.
Specifically, for new sources at production sites, the single-pollutant
cost effectiveness of solar-powered electric controllers is $395 per
ton of methane and $1,421 per ton of VOC. For compressed air systems
driven by a generator, the single-pollutant cost effectiveness value
for methane is $1,857 per ton, which is considered reasonable, as are
the multipollutant cost effectiveness values ($929 per ton of methane
and $3,341 per ton of VOC). For the transmission and storage segment,
the single-pollutant methane cost effectiveness for solar-powered
electric controllers is $302 per ton and $1,422 per ton for compressed
air systems driven by a generator. These are both within the range
considered reasonable for methane.
For existing sources without access to grid power, the methane cost
effectiveness value for production sites with three diaphragm pumps is
$395 per ton for solar-powered electric pumps and $2,048 per ton for
compressed air systems powered by a generator. At transmission and
storage sites, for the otherwise same sources (existing sources without
electricity, with three diaphragm pumps), methane cost effectiveness
values are $302 per ton for solar-powered electric pumps and $1,567 per
ton for compressed air systems powered by a generator. These values are
all within the ranges considered reasonable for methane.
For sites without electricity with one or two diaphragm pumps, the
cost effectiveness values for compressed air systems powered by a
generator are not consistently within the range considered reasonable
by the EPA. This leaves solar-powered electric pumps as the only option
evaluated that has cost effectiveness values in the range
[[Page 16935]]
considered reasonable by the EPA for both the production and the
transmission and storage segments. However, the EPA has some concerns
about the technical feasibility of solar-powered pumps in some
situations. Specifically, the Carbon Limits report, which was a
reference the EPA relied upon for this analysis, states that ``[s]ites
with a large number of pumps or with pumps with high energy or power
demand may represent a challenge for 100 percent solar-powered electric
systems. In addition, shortly after completion, some wells may require
high volumes of methanol injection, and powering pumps to inject this
high volume can strain these systems.'' \383\
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\383\ Carbon Limits. (2016) Zero emission technologies for
pneumatic controllers in the USA--Applicability and cost
effectiveness. Available at https://www.carbonlimits.no/wp-content/uploads/2017/01/Report_FINAL.pdf.
---------------------------------------------------------------------------
While the EPA believes that solar-powered pumps are suitable for
some applications, the EPA acknowledges concerns about their technical
feasibility in some situations experienced at oil and gas sites. The
EPA concluded that it is not appropriate to establish BSER based solely
on solar-powered pumps. Therefore, the EPA created three subcategories:
(1) Pumps at sites with access to electrical power, (2) pumps at sites
without electrical service with three or more natural gas-driven
diaphragm pumps, and (3) pumps at sites without electrical service with
fewer than three natural gas-driven diaphragm pumps. The BSER
determinations for these categories are discussed below. These
determinations apply for both new and existing sources.
a. Pumps at Sites With Access to Electrical Power
The options evaluated for sites with electrical power are electric
pumps and pneumatic pumps driven by compressed air systems. The EPA
considers both of these options to be adequately demonstrated. For all
scenarios at sites with electricity, the cost effectiveness values are
within the range considered reasonable by the EPA (see tables 20 and
21). There could be secondary air impacts associated with the
generation of the additional electricity, but those impacts are
expected to be negligible. See the NSPS OOOOb and EG OOOOc TSD for this
rulemaking for a discussion of these impacts. In conclusion, the EPA
determined that a zero-emissions standard represents the BSER for pumps
at sites with access to electrical power. This includes all diaphragm
and piston pumps included in the affected facility at the site.
b. Pumps at Sites Without Electrical Service With Three or More Natural
Gas-Driven Diaphragm Pumps
The options evaluated for sites without access to electrical power
are solar-powered electric pumps and pumps driven by compressed air
systems powered by a generator. As discussed above, the EPA considers
pumps driven by compressed air systems powered by a generator to be
adequately demonstrated. While the EPA recognizes the technical
limitations of solar-powered pumps for some applications, the EPA finds
that they are an option for many sites. For all scenarios where three
or more diaphragm pumps are present at a site without electricity, the
cost effectiveness values for both solar-powered pumps and compressed
air systems are within the range considered reasonable by the EPA (see
tables 20 and 21). There will be secondary air impacts associated with
the use of generators, but based on a site-specific analysis, the EPA
concludes that the benefits of the methane and VOC reductions outweigh
the potential negative impacts. See section XI.D.2 of this document and
the NSPS OOOOb and EG OOOOc TSD for this rulemaking for a discussion of
these secondary air impacts from generators. While not shown here, for
sites without access to electrical power that contain only piston
pumps, the EPA did not identify any control options resulting in zero
emissions that were considered cost effective. However, if a non-
natural-gas zero-emissions system is installed to reduce diaphragm pump
emissions, it would be cost effective to also use zero-emissions piston
pumps. Therefore, the BSER determination for pumps at sites without
access to electrical power and three or more diaphragm pumps is zero
emissions of GHG (methane) and VOC. This is the BSER determination
regardless of the number of piston pumps at the site. In conclusion,
the EPA determined that BSER for pumps at sites with three or more
diaphragm pumps without access to electrical power is zero emissions of
methane and VOC from all diaphragm and piston pumps at the site.
c. Pumps at Sites Without Access to Electrical Power With Fewer Than
Three Natural Gas-Driven Diaphragm Pumps
As discussed above, given the EPA's conclusion that solar-powered
pumps are not technically feasible for some common applications and the
fact that the analysis did not show cost effectiveness values of a
compressed air system powered by a generator to be consistently within
the range that the EPA considers reasonable at sites with fewer than
three diaphragm pumps, the EPA concludes that a zero-emissions standard
does not reflect the BSER for sites without access to electrical power
that have fewer than three diaphragm pumps.
For this subcategory, the EPA evaluated other emissions control
options, including routing the emissions to a process and routing the
emissions to a combustion device. In most cases, a VRU will be required
to enable the captured gas from the pump to be routed to a process.
Therefore, costs were estimated for installing a closed vent system and
VRU in order to route the gas to a process. It was assumed that this
would achieve a 100 percent reduction in methane and VOC emissions.
Costs were also estimated to install a closed vent system and a new
combustion device to reduce the emissions, assuming a methane and VOC
reduction of 95 percent. The EPA considers both routing emissions to a
process and routing emissions to a combustion device to be adequately
demonstrated emissions reduction techniques. As shown in tables 20 and
21, both options of routing emissions to a process via a new VRU or to
a new combustion device have cost effectiveness values outside the
ranges the EPA considers reasonable. Therefore, the EPA concludes that
requiring the installation of a new VRU or control device for pumps at
these sites is not the BSER.
The EPA also evaluated routing emissions through an existing VRU to
a process (or routing directly to a process if that is possible) and
routing emissions to an existing combustion device. Both of these
options are adequately demonstrated since the emissions reduction
technique is already being used for other equipment at the site.
Further, the cost effectiveness of both options is in the range
considered reasonable by the EPA. Therefore, the EPA concludes that,
for sites without access to electricity and fewer than three diaphragm
pumps, the BSER is routing to a process where an existing VRU is
available or to a combustion device where an existing one is available.
d. Summary of Final Rule
Considering our revised analysis and BSER determinations, for
affected and designated facilities at sites with access to electrical
power and at sites without access to electrical power with three or
more diaphragm pumps, the final rule and presumptive standard require
these facilities to have zero GHG (methane)
[[Page 16936]]
and VOC emissions from all diaphragm and piston pumps. Zero emissions
may be achieved either by using pumps not powered by natural gas (and
thus not an affected or designated facility) or by routing natural gas-
driven pump emissions through a CVS to a process. As explained in the
December 2022 Supplemental Proposal, the EPA understands that emissions
routed through a CVS to a process would achieve a 100 percent emissions
reduction from the pumps and therefore would meet a zero-emissions VOC
and GHG standard. Like what was included in the supplemental proposal,
the CVS demonstration requirements that there are no identifiable
emissions from the CVS apply in the final rule. Unlike what was
proposed, the final rule does not require a demonstration that using
pumps not driven by natural gas is infeasible before compliance by
routing emissions to a process is allowed.
For sites without access to electrical power with fewer than three
diaphragm pumps, the final requirements are that natural gas-driven
pump emissions must be routed through a CVS to a process if the site
has a VRU, but if the site does not have a VRU, emissions can be routed
to an onsite control device that achieves a 95 percent emissions
reduction. If there is no control device onsite that achieves a 95
percent emissions reduction, emissions must be routed to a control
device(s) onsite that achieves less than a 95 percent emissions
reduction. If no VRU or control devices are onsite, emissions from
natural gas-driven pumps are not required to be controlled. A summary
comparison of the emissions standards included in the December 2022
Supplemental Proposal and the final rule is included in table 22.
Table 22--Comparison of Pump NSPS Standards and EG Presumptive Standards Between the Supplemental Proposal and
the Final Rule
----------------------------------------------------------------------------------------------------------------
Supplemental proposal
affected/designated Final rule affected/
Standard/presumptive standard facility site designated facility Difference(s)
characteristics site characteristics
----------------------------------------------------------------------------------------------------------------
Zero emissions..................... Sites with electricity Sites with electricity Supplemental proposal
and Sites with >=3 required non-natural gas-
diaphragm pumps. driven pumps; final rule
allows non-natural gas-
driven pumps and/or
routing pump emissions
through CVS to a process
and/or other control means
that achieves zero
emissions.
95 percent control................. Sites without No sites.............. 95 percent emissions
electricity and >=4 reduction required under
diaphragm pumps. supplemental proposal
after demonstrations that
it is technically
infeasible to use non-gas
driven pump, and to route
emissions through a CVS to
a process; 95 percent
emissions reduction not
directly required for any
sites in the final rule.
Route emissions to existing control Sites without Sites without Use of control device
device. electricity and <4 electricity and <3 required under
diaphragm pumps. diaphragm pumps. supplemental proposal
after demonstrations that
it is technically
infeasible to use non-gas
driven pump and to route
emissions to a process;
technical infeasibility
demonstrations not
required in final rule,
but final rule requires
routing emissions to a
process if a VRU is onsite
before a control device
can be used.
----------------------------------------------------------------------------------------------------------------
It should be noted that there are similarities between the BSER
analyses for natural gas-driven pumps and natural gas-driven process
controllers. For both types of sources, the EPA evaluated a number of
options that are not powered by natural gas and thus have zero methane
and VOC emissions. As discussed above, for sites without access to
electrical power with fewer than three diaphragm pumps, there are no
cost-effective zero-emissions control options that the EPA found to be
adequately demonstrated. For pumps at these sites, the only zero-
emissions option with values the EPA considers to be cost-effective was
solar-powered pumps. Given the power needs for some pumps to properly
operate and the potential inadequacies of solar-powered systems to
provide that amount of energy, the EPA determined that solar-powered
systems do not represent BSER for pumps. Therefore, the EPA created a
subcategory for sites without access to electrical power and fewer than
three pumps and established different emissions control requirements
for that subcategory. In contrast, for controllers, there was more than
one adequately demonstrated zero-emissions option evaluated for every
sized model plant throughout the sectors with cost effectiveness values
considered reasonable. Therefore, even if there are power limitations
for solar-powered process controllers, which require much less energy
than pumps to properly operate, there are other cost-effective zero-
emissions options available, and consideration of other emissions
control options or subcategories of process controller affected
facilities was not necessary.
Comment: In the December 2022 Supplemental Proposal, the EPA
proposed a hierarchy of emissions control requirements for sites that
did not have access to electrical power. Under this approach, the EPA
proposed that an owner or operator would be required to first evaluate
pump options that do not use natural gas and provide a certified
demonstration that such options are infeasible before being allowed to
use the next tier of emissions control options. For instance, at sites
without access to electrical power, the proposal allowed for pump
emissions to be routed to a process, but only after certified
assessments were made demonstrating that it was technically infeasible
to use solar-powered pumps and infeasible to use pumps powered by
compressed air. One commenter stated that the EPA should remove the
certifications associated with the hierarchy of pump compliance
options. The commenter stated that the proposed certification
requirements are unreasonably onerous because, in each case, the
certifying individual must essentially prove a negative--that the
otherwise applicable zero-emissions approaches are ``technically
infeasible.'' The commenter stated that there is no definition of
technical infeasibility in the proposed rule, but the words could be
construed as setting an exceedingly
[[Page 16937]]
high bar, such that a given non-emitting technique is ``infeasible''
based solely on a technical assessment of whether it can theoretically
be physically applied in the given situation, even though it could be
inordinately expensive. According to the commenter, this outcome would
not be lawful because it would violate the statutory requirement that
BSER and the corresponding standard of performance must be cost-
effective. The commenter added that a ``technical infeasibility''
standard allows for second-guessing by regulators or citizen enforcers,
which invites a ``battle of the experts'' in potential enforcement
actions. According to the commenter, this diminishes the possibility
that the opt-outs can be implemented with reasonable certainty.
The commenter also reported that the express threat of possible
personal liability on the part of certifiers will limit the number of
individuals willing to make the needed certifications, particularly
considering the uncertainties about what will be needed as a practical
matter to demonstrate ``technical infeasibility.'' The commenter stated
that the clear opportunity and possibility of second-guessing will be
further material disincentives.
Response: In consideration of these comments, the EPA reviewed the
proposed ``certification of infeasibility'' requirements. The EPA
restructured the final standards for pumps based on comments received
on the December 2022 Supplemental Proposal. The final rule no longer
includes the complex hierarchy of technical feasibility demonstrations
that was included in the December 2022 Supplemental Proposal. Instead,
the final rule includes a subcategory based on clear criteria such that
sources can be certain as to which emissions standards apply without
demonstrations of technical infeasibility.
Comment: One commenter mentioned that the EPA proposed to allow
operators to route natural gas-driven pump emissions to a control
device, but only if the operators can demonstrate that routing to a
process is technically infeasible and that it is infeasible to use
pumps not driven by natural gas. The commenter urged the Agency to
recognize the substantial investments that operators have already made
to route emissions from pumps to control devices by allowing any
natural gas-driven pump to be routed to controls--not only in
situations where non-natural-gas technology and routing to a process
are each technically infeasible.
Response: As explained above, for the final rule we have removed
the proposed requirement for demonstrations of technical infeasibility
before the use of other equivalent control options may be used for
pumps. In the final rule, we have further added the conditions under
which pump emissions may be routed to a control device, which reflect
our BSER determinations. For sites without access to electrical power
and that have two or fewer diaphragm pumps, pump affected facility
emissions may be routed to a control device if there is no VRU onsite.
2. Compliance Dates
Comment: Two commenters state that a 60-day compliance deadline for
new/modified sources is unrealistic due to supply chain concerns,
personnel shortages, and inflation. Due to supply chain shortages and
disruption, one commenter reports that companies are experiencing
backorders for some equipment, including non-natural-gas-driven pumps,
generator skids, and air compressor skids, with current lead times
ranging up to 12 months. The commenters note that there is no
indication that this lead time will improve in the near future and
believe it can be expected to worsen as owners and operators across the
country increase demand in response to the final rule. One commenter
recommended a compliance deadline of 12 to 26 months from the
publication date of the final rule and one commenter proposed at least
a 1-year timeframe for NSPS OOOOb compliance to allow for procurement
and installation of the systems and equipment necessary (including
labor necessary for installation).
One commenter requested that the EPA extend implementation
timelines--particularly for sources that became NSPS OOOOb affected
facilities prior to the date of final rule publication. The commenter
remarked that until the effective date of NSPS OOOOb, some of these
facilities would be unregulated under an existing NSPS or would begin
operating as NSPS OOOOa affected facilities and may then need to
complete retrofits to comply with newly applicable NSPS OOOOb
standards. For example, the commenter states that NSPS OOOOa pneumatic
pumps are not subject to a zero-emissions standard but would be subject
to zero-emissions standards under NSPS OOOOb, requiring retrofit within
60 days after the final rule's publication in the Federal Register.
According to the commenter, this is not enough time to acquire retrofit
equipment that will be in high demand, and likely short supply, as
operators across the country place orders for equipment to meet the
zero-emissions standard. In addition, the commenter reports that
operators must acquire engineering resources to engineer the
installation of zero-emissions pneumatic systems. They report that
these engineering resources, too, are likely to be in high demand and
short supply. The commenter asserts that the timing of compliance
obligations is particularly pronounced for pneumatic pumps, as
according to the commenter, operators may no longer use pneumatic pumps
that are driven by natural gas, subject to limited exceptions. The
commenter notes that the November 2021 Proposal did not go so far as to
eliminate the use of natural gas-driven pneumatic pumps entirely. The
commenter states that operators may need to completely replace natural
gas-driven pneumatic pumps that would have complied with the standards
described in the November 2021 Proposal.
Response: Based on these comments, and for the same reasons
explained in section XI.D.4 of this preamble for process controllers,
the EPA is finalizing a NSPS compliance deadline for pumps required to
meet a zero-emissions standard that allows for up to 1 year from the
effective date of the final rule.
The equipment that owners and operators will need to comply with
the final standard of zero emissions for pumps is, in some situations,
the same equipment that owners and operators will need to comply with
the final standard for process controllers. Based on comments, it
appears that some equipment necessary for the installation of zero-
emitting pumps may not be available quickly enough, and in large enough
quantities, to enable new sources to comply with the final standard
upon startup, or within 60 days after the publication of the final
NSPS. As is the case for process controllers, the equipment types that
the EPA believes are necessary to comply with the final zero-emissions
standard for pumps in NSPS OOOOb are quite different from the type of
equipment used to comply with the standards for these sources found in
NSPS OOOOa. Due to these considerations, the EPA is not certain that
new sources needing to meet the zero-emissions standard could obtain
the equipment necessary to demonstrate compliance on the proposed
timeline. This change to the final rule compliance timeline in NSPS
OOOOb for pumps does not apply to sites without access to grid
electricity that have fewer than three diaphragm pumps because those
sites are not required to demonstrate zero emissions.
Until the final date of compliance with the zero-emissions
standard,
[[Page 16938]]
owners/operators must demonstrate compliance with an interim standard
which mirrors the requirements for pumps at sites without access to
grid electricity that have fewer than three diaphragm pumps found at 40
CFR 60.5393b(b). In summary, the standards for these sites require that
GHG and VOC emissions from all natural gas-driven pumps in the affected
facility be routed to a process if a VRU is onsite. If a VRU is not
onsite, emissions must be reduced by 95 percent if a control device
with at least this emissions reduction capability is already available
onsite or may be reduced by less than 95 percent if a control device is
onsite but is not capable of reducing GHG and VOC emissions by 95
percent or more. As these requirements are similar to the current NSPS
OOOOa requirements for pumps at well sites, owners/operators of new and
recently modified or reconstructed sites subject to NSPS OOOOb will be
able to readily obtain the equipment necessary for this interim
standard, to the extent that equipment is even necessary. The only
difference compared to NSPS OOOOa is that NSPS OOOOb requires emissions
to be routed to a process if a VRU is already on the site. The
information available to the EPA and provided by commenters does not
suggest any equipment backlogs for common piping that may be needed to
route emissions to a process through a VRU. Complying with the interim
standard described above does not require using the equipment that
commenters claimed they could not easy obtain (i.e., the equipment
needed to meet the zero-emissions standard). Therefore, the EPA expects
no sites to have any problems complying with these interim requirements
within 60 days after publication of the final rule. If an owner or
operator opts to comply with the interim standard during the one year
following publication of the final rule, then they must still comply
with the final zero-emissions standard after the year has passed.
Owners and operators can, and are encouraged to, comply with the final
zero-emissions standard before the year has passed.
3. Recordkeeping and Reporting Requirements for Pumps Not Included in
the Affected Source
Comment: Commenters pointed out that 40 CFR 60.5410b(g)(1) requires
owners and operators to submit an identification of all pumps that are
not powered by natural gas in the initial annual report required by 40
CFR 60.5420b(b)(10)(i), and such pumps are not part of the pumps
affected facility definition. The commenters recommended that owners or
operators only be required to maintain records sufficient to determine
compliance with the regulations. The commenters contend that having
requirements for equipment that is not part of an affected source
exceeds the EPA's authority granted under CAA section 111 and add that
there is no environmental benefit to keeping or submitting information
for equipment that cannot have emissions. The commenters recommended
that the EPA remove any reporting or recordkeeping requirements for
these pumps from the final regulations.
Response: After considering this comment, we have determined that
it is appropriate in this instance to require identification of the
equipment that is included in the affected facility, rather than the
equipment that is not part of the affected facility. The pumps included
in the affected facility are those that are subject to the emissions
standards in the rule, whereas pumps not included in the affected
facility are not subject to the emissions standards in the rule and
also have no potential to emit methane or VOCs. Therefore, we have
revised the recordkeeping requirements to require identification only
of pumps that meet the finalized definition of an affected facility,
which are those pumps that are driven by natural gas and that are in
operation for 90 days or more in a calendar year.
4. Modification and Reconstruction Criteria and Requirements
Comment: Commenters requested that the EPA clarify that, for
purposes of the collection of controllers or pumps at a site, a
modification occurs only when a natural gas-driven pump is added. The
commenters pointed out that the addition of a pump not driven by
natural gas would not increase emissions from the affected source.
Commenters also requested that the EPA clarify which pumps would be
considered in the determination of whether a reconstruction has taken
place.
Response: While it was our intention in the December 2022
Supplemental Proposal to only include the addition of natural gas-
driven pumps in the conditions that would constitute a modification, as
only those pumps could increase emissions, we agree that the proposed
regulatory text did not specify this. We therefore have updated what we
proposed for regulatory language to clarify that the addition of one or
more natural gas-driven pumps to a site constitutes a modification. We
also are clarifying in the final rule that reconstruction would be
considered to occur whenever greater than 50 percent of the number of
existing onsite natural gas-driven pumps are replaced.
Comment: In addition to these clarifications regarding the criteria
for determining whether a modification or reconstruction has taken
place, one commenter stated that it is unclear how the notification
requirements of 40 CFR 60.15 apply for reconstruction. The commenter
noted that the proposed language in 40 CFR 60.5365b(d)(2)(ii) suggests
that reconstructed natural gas-driven pumps would be subject to some of
the requirements included in 40 CFR 60.15, which include 60-day
notification and Administrator approval. According to the commenter,
this conflicts with information presented in table 5 of the regulatory
text, which states that 40 CFR 60.15(d) does not apply to pumps. The
commenter believes it was the EPA's intent to not apply the additional
notification and approval, given the number of facilities that will
trigger reconstruction over time.
Response: We agree that we did not intend for facilities to be
required to notify the Administrator of upcoming pump replacements that
would constitute a reconstruction or for the Administrator to be
required to review the notification and determine whether the
replacements constitute a reconstruction. We have updated what we
proposed for regulatory text to not refer to the requirements of 40 CFR
60.15(d) and have kept the information presented in table 5 of the
proposed regulatory text, which states that 40 CFR 60.15(d) does not
apply to pumps.
5. Change in Pneumatic Pump Terminology
In addition to the revisions to the modification and reconstruction
criteria and requirements for pumps, to assist with avoiding possible
confusion about which types of pumps are included within the definition
of the affected facility and which types of pumps must be considered
for purposes of the reconstruction and modification provisions, we have
changed the terminology of ``pneumatic pumps'' (used in both the
November 2021 Proposal and the December 2022 Supplemental Proposal) to
simply ``pumps'' in the final rule. The EPA has made this change both
in the final rule preamble and the final regulatory text. The term
``pumps'' is broader in scope because it includes pneumatic pumps as
well as other types of pumps that are not pneumatic. Only a subset of
pumps used by oil and gas facilities are pneumatic pumps that use
pressurized air or gas to perform their functions. Other pumps might
use electricity to
[[Page 16939]]
perform their functions. From a technical perspective, electronic pumps
are not true ``pneumatic'' devices, but these electronic pumps can be
used to achieve the zero-emissions standard. The EPA changed the
terminology because we did not want to inadvertently convey that
misimpression that pumps had to be pneumatic. To be clear, the final
rule applies to the collection of natural gas-driven pumps. Pumps that
are not driven by natural gas are not included in the affected
facility. Further, only pumps driven by natural gas will be counted
when determining whether a modification or reconstruction has occurred.
F. Wells and Associated Operations
In the December 2022 Supplemental Proposal, the EPA proposed to
define a well affected facility, and well designated facility, to
consist of a single well. The EPA also proposed standards for well
affected facilities and designated facilities for oil wells with
associated gas, gas wells that undergo liquids unloading, and wells
that undergo completions. A summary of the comments received and the
EPA's response to these comments, including any changes made to the
final rule, as applicable, are provided below. The EPA's full response
to comments on the November 2021 Proposal and December 2022
Supplemental Proposal, including any comments not discussed in this
preamble, can be found in the EPA's RTC document for the final
rule.\384\
---------------------------------------------------------------------------
\384\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
---------------------------------------------------------------------------
1. Well Affected Facility and Designated Facility Definitions
In the December 2022 Supplemental Proposal, rather than including
three separate definitions for well affected facilities (as initially
proposed in the November 2021 Proposal) for (1) oil wells with
associated gas, (2) gas wells that undergo liquids unloading, and (3)
wells that undergo completions, the EPA proposed a single definition
for a well affected facility, which was defined as a single well, in
the proposed NSPS OOOOb. A well is defined as a hole drilled for the
purpose of producing oil or natural gas. The EPA proposed separate
standards for well completions, associated gas from oil wells, and gas
well liquids unloading operations, all or some of which could apply to
a given well affected facility. A well affected facility would be
required only to comply with the standards that are applicable to the
well. For example, a gas well would not be subject to the standard for
oil wells with associated gas. The proposed NSPS OOOOb specified that a
modification to an existing well occurs when the definition of
modification in 40 CFR 60.14 is met, including when an existing well
undergoes hydraulic fracturing or refracturing.
For the EG OOOOc rule, the EPA proposed, similar to NSPS OOOOb, a
definition of well designated facility as a single well. Modification
provisions do not apply under EG OOOOc. The December 2022 Supplemental
Proposal included proposed presumptive standards for associated gas
from oil wells and gas well liquids unloading. However, since the
fracturing or refracturing of an existing well would constitute a
modification under NSPS OOOOb, which would make the well a well
affected facility under NSPS OOOOb, there would never be an existing
well subject to well completion requirements and no requirements are
specified for well completions under EG OOOOc. More discussion of the
well affected facility/designated facility specific to each of the
three associated well operations is provided in sections X.F.2, 3, and
4 of this document.
The EPA did not receive comments on the proposed definition of a
well affected facility or designated facility that warranted changes to
what was proposed in the December 2022 Supplemental Proposal.
Therefore, the definitions have been finalized as proposed.
2. Associated Gas From Oil Wells
In section X.F.2 of this document, the final NSPS OOOOb and EG
OOOOc requirements for oil wells with associated gas are summarized.
The EPA received many comments on the December 2022 Supplemental
Proposal on the following topics: the definition of associated gas, the
BSER analysis for new wells, BSER for existing wells, temporary venting
and flaring, and the infeasibility determination and certification. For
each of these topics, a summary of the proposed rule, the comments, the
EPA responses, and changes made in the final rule (if applicable), are
discussed here. These comments and the EPA's responses to these
comments generally apply to the standards and presumptive standards in
both the NSPS OOOOb and EG OOOOc respectively. The instances where the
comment and/or response only applies to NSPS OOOOb or EG OOOOc are
noted. The EPA's full response to comments on the November 2021
Proposal and December 2022 Supplemental Proposal, including any
comments not discussed in this preamble, can be found in the EPA's RTC
document for the final rule.\385\
---------------------------------------------------------------------------
\385\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
---------------------------------------------------------------------------
a. Definition of Associated Gas
Neither the November 2021 Proposal nor the December 2022
Supplemental Proposal included a definition of ``associated gas.''
Comment: Several commenters \386\ suggested that a definition of
``associated gas'' be added. Commenters expressed that it is important
for the EPA and the regulated community to have a common understanding
of the definition of associated gas. One commenter added that, without
a definition, the term ``associated gas'' could take on various
meanings including the most literal interpretation of any gas
associated with oil well production, which might include emissions from
other NSPS OOOOb or EG OOOOc affected/designated facility types that
the EPA regulates in other sections of its proposal--e.g., a collection
of fugitive emissions components or storage vessels. Commenters
provided several suggestions for this definition, including:
---------------------------------------------------------------------------
\386\ EPA-HQ-OAR-2021-0317-2248, -2294, -2326, -2360, and -2428.
---------------------------------------------------------------------------
Associated gas means the gas that can be separated from
the produced liquids in the first stage of separation at a pressure
sufficient for it to flow into the gathering system.
Associated gas means the natural gas which originates at
wells operated primarily for oil production and occurs either in a
discrete gaseous phase at the wellhead or is released from the liquid
hydrocarbon during the initial stage of separation after the wellhead.
Associated gas means the natural gas which originates at
oil wells operated primarily for oil production and occurs either in a
discrete gaseous phase at the wellhead or is released from the liquid
hydrocarbon during the initial stage of separation after the wellhead.
Associated gas means the natural gas evolved from
hydrocarbon liquids during the initial stage of separation following
production from the wellhead. Associated gas does not
[[Page 16940]]
include natural gas associated with well completion or downhole well
maintenance activities.
Response: The EPA agrees with the commenters that a definition of
associated gas would be beneficial to provide clarity to regulatory and
enforcement agencies and to the regulated community. First, our
intention is to regulate the gas that is released from the liquid at
the first stage of separation, so we included that characteristic in
the definition in the final NSPS OOOOb and EG OOOOc.
One commenter suggested that the EPA define associated gas by using
the phrase ``in a discrete gaseous phase at the wellhead,'' arguing
that this description is necessary to avoid a broad interpretation of
associated gas that encompasses any gas associated with oil well
production. The EPA believes that the commenter's suggested language is
not necessary to clearly define associated gas and believes that it
could add confusion.
We do not believe that the most literal interpretation offered by
the commenter that any gas associated with oil well production might be
considered associated gas, and we do not feel a need to include such a
clarification in the definition. However, we recognize that there could
be confusion between the emissions associated with well completions and
associated gas. This is particularly the case in situations where a
permanent separator has been placed onsite during the completion
activities and used during the separation flowback stage. The
definition of flowback in 40 CFR 60.5430b of the final rule specifies
that the flowback period ends when either the well is shut in and
permanently disconnected from the flowback equipment or at the startup
of production. This provides a clear distinction between when the
completion flowback requirements end and the associated gas production
begins. Therefore, the final definition of associated gas includes the
phrase, ``Associated gas production begins at the startup of production
after the flowback period ends.'' The full definition of ``associated
gas'' for this final rule is included below and can also be found at 40
CFR 60.5430b and 40 CFR 60.5430c.
Comment: One commenter \387\ requested that the EPA allow certain
provisions for wildcat or delineation wells in its proposal with
respect to the associated gas from oil well provisions. The commenter
explains that such wells are exploratory in nature and are typically
located in remote locations far from any form of permanent
infrastructure, including gathering infrastructure. Wildcat or
delineation wells will typically only produce for a short period of
time after flowback ends in order to complete well testing, which is
used to determine the production flow rate along with other parameters
such as the gas composition before the well is shut in or capped in
accordance with state protocols. According to the commenter, in many
instances an operator will not know or understand the composition of
the gas until after the well is drilled. The commenter suggests that
this combination of characteristics makes it impracticable to install
gas gathering infrastructure or plan for other forms of beneficial use
at a wildcat or delineation well. Noting that the EPA has exempted such
wells from NSPS OOOOa standards for well completions, the commenter
recommends that the EPA allow special considerations for handling
associated gas since these activities are exploratory in nature and are
typically not located near existing infrastructure.
---------------------------------------------------------------------------
\387\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------
Response: The EPA acknowledges that the types of associated gas
wells that are the focus of these rule requirements are wells that
consistently produce, and potentially emit, natural gas. The temporary
nature of wildcat and delineation wells is not conducive to warrant the
construction of piping to connect to a natural gas gathering system or
to utilize another solution where the gas could be used. Further, as
noted by the commenter, the owners and operators of wildcat or
delineation wells typically do not have knowledge of the nature and
composition of the gas until after the well is drilled, which further
hinders the ability to implement a beneficial-use solution. Therefore,
the EPA has clarified in the definition of associated gas that gas from
wildcat or delineation wells, which are defined in 40 CFR 60.5430b, is
not associated gas for purposes of regulation under NSPS OOOOb and EG
OOOOc. In response to these comments, the final rule includes the
following definition in 40 CFR 60.5430b and 40 CFR 60.5430c:
b. BSER Analysis for New Wells
In the November 2021 Proposal, the EPA determined that the BSER for
associated gas was routing the associated gas from oil wells to a sales
line. In the preamble for the November 2021 Proposal (86 FR 63236-39),
and in the associated TSD, the EPA evaluated several equivalent options
that would all effectively eliminate direct emissions of VOC and
methane from associated gas, including routing the associated gas to a
sales line, utilizing the associated gas in a ``beneficial'' manner,
and reinjecting the gas. Regarding the cost impacts of routing the gas
to a sales line, the EPA assumed ``that in situations where gas sales
line infrastructure is available, there is minimal cost to owners and
operators to route the associated gas to the sales line. While
situations at well sites can differ, which would impact this cost, the
EPA believes that in every situation the value of the natural gas
captured and sold would outweigh these minimal costs of routing the gas
to the sales line, thus resulting in overall savings.'' 86 FR 63237.
The EPA then concluded with, ``Given the prevalence of this practice,
the environmental benefit, and the economic benefits to owners and
operators, the EPA concludes that BSER is routing associated gas from
oil wells to a sales line.'' 86 FR 63237. However, in 2021, the EPA
also recognized that there are situations where there would not be
access to a sales line and therefore also evaluated the costs and
impacts of routing associated gas to a flare.
In the December 2022 Supplemental Proposal, the EPA again
determined that BSER was routing the associated gas to a sales line and
again proposed this requirement. The supplemental proposal also
included that ``[i]f access to a sales line is not available, the gas
can be used as an onsite fuel source or used for another useful purpose
that a purchased fuel or raw material would serve. If demonstrated that
a sales line and beneficial uses are not technically feasible, the gas
can be routed to a flare or other control device that achieves at least
95 percent reduction in methane and VOC emissions.'' 87 FR 74710.
While no comments were received on the EPA's earlier assertion in
the November 2021 Proposal that there would be minimal cost to route
the gas to an available sales line, comments were received on the
flaring analysis. As a result of these comments, the EPA updated the
flaring analysis in the December 2022 Supplemental Proposal. This
updated flaring analysis assumed an initial capital cost of $100,579 to
install a new flare, which was the recommended cost provided by a
commenter. Assuming a 7 percent interest rate and 10-year capital
recovery period, along with an annual maintenance and operational cost
of $25,000, the estimated annual cost was $36,044. Details of this cost
estimate are included in the TSD for the December 2022 Supplemental
Proposal.
The EPA also updated the analysis of the associated gas emissions
in the December 2022 Supplemental Proposal because the analysis
performed for the
[[Page 16941]]
November 2021 Proposal included emissions from associated gas wells
that the EPA concluded were not representative of ``routine'' venting
situations. The resulting analysis was a representative well with
uncontrolled potential associated gas emissions of 343.6 tpy of methane
and 96 tpy of VOC. The details of this analysis may also be found in
the TSD for the December 2022 Supplemental Proposal.
Comments were received on the December 2022 Supplemental Proposal
related to the representative baseline emissions analysis and the
assumption that the costs of routing to a sales line or other
beneficial use were minimal.
i. Baseline Emissions for Representative Well
Comment: One commenter \388\ stated that the EPA seemed to bias the
data selected for baseline emissions to fit their expectation rather
than using actual reported data. The commenter cited section 6.3.1 of
the supplemental proposal TSD.
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\388\ EPA-HQ-OAR-2021-0317-2428.
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Response: In the TSD for the December 2022 Supplemental Proposal,
the EPA identified 95 facilities/basins that reported associated gas
venting emissions (through GHGRP subpart W data) for 2019. For each
facility/basin, the number of wells venting is reported, along with the
total methane vented from all wells. For each facility/basin, we
calculated the average emissions per well. These average well emissions
ranged from 0.015 tpy to over 2,400 tpy. Almost 20 percent of the
facilities/basins had average well methane emissions lower than 0.2
tpy.
Explanations of the specific causes of emissions are not provided
in the GHGRP subpart W outputs, but it would be expected that routine
venting of associated gas would result in emissions greater than this
level as the DOE indicates that the average associated gas production
for an oil well is around 7.5 boe per day,\389\ which would be around
450 tons of methane emissions per year. In order to avoid selecting a
well associated gas venting level that was unreasonably low, a weighted
average well emissions level was calculated, using the total emissions
from the facility/basin as the weighting factor. The result is an
estimated average annual methane emissions level of 344 tpy. Applying
the representative composition yields a representative VOC emissions
level of 96 tpy.
---------------------------------------------------------------------------
\389\ https://www.eia.gov/petroleum/wells/pdf/full_report.pdf.
---------------------------------------------------------------------------
The intention of the analysis that the commenter discusses was to
develop an emissions level estimate that represented the routine
venting of associated gas--that is, situations where the associated gas
was vented and not usually routed to a sales line or used for another
purpose. As alluded to by the commenter, we assumed that the low
emitting situations likely represent instances where venting was only
temporary, and thus we discounted their contribution to the
representative emissions level. As discussed in detail in section
XI.F.2.f of this document, we recognized that the proposed rule did not
adequately distinguish between ``routine'' and ``temporary''
situations. The final rule includes limited conditional allowances for
venting in temporary situations where the associated gas is routed to a
sales line normally (or used for another beneficial purpose) but due to
circumstances or disruptions operators are not able to maintain normal
operations without temporarily venting.
In conclusion, the EPA continues to believe that the associated gas
emissions estimate levels used for the December 2022 Supplemental
Proposal's representative well appropriately characterizes a well that
routinely vents the gas. Therefore, no changes were made to the
representative well emissions level.
ii. BSER Cost Analysis
As noted earlier in this document, both in the November 2021
Proposal and in the December 2022 Supplemental Proposal, we assumed
that there would be minimal cost to route the gas to an available sales
line, which was determined to represent BSER.
Comment: In comments on the December 2022 Supplemental Proposal,
one commenter \390\ stated that the associated gas model plant analysis
did not include assumptions reflective of actual proposed requirements.
They pointed out that none of the beneficial reuse emerging
technologies were included in the model plant analysis, and that it was
unclear how the EPA justified the inclusion of these technologies
related to costs, feasibility, or environmental benefit/disbenefit.
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\390\ EPA-HQ-OAR-2021-0317-2428.
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Another commenter \391\ also recognized that the EPA declined to
quantitatively analyze the cost of routing to a sales line and the
other beneficial use options, but the commenter provided a study \392\
that included estimates of the costs of various gas recovery options.
Specifically, this study estimated the costs of routing to a sales line
(pipeline gathering), onsite use (for fueling equipment or for local
electricity generation), gas-to-wire, onsite compressed natural gas
(CNG), onsite liquefied natural gas (LNG), and gas reinjection. Based
on the cost data from this study, the commenter concluded that the cost
effectiveness values for all abatement methods are well within the
range that the EPA finds reasonable.
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\391\ EPA-HQ-OAR-2021-0317-2433.
\392\ Rystad Energy. ``Cost of Flaring Abatement, Final
Report.'' January 31, 2022.
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Response: While the first commenter indicated that the EPA did not
perform an analysis of the BSER options, the commenter did not provide
any information to support their comments. Contrary to this comment,
the EPA did perform a BSER analysis. The EPA found the study provided
by the second commenter to be informative regarding the extent of
flaring in the U.S. and fundamental considerations in non-flaring
abatement options. However, we closely examined this information and
determined that the basis for these cost estimates lacked some details
that the EPA thought necessary in order to use them as the basis for a
BSER analysis. See EPA-HQ-OAR-2021-0317-2433 attachment T to review the
data submitted.
In addition to following up with the single commenter that provided
cost information for non-flaring options,\393\ the EPA performed a
search for cost information from other sources. One source identified
with detailed cost information that the EPA found to be informative was
a study performed by ICF International for the Interstate Natural Gas
Association of America (INGAA) Foundation.\394\ In addition to a
plethora of information regarding midstream infrastructure, this study
included detailed costs for the installation of gathering and boosting
systems and associated lines. Specifically, it provided detailed cost
information for, among other things, pipeline costs and compression/
pumping costs. The gathering pipeline costs were provided starting in
2010 and projected to 2035 for pipe sizes ranging from 2 inches to 30
inches. In conversations with the authors of this
[[Page 16942]]
report,\395\ the commenter indicated that the most representative pipe
sizes for connecting a well to an existing gathering system were either
4 or 6 inches.
---------------------------------------------------------------------------
\393\ Please see June 5, 2023, meeting memorandum for meeting
between the EPA and EDF and Rystad in EPA-HQ-OAR-2021-0317.
\394\ North America Midstream Infrastructure through 2035
Significant Development Continues. The INGAA Foundation, Inc.
Prepared by ICF. June 18, 2018. Available at: https://ingaa.org/north-america-midstream-infrastructure-through-2035-significant-development-continues/.
\395\ See EPA Docket EPA-HQ-OAR-2021-0317 for record of June 21,
2023, call with INGAA Foundation/ICF.
---------------------------------------------------------------------------
This information was used to estimate the costs for connecting the
associated gas from a well site to a nearby gathering system/sales line
for the representative well discussed earlier in this document.
Specifically, costs were estimated for both 4- and 6-inch pipe sizes
and for a variety of distances, in miles, to the gathering system.
Other assumptions in this analysis were that the compressor horsepower
needed was 25 horsepower and the capital recovery was based on 7
percent interest rate and 10 years. Annual operation and maintenance
costs were estimated to be 25 percent of the total capital costs. Table
23 provides the results of this analysis.
Table 23--NSPS Cost Analysis for Routing Associated Gas to Sales Line for Representative New Well \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost effectiveness ($ per ton of emission reduction)
---------------------------------------------------------------------------------------------------------------------
Without considering savings Considering savings
Pipe size Length (miles) ---------------------------------------------------------------------------------------------------------------------
(inches) Single pollutant Multipollutant Single pollutant Multipollutant
---------------------------------------------------------------------------------------------------------------------
Methane VOC Methane VOC Methane VOC Methane VOC
--------------------------------------------------------------------------------------------------------------------------------------------------------
4............... 1............... $158 $569 $79 $285 Net Savings....... Net Savings....... Net Savings....... Net Savings.
4............... 3............... 257 926 129 463 59................ 213............... 38................ 137.
4............... 5............... 357 1,283 178 641 158............... 570............... 88................ 315.
4............... 7............... 456 1,640 228 820 258............... 927............... 137............... 494.
4............... 10.............. 604 2,175 302 1,087 423............... 1,522............. 212............... 761.
4............... 20.............. 1,100 3,958 550 1,979 919............... 3,306............. 459............... 1,653.
4............... 30.............. 1,596 5,742 798 2,871 1,415............. 5,090............. 707............... 2,545.
4............... 40.............. 2,092 7,526 1,046 3,763 1,910............. 6,873............. 955............... 3,437.
4............... 50.............. 2,587 9,310 1,294 4,655 2,406............. 8,657............. 1,203............. 4,329.
6............... 1............... 171 615 85 307 Net Savings....... Net Savings....... Net Savings....... Net Savings.
6............... 3............... 295 1,062 148 531 97................ 349............... 57................ 205.
6............... 5............... 420 1,510 210 755 222............... 797............... 119............... 429.
6............... 7............... 544 1,957 272 979 346............... 1,244............. 181............... 652.
6............... 10.............. 731 2,629 365 1,314 549............... 1,976............. 275............... 988.
6............... 20.............. 1,353 4,867 676 2,433 1,171............. 4,214............. 586............... 2,107.
6............... 30.............. 1,975 7,104 987 3,552 1,793............. 6,452............. 897............... 3,226.
6............... 40.............. 2,597 9,342 1,298 4,671 2,415............. 8,690............. 1,208............. 4,345.
6............... 50.............. 3,219 11,580 1,609 5,790 3,037............. 10,927............ 1,519............. 5,464.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ The representative well has associated gas methane emissions of 343.6 tpy and VOC emissions of 95.5 tpy.
As provided in table 23, the single-pollutant cost effectiveness
for methane ranges from $158 to $3,219 per ton of methane emissions
eliminated. If the value of the gas that will be sold (i.e., the
savings) is considered, the range is from a net savings to $3,037 per
ton. The per-ton VOC cost effectiveness ranges from $569 to $11,580
without savings and ranges from a net savings to $10,927 considering
the savings. The multipollutant cost effectiveness values range from
$79 per ton of methane and $286 per ton of VOC to $1,609 per ton of
methane and $5,790 per ton of VOC. If savings are considered, these
multipollutant cost effectiveness values range from a net savings to
$1,519 per ton of methane and $5,464 per ton of VOC. More details on
this analysis are provided in the 2023 NSPS OOOOb and EG OOOOc Final
Rule TSD.
The EPA determines that the estimated costs, for both pipe sizes
for distances out to 50 miles are reasonable, when considering
multipollutant reductions of methane and VOC. The EPA factors in that
owners and operators of newly drilled wells have the flexibility to
plan and coordinate the construction of gas gathering systems even over
extended distances. Our analysis shows that constructing up to 50 miles
of pipeline is a cost-effective means of managing associated gas at
representative volumes of gas. In cases where the cost of construction
of gathering line or gas volume differs significantly from these
representative parameters, the other options for managing associated
gas are available under the standards. The information presented in
table 23 supports the assumption that the EPA made in the November 2021
Proposal and the December 2022 Supplemental Proposal that routing to a
sales line is cost-effective.
c. BSER Conclusion for New Sources
In the December 2022 Supplemental Proposal, we concluded that BSER
was routing the associated gas to a sales line. In addition, we
recognized that there were other options that achieved the same level
of emissions reduction as routing to a sales line. Therefore, we
proposed four compliance options to reduce emissions of methane and VOC
from associated gas from new oil wells. These options were: (1) recover
the associated gas from the separator and route the recovered gas into
a gas gathering flow line or collection system to a sales line, (2)
recover the associated gas from the separator and use the recovered gas
as an onsite fuel source, (3) recover the associated gas from the
separator and use the recovered gas for another useful purpose that a
purchased fuel or raw material would serve, or (4) recover the
associated gas from the separator and reinject the recovered gas into
the well or inject the recovered gas into another well for enhanced oil
recovery.
Routing associated gas to a sales line is an adequately
demonstrated method of emissions reduction. This is supported by the
statements of one industry commenter,\396\ which indicated that
recovering associated gas from the separator and routing the recovered
gas into a gas gathering flow line or collection system to a sales line
``explains standard business operations for thousands of wells
producing a vital energy resource throughout the country.'' They add
that ``[s]elling natural gas is part of our business.'' The
environmental benefit of routing associated gas to a sales line is
significant, as there are no GHG
[[Page 16943]]
(methane) or VOC emissions. As outlined in the TSD for this final rule,
there are also minimal nonair quality health and environmental impacts
related to routing gas into a sales line. Further, as discussed in
section XI.F.2.b of this document, in response to comments, the EPA
obtained information related to the costs of connecting to a sales line
and performed an analysis, the results of which showed that the cost of
routing to sales is reasonable given the emissions reductions. Given
these considerations, the EPA again concludes that BSER is routing
associated gas from oil wells to a sales line. In addition, the EPA
continues to accept that the other three options proposed achieve
equivalent emissions reductions to routing to a sales line and that
they should be allowed as regulatory alternatives to the BSER.
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\396\ EPA-HQ-OAR-2021-0317-2428.
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The December 2022 Supplemental Proposal for new sources allowed the
associated gas to be routed to a flare or control device that reduces
methane and VOC emissions by at least 95.0 percent if a determination
was made that it was not technically feasible to route the associated
gas to a sales line, use it as onsite fuel or for another beneficial
purpose, or inject/reinject it due to technical or safety reasons, and
the determination was certified by a professional engineer or another
qualified individual with expertise in the uses of associated gas.
Ongoing, continuous flaring in the absence of a method for capturing
and selling, putting to beneficial use, or storing associated gas is
referred to as ``routine'' flaring. As described previously in this
preamble and in response to comments described below, the EPA has
changed these provisions for the final NSPS OOOOb rule to specify that
routine flaring is disallowed at new wells that commence construction
24 months after the effective date of this final rule. As discussed in
detail below, new sources can take this requirement into account when
planning. Moreover, the final rule provides for an orderly ``phase in''
of this requirement through compliance deadlines that vary based on the
date of construction, and it also recognizes reasonable exemptions for
temporary or emergency uses of flaring. These requirements for new
wells reflect comments and information the EPA received in response to
the December 2022 Supplemental Proposal.
Comment: Numerous commenters supported the EPA's proposal to allow
for multiple compliance options as alternatives to routing gas to a
sales line, and several pointed out that the proposed list was
consistent with the options allowed in New Mexico and Colorado. For
instance, one commenter \397\ stated, ``As in the EPA's supplemental
proposal, Colorado and New Mexico require operators to capture
associated gas from oil wells and either route the gas to a sales line
or put it to an alternative use. The alternative uses allowed in New
Mexico largely overlap with those included in the EPA's supplemental
proposal and include, among other things, power generation on lease,
liquids removal on lease, reinjection for underground storage, and
other alternative uses approved by the division. For wells that are not
connected to a pipeline, Colorado similarly allows operators
flexibility to use other options to capture gas including to generate
electricity or to process the gas to recover natural gas liquids,
without venting or flaring.''
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\397\ EPA-HQ-OAR-2021-0317-2433.
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The commenter \398\ also recommended that the EPA remove any
specific reference to ``enhanced oil recovery.'' The commenter
explained that other preferable options exist for injected or
reinjected gas, such as permanent storage in porous geological
formations, and there is no reason to disallow or subordinate these
alternatives.
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\398\ EPA-HQ-OAR-2021-0317-2433.
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Response: The EPA agrees with this comment and therefore has
eliminated specific reference to enhanced oil recovery in the final
rule for both NSPS OOOOb and EG OOOOc. Specifically, the fourth
compliance option (alternative standard) under the final rule allows
the recovery of associated gas from the separator and reinjection into
the well or injection into another well. Removal of reference to
enhanced oil recovery means that sources can choose to reinject
regardless of whether doing so results in additional oil being produced
or recovered from the well. This compliance option still results in
equivalent emissions reductions to the BSER.
Comment: Many commenters objected to the allowance of routine
flaring for new sources. One commenter \399\ urged the EPA to eliminate
pollution from routine flaring except in emergency situations and to
define the term ``emergency'' clearly and narrowly. The commenter
recommended that exemptions only be applicable to short-term and
temporary flaring. Another \400\ suggested that routine flaring from
new wells can never be justified due to the technical infeasibility of
some alternative. The commenter stated that routine flaring is readily
preventable at new wells with proper planning and coordination. Another
commenter \401\ urged the EPA to adopt NSPS and EG that effectively
prohibit routine flaring of associated gas from new and existing oil
wells, with the only exceptions related to safety and emergencies, by
requiring owners or operators to capture all or most of the gas.
Another commenter \402\ strongly supported the EPA's proposed
requirement that owners and operators of oil wells with associated gas
must capture that gas and route it to a sales line. However, they
stated the belief that the EPA can and should take further steps to
eliminate routine flaring. They asserted that the EPA should replace
the broad technical infeasibility exception that would allow operators
to continue routinely flaring with narrowly defined exemptions
applicable only to short-term and temporary flaring. Another commenter
\403\ called for a nationwide ban on routine flaring, characterizing
the practice as wasteful and unnecessary. The commenter points out that
leading state examples and the commitments made by multiple operators
demonstrate that eliminating routine flaring is feasible and cost-
effective.
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\399\ EPA-HQ-OAR-2021-0317-2394.
\400\ EPA-HQ-OAR-2021-0317-2433.
\401\ EPA-HQ-OAR-2021-0317-2410.
\402\ EPA-HQ-OAR-2021-0317-2392.
\403\ EPA-HQ-OAR-2021-0317-2408.
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The commenter noted that numerous operators have committed to
eliminate routine flaring as part of the World Bank's ``Zero Routine
Flaring by 2030'' initiative. To date, 54 oil companies and 34
governments have endorsed the ``Zero Routine Flaring by 2030''
initiative. Based on satellite estimates and publicly reported flaring
data, together the endorsers represent approximately 60 percent of
global flaring. The commenter added that ExxonMobil ``recently
announced a commitment to end routine flaring while also expressing
support for regulations banning this wasteful practice.'' They urged
the EPA to revise its proposal to prohibit routine flaring by requiring
that operators use one of the four gas recovery abatement methods
included in the EPA's proposal. They suggested that the EPA allow for
flaring only during explicit, narrowly tailored, and time-limited
exemptions. They believed that doing so would more clearly and
unequivocally prohibit pollution stemming from routine flaring, as well
as enhance the enforceability of the rule.
[[Page 16944]]
One industry commenter \404\ reported that it is actively working
to reduce flaring of associated gas across each of its operating areas
and has committed to eliminate routine flaring by 2030. Since the
commenter's standard practice is to only bring wells online where
adequate sales line capacity exists, the commenter supports the
restriction of the routine flaring of associated gas from oil wells
that are considered ``new'' sources.
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\404\ EPA-HQ-OAR-2021-0317-2360.
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Commenters also pointed out that Colorado and New Mexico do not
allow the long-term routine flaring of associated gas. One \405\
recommended that the EPA should follow the lead of these states and
prohibit routine flaring of associated gas from new and existing oil
wells except in very limited cases such as emergencies and for safety
reasons.
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\405\ EPA-HQ-OAR-2021-0317-2410.
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One commenter \406\ stated that a standard based on approaches like
those adopted in Colorado and New Mexico, which clearly limit and
delineate circumstances where temporary flaring would be permitted,
represents the ``best system'' for several reasons. For one, it would
require gas recovery but contain reasonable exemptions for temporary
flaring during certain activities that may require flexibility to vent
or flare. Thus, this system would ``reduc[e] emissions as much as
practicable'' and reflect the ``maximum practicable degree of
control.'' The standard would permit technological flexibility by
allowing the use of a multitude of abatement methods, including routing
to a sales line, injection, or reinjection, use as onsite fuel, or use
for another alternative purpose. The commenter pointed out that the
costs of a capture standard are reasonable, cost-effective, and in some
instances even profitable for operators.
---------------------------------------------------------------------------
\406\ EPA-HQ-OAR-2021-0317-2433.
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Response: The EPA finds these arguments for not allowing routine
flaring under any circumstance for new sources to be compelling. The
EPA reviewed the comments from across the industry on our proposal to
direct the gas to a sales line or adopt another gas management
technique that did not require flaring. The conclusion that the EPA
reached for new sources was that operators did not demonstrate or even
explain that routing to a sales line or the alternatives were
infeasible, only that specific circumstances could make certain
alternatives more attractive than others. The most cited factors for
deciding between the proposed alternatives were the logistics of each
option and the costs of adopting any method as a function of the amount
of available gas and whether the well was new, existing, or a marginal
well nearing the end of production. Since the objective of our proposal
was to cost-effectively minimize the emissions that result from
associated gas, and flaring emits more than the zero-emissions options,
we looked at the group of wells where the factors allowing a non-
flaring option were most in favor of operators. New wells fit the
criteria where factors worked most in favor of not flaring. New wells
benefit from new investment and the benefit of planning to accommodate
each option best suited to the site. Production is highest at startup,
meaning that from the start of production a new well would have
anywhere from 10 to 30 years of production to draw upon to manage and
amortize the investment required to manage associated gas. Our analysis
of the costs of connecting to a sales line indicated that for
representative amounts of gas at reasonable distances, the outlook for
amortization of the capital investment was reasonable. See table 22
above. Where distances or logistics might make connection to sales
lines less attractive, commenters provided cost and qualitative support
that the other alternatives would likely be used rather than connecting
to sales, provided they had the benefit of space and time to plan for
managing the associated gas when construction was beginning. As
mentioned above, companies themselves have made voluntary commitments
to eliminate flaring in the near future, by 2030.\407\ While those
commitments are on a longer time horizon than this final rule, our
decision to limit the prohibition on routine flaring to only new wells
means the timelines between implementation of the NSPS and the
voluntary commitments are in the range of about 4 years apart
(considering the phase-in period for the final associated gas standards
in the NSPS). We heeded industry comments that a significant time
horizon would be required to make such a transition, and we chose 24
months from the effective date of the final rule as the most flexible
option that would provide meaningful and timely reductions without
disrupting the near-term investments taking place now. We concluded
that, for new sources, opportunities exist for advance planning to
route the associated gas to a sales line, use it as onsite fuel or for
another beneficial purpose, or inject/reinject it. Therefore, in the
final rule, the EPA has eliminated the allowance for new sources that
associated gas can be routinely routed to a flare or other control
device. As explained further below, the EPA is finalizing a phase-in
approach for this standard for the NSPS OOOOb.
---------------------------------------------------------------------------
\407\ To date, 54 oil companies and 34 governments have endorsed
the ``Zero Routine Flaring by 2030'' initiative. See ``Global
Initiative to Reduce Gas Flaring: ``Zero Routine Flaring by 2030,''
EPA Docket ID EPA-HQ-OAR-2021-0317.
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As discussed in section XI.F.2.f of this document, the EPA
recognizes that a source routing the associated gas to a sales line,
using it as onsite fuel or for another beneficial purpose, or
injecting/reinjecting it will likely encounter temporary situations
where it is infeasible or unsafe to route the associated gas to a sales
line, use it as onsite fuel or for another beneficial purpose, or
inject/reinject it. Therefore, the final rule allows temporarily
routing to a flare or other control device in specified situations.
In addition, the EPA acknowledges that owners or operators may have
already planned and initiated efforts to drill new wells based on the
allowance of routing to a flare or control device with an infeasibility
determination that was included in the December 2022 Supplemental
Proposal. The EPA also accepts that existing wells that are modified or
reconstructed may be limited in the options to route to a sales line or
comply with one of the other options. Therefore, the final rule
includes special allowances for these situations. This is discussed in
section XI.F.2.d of this document.
d. Considerations for New Sources for Which Construction Commenced
Prior to the Final Rule and for Reconstructed and Modified Sources
In the December 2022 Supplemental Proposal, the EPA proposed to
allow new sources to routinely route associated gas to a flare or
control device with a demonstration and certification that routing the
associated gas to a sales line, using it as onsite fuel or for another
beneficial purpose, or injecting/reinjecting it was infeasible for
technical or safety reasons. A new source is defined as a well that
commenced construction, reconstruction, or modification after December
22, 2022. Further, the definition of ``commenced'' found within 40 CFR
60.2 applies for purposes of NSPS OOOOb. That definition states that
``commenced means . . . that an owner or operator has undertaken a
continuous program of construction or modification or that an owner or
operator has entered into a contractual obligation to undertake and
complete, within a reasonable time, a continuous
[[Page 16945]]
program of construction or modification.''
As discussed in section XI.F.2.c of this document, the EPA believes
that, with the full knowledge and understanding of the final rule,
owners planning on drilling new wells in the future have the ability to
plan ahead to ensure that the associated gas is routed to a sales line,
used as onsite fuel or for another beneficial purpose, or injected/
reinjected. However, the EPA acknowledges that new wells have commenced
construction in the period between December 22, 2022, and the date of
publication of this final rule, and that it is reasonable for owners
and operators of such wells to have assumed that the final rule could
have continued to allow the proposed allowance to routinely flare the
associated gas or route it to a control with an infeasibility
determination and certification. The EPA concludes that for wells in
this situation, it is appropriate to allow the associated gas to be
routinely routed to a flare or control device with a determination and
certification that it is technically infeasible \408\ to route the
associated gas to a sales line, use it as onsite fuel or for another
beneficial purpose, or inject/reinject it. The EPA encourages owners
and operators of these sources to continue to seek opportunities to
route the associated gas to a sales line, use it as onsite fuel or for
another beneficial purpose, or inject/reinject it. These methods will
not only eliminate the environmental impacts of routine flaring but
will also significantly reduce the compliance burden on the owners and
operators. Therefore, the final rule allows sources that have made the
requisite determination and certification to route the associated gas
to a flare or control device that achieves a 95.0 percent reduction in
VOC and methane emissions for those wells for which construction was
commenced between December 22, 2022, and the effective date of the
final rule, which is May 7, 2024. This is only allowed with a
demonstration and certification that it is technically infeasible to
route the associated gas to a sales line, use it as onsite fuel or for
another beneficial purpose, or inject/reinject it. This demonstration
and certification must then be renewed annually. See section XI.F.2.g
of this document for a discussion of comments received on the
infeasibility determination and certification process and the
requirements contained in the final rule.
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\408\ As discussed in section XI.F.2.g of this document, based
on comments, the EPA determined that the need to flare associated
gas due to safety reasons is a temporary circumstance and would not
result in the need to routinely flare in place of routing the
associated gas to a sales line, using it as onsite fuel or for
another beneficial purpose, or injecting/reinjecting it. Therefore,
temporary flaring due to safety reasons is allowed without any type
of infeasibility determination or certification.
---------------------------------------------------------------------------
The EPA recognizes that existing sources that undergo
reconstruction or modification and thus become new sources also face
different circumstances than new wells for which construction commences
with full knowledge of the ``no routine flaring'' requirement in the
final rule. These wells were likely originally drilled without the
expectation that the EPA would be proposing and promulgating
requirements that would require the routing of associated gas to a
sales line, using it as onsite fuel or for another beneficial purpose,
or injecting/reinjecting it as required by the final rule. The location
of these existing wells that are undergoing reconstruction or
modification is established and the owner or operator does not have the
ability to move the well to allow connection more easily to a sales
line, to inject into another well, or perhaps to utilize any other
option. Therefore, the EPA concluded that it is appropriate to allow
wells reconstructed or modified after December 22, 2022, to routinely
flare associated gas or route it to control with a technical
infeasibility determination and certification. This demonstration and
certification must then be renewed annually.
Finally, the EPA acknowledges that owners and operators could have
initiated the planning stages of a new well based on the December 2022
Supplemental Proposal even though they may not have specifically
undertaken the activities that meet the definition of ``commenced
construction.'' Therefore, owners and operators may have made
preliminary plans assuming that flaring or routing to control would be
allowed with a determination that it is technically infeasible to route
the associated gas to a sales line, use it as onsite fuel or for
another beneficial purpose, or inject/reinject it. The final rule
allows sources that commence construction within a certain period after
the effective date of the rule to routinely route the associated gas to
a flare or to a control device for a short period, after which they are
required to route the associated gas to a sales line, use it as onsite
fuel or for another beneficial purpose, or inject/reinject it. This
will allow owners and operators to proceed with plans, but also not
allow routine flaring or routing to control for an extended period.
Specifically, the final rule allows wells for which construction
commences between May 7, 2024 and May 7, 2026 to route the associated
gas to a flare or to a control device that achieves a 95.0 percent
reduction in VOC and methane emissions, with the proper demonstration
of technical infeasibility, until May 7, 2026. Routine flaring for
these sources is only allowed with a demonstration and certification
that it is technically infeasible to route the associated gas to a
sales line, use it as onsite fuel or for another beneficial purpose, or
inject/reinject it. This demonstration and certification must then be
renewed annually. After May 7, 2026, these sources will no longer be
able to routinely flare associated gas, and must route the associated
gas to a sales line, use it as onsite fuel or for another beneficial
purpose, or inject/reinject it. For information regarding technical
infeasibility demonstrations, including examples, see section
X.F.2.a.i. of this document.
e. BSER for Existing Sources
In the December 2022 Supplemental Proposal, the EPA proposed
presumptive standards for associated gas from existing oil wells for
the EG OOOOc that mirrored those for new sources under NSPS OOOOb. That
is, EG OOOOc included four compliance options to eliminate emissions of
methane from associated gas from existing oil wells. These options
were: (1) recover the associated gas from the separator and route the
recovered gas into a gas gathering flow line or collection system to a
sales line, (2) recover the associated gas from the separator and use
the recovered gas as an onsite fuel source, (3) recover the associated
gas from the separator and use the recovered gas for another useful
purpose that a purchased fuel or raw material would serve, or (4)
recover the associated gas from the separator and reinject the
recovered gas into the well or inject the recovered gas into another
well for enhanced oil recovery. Associated gas was allowed to be routed
to a flare or other control device if the owner or operator
demonstrated that all four options were infeasible due to technical or
safety reasons and if that demonstration is approved by a certified
professional engineer or other qualified individual.
Comment: One commenter \409\ suggested that there was a fundamental
flaw in the EPA's process that has resulted in a misguided BSER
determination for existing sources that effectively regulates existing
sources the same as new and modified sources. Another commenter claimed
that the EPA's recurring conclusion that
[[Page 16946]]
designated facilities under the EG should be the same as affected
facilities under the NSPS did not recognize the differences between new
and existing sources.\410\
---------------------------------------------------------------------------
\409\ EPA-HQ-OAR-2021-0317-2294.
\410\ EPA-HQ-OAR-2021-0317-2446.
---------------------------------------------------------------------------
Response: The EPA generally agrees with the commenters that
consideration must be given to any meaningful differences between new
and existing sources in determining the respective BSER. The EPA
proposed that routing the associated gas from existing wells to a sales
line was an adequately demonstrated method of emissions reduction and
the costs were reasonable. We also determined that the other equivalent
compliance options also were appropriate for existing sources (we did
not identify any limitations that would universally inhibit use of the
alternatives for existing sources). We recognized that there could be
situations where it was infeasible to comply with one of these options,
so the proposed presumptive standards in EG OOOOc included the
allowance to routinely flare the associated gas or route it to control
if it was demonstrated and certified that the earlier listed four
alternatives were infeasible due to technical or safety reasons.
As discussed in section XI.F.2.c of this document, the final rule
will phase out the option for new sources to routinely route the
associated gas to a flare or control device. In addition, numerous
comments were submitted regarding considerations related to wells that
produce low levels of associated gas. In light of the changes to the
NSPS and comments received specific to existing sources of associated
gas, the EPA reevaluated the BSER for existing sources. This revised
BSER analysis for existing sources recognizes that, unlike new sources,
existing sources may not have taken into account distance to a gas line
when choosing their location and cannot readily do so now.\411\
---------------------------------------------------------------------------
\411\ See full BSER analysis in chapter 4 of the final TSD for
this rulemaking.
---------------------------------------------------------------------------
Comment: Commenters \412\ believed that the EPA needs to maintain
flaring as an option for wells with little associated gas. They
maintained that the gas production rate is too low to be able to
justify the expense of routing to a sales line or even investing in the
equipment to inject the gas back into the reservoir. Many times, the
gas production rate is too low to be able to reliably operate an engine
to produce power to operate surface equipment. They added that low
production wells need to have the option to flare the gas as an
environmentally acceptable option. The commenters believed that
eliminating this option would be an unnecessary burden on small
businesses.
---------------------------------------------------------------------------
\412\ EPA-HQ-OAR-2021-0317-2168 and -2172.
---------------------------------------------------------------------------
The commenters pointed out that much of the associated gas from low
production wells does not meet the requirements to be sold on an
interstate pipeline system. The gas may require water, nitrogen,
CO2, and heavier hydrocarbons (ethane, propane, butane,
pentane, and hexane) to be removed prior to its being sold into the gas
market. The cost to make the gas ``pipeline spec'' usually exceeds the
benefit of selling the gas on the pipeline. The commenters provided
that this is another example where low production wells should be
exempt from the proposed regulation.
Another commenter \413\ explained that, for many of their existing
wells, no sales line is readily available, and even if one was
available, the volume of associated gas may be too low to reach a sales
line. The commenter recommended that the EPA reconsider this
requirement for existing well sites, in recognition that the
infrastructure is unlikely to be present to make such a requirement
feasible.
---------------------------------------------------------------------------
\413\ EPA-HQ-OAR-2021-0317-2283.
---------------------------------------------------------------------------
Yet another commenter \414\ recommended that the EPA maintain an
exemption for low production wells. The commenter explained that many
of the low production wells operate with low pressure and low gas-to-
oil ratios, so the PTE is significantly less than the PTE for higher-
production wells that were recently drilled.
---------------------------------------------------------------------------
\414\ EPA-HQ-OAR-2021-0317-2172.
---------------------------------------------------------------------------
Response: As discussed in section XI.F.2.b of this document, the
EPA obtained data and performed a cost analysis of collecting the
associated gas and routing it to a sales line for a representative new
well. As discussed, this representative new well had methane emissions
of 343.6 tpy. In response to the comments regarding low associated gas
production wells, the EPA performed an analysis for varying baseline
emissions levels and distances to the gathering system. Specifically,
the EPA evaluated the costs of routing associated gas to a sales line
for distances up to 5 miles using a 4-inch pipe. The results of this
analysis are provided in table 24.
Table 24--Methane Cost Analysis of Routing to Sales Line for Low Associated Gas Production Wells
----------------------------------------------------------------------------------------------------------------
Miles from gathering system cost effectiveness ($/ton methane reduced)
Associated gas methane emissions -------------------------------------------------------------------------------
(tpy) 0.25 0.50 1 3 5
----------------------------------------------------------------------------------------------------------------
10.............................. $3,961 $4,387 $5,239 $8,646 $12,053
20.............................. 1,882 2,095 2,520 4,224 5,927
30.............................. 1,188 1,330 1,614 2,750 3,886
40.............................. 842 948 1,161 2,013 2,865
50.............................. 634 719 889 1,571 2,252
60.............................. 495 566 708 1,276 1,844
70.............................. 396 457 579 1,065 1,552
80.............................. 322 375 481 907 1,333
90.............................. 264 311 406 785 1,163
100............................. 218 260 346 686 1,027
----------------------------------------------------------------------------------------------------------------
Based on the results of this analysis, the EPA decided it was
appropriate to separate existing oil wells with associated gas into two
subcategories. For wells with 40 tpy of methane emissions, the cost
effectiveness of routing to sales was considered reasonable at
distances in a range of about 3 miles. We assume that the methane
emissions are equivalent to the amount of methane contained in the
associated gas. Therefore, the two subcategories are those with
associated gas that contains 40 tpy or less methane and those that
contain greater than 40
[[Page 16947]]
tpy methane. The EPA then developed BSER separately for these two
subcategories.
i. BSER for the Subcategory of Wells With Associated Gas Containing 40
tpy or Less Methane
For wells that produce 40 tpy or less of associated methane gas,
the analysis shows that, depending on the distance from the well to the
gathering system, it could sometimes be cost-effective to route the
associated gas to a sales line, and sometimes not. Assuming that there
is an existing flare or control device onsite that could accept the
associated gas, the cost to direct the associated gas into the flare
would be minimal (approximately $6,100 capital cost, with an annual
cost of $670). The cost effectiveness of routing to an existing flare
for an associated gas well where the associated gas contains 40 tpy of
methane is $18 per ton of methane, which is well within the range that
the EPA has considered reasonable. In fact, the cost effectiveness for
wells with 1 tpy of methane ($915/ton) is still reasonable. For the
installation of a new flare, the cost effectiveness for a well where
the associated gas contains 40 tpy methane is $1,758 per ton of
methane, which is also considered reasonable. Considering that routing
associated gas to a flare or control device is an adequately
demonstrated method and considering this cost effectiveness leads the
EPA to conclude that BSER to reduce the methane emissions from
associated gas from existing oil wells where the associated gas
contains 40 tpy or less of methane is routing to a flare. This outcome
is consistent with the recommendations made by the commenters.
Comment: One commenter \415\ stated that repeated, onerous
technical infeasibility analyses and detailed recordkeeping should be
eliminated in the final rule for wells with low associated gas
production.
---------------------------------------------------------------------------
\415\ EPA-HQ-OAR-2021-0317-2403.
---------------------------------------------------------------------------
Response: Because the EPA has determined that BSER for this
subcategory of existing sources is routing to a flare or control
device, the final model rule does not include a requirement to
demonstrate technical infeasibility for wells with associated gas
containing 40 tpy or less of methane. The presumptive standard allows
sources in this subcategory to routinely flare without needing to make
a demonstration of technical infeasibility. However, the final
presumptive standard does include the requirement to calculate and
document the methane content of associated gas using the GOR. The
calculation is based on a simplified version of the methodology in
subpart W of the GHGRP.
Note that under the presumptive standard in the final EG, owners
and operators of these low associated gas production wells are allowed
to route the associated gas to a sales line, use it as onsite fuel or
for another beneficial purpose, or inject/reinject it. In fact, the EPA
encourages this option where possible. If a source elects to comply
with one of these options, the presumptive standard would not require
that source to comply with the requirement to calculate the annual
methane content of the associated gas.
Comment: One commenter \416\ stated that many older, existing well
sites in the Midland Basin do not have flares onsite, and it would
present a significant capital expense to add a flare or similar control
device at each existing well site. Another commenter \417\ stated that
``for many conventional oil wells in Pennsylvania and New York, a gas
sales line is not reasonably available. The ``associated gas'' produced
at these conventional oil and gas well sites would not be sufficient to
sustain a flare, much less justify the changes and capital expenditures
needed to attempt to use the gas onsite. The commenter indicated that
the EPA must expressly allow Pennsylvania and New York conventional oil
producers to vent the small volumes of ``associated gas,'' which the
commenters contend is the only safe and environmentally sound method of
dealing with associated gas at some Pennsylvania conventional oil
wells. The first commenter stated that the EPA should consider the
remaining useful life of these existing sources, as required by the
CAA.
---------------------------------------------------------------------------
\416\ EPA-HQ-OAR-2021-0317-2283.
\417\ EPA-HQ-OAR-2021-0317-1341.
---------------------------------------------------------------------------
Response: The EPA acknowledges these comments and understands that
certain situations exist where the methane content in the associated
gas is low and there is not a flare or control device onsite. The EPA
also recognizes that the cost of installing a new flare or control
device solely to reduce the methane emissions from the associated gas
could be above what is typically considered reasonable by the EPA for
wells with very low levels of methane. Both commenters cite instances
where the wells are older and located in specific geographic locations.
We conclude that these situations are most likely to occur for older
wells where the wells are approaching the end of their useful lives.
The EPA also believes that the wells discussed by comments do not
represent the majority of designated facilities across the country.
Therefore, the EPA did not elect to further subcategorize wells with 40
tpy or less associated gas methane into those sites with and without
existing control devices. First, the EPA believes that many of these
sites likely have existing control devices already onsite that could
accommodate the associated gas. The EPA is aware that several states,
including New Mexico, North Dakota, and Texas, have regulations that
require control devices in certain situations that are relevant here.
Second, we believe that the particular sites discussed by commenters
could be candidates for states to examine under the RULOF framework of
40 CFR part 60, subpart Ba, when states are developing their state
plans in accordance with these final EG in 40 CFR part 60, subpart
OOOOc. States can consider the RULOF-specific situations at the low
associated gas production wells that do not have flares or other
control devices onsite to possibly apply a standard of performance less
stringent than the presumptive standard in this EG consistent with the
EPA's implementing regulations. Further, the EPA acknowledges that the
Agency did not assess costs for existing wells that are located more
than 5 miles away from a gathering system, and states may wish to
examine the possibility of invoking RULOF for situations where a well
with low levels of associated gas is located a far distance away from a
gathering system and cannot otherwise comply with the alternatives
included in the presumptive standard.
ii. BSER for the Subcategory of Wells With Associated Gas Containing
Greater Than 40 tpy Methane
As discussed for new sources, routing associated gas to a sales
line is an adequately demonstrated method for reducing methane
emissions. As shown in table 23, the cost effectiveness of routing the
gas to a sales line for wells with associated gas containing greater
than 40 tpy methane is at levels considered reasonable by the EPA,
especially in situations where the well is relatively near the
gathering system. Therefore, the EPA determined that BSER for this
subcategory is routing the associated gas to a sales line. As with new
sources, the EPA believes that the other options that achieve the same
level of emissions reduction should be allowed.
As discussed for modified and reconstructed sources, the EPA
recognizes that existing sources were likely originally drilled without
the expectation that the EPA would issue these EG which include a
presumptive
[[Page 16948]]
standard of routing the associated gas to a sales line, using it as
onsite fuel or for another beneficial purpose, or injecting/reinjecting
it. The location of these existing wells is established, and the owner
or operator may not have the ability to move the well to allow a closer
connection to a sales line, to inject into another well, or perhaps to
utilize any other option. Therefore, the EPA concluded that it is
appropriate to allow existing wells with greater than 40 tpy methane to
routinely flare associated gas or route it to control with a technical
infeasibility determination and certification which is renewed
annually.
The final presumptive standards for existing wells with associated
gas containing greater than 40 tpy methane are to reduce or eliminate
emissions of methane by: (1) Recovering the associated gas from the
separator and routing the recovered gas into a gas gathering flow line
or collection system to a sales line, (2) recovering the associated gas
from the separator and using the recovered gas as an onsite fuel
source, (3) recovering the associated gas from the separator and using
the recovered gas for another useful purpose that a purchased fuel or
raw material would serve, or (4) recovering the associated gas from the
separator and reinjecting the recovered gas into the well or injecting
the recovered gas into another well. In addition, the final presumptive
standards for this subcategory allow the associated gas to routinely be
routed to a flare or control device that reduces methane and VOC
emissions by at least 95.0 percent if annual demonstrations are made
that it is technically infeasible to route the associated gas to a
sales line, use it as onsite fuel or for another beneficial purpose, or
inject/reinject it and the determination is certified by a professional
engineer or another qualified individual with expertise in the uses of
associated gas. See section XI.F.2.g of this document related to the
infeasibility determination and certification.
Comment: One commenter \418\ stated that the EPA failed to
understand the implications of inherent production depletion on the
economics and emissions from smaller wells. The commenter asserted that
there are fundamental factors that are not adequately considered in the
EPA assessments, and that, as oil and natural gas wells undergo their
inherent depletion, the reduced volumes of production limit the amount
of emissions that can be generated.
---------------------------------------------------------------------------
\418\ EPA-HQ-OAR-2021-0317-2446.
---------------------------------------------------------------------------
Response: The EPA understands the depletion of production over time
and understands that it impacts the associated gas volume, and thus the
methane contained in the associated gas. Therefore, the presumptive
standard included in the final EG includes the provision that existing
wells whose production is less than 40 tpy of methane upon becoming a
designated facility can flare routinely without a demonstration of
technical infeasibility. The EPA determined that for wells with above
40 tpy of methane it is reasonable to route the gas to a sales line or
choose an equivalent alternative, or in the absence of a feasible
alternative, to flare the gas. While the level of gas production may
decline over time from above 40 tpy to below, the EPA considers the
cost of control of the gas from designation as a designated facility
producing over 40 tpy to the time of well closure to be reasonable, and
considers that the cost may be mitigated by any recovery from an
associated gas management technique that allows some cost savings.
Further, if an owner/operator is already complying with a zero-
emissions option, then they should be able to continue to comply with
that option cost-effectively, even if their production declines, as
they have already made the investment.
f. Temporary Flaring/Venting
Comment: A number of comments were received on the topic of
temporary flaring and venting. Commenters from across the spectrum
(industry, state agencies, environmental organizations) agree that
there are extenuating circumstances beyond the reasonable control of
the operator that can result in the inability to exercise the primary
use option. Further, there is agreement that flaring should be allowed
in these circumstances. Commenters encouraged the EPA to distinguish
between ``routine'' and ``non-routine'' flaring events.
In the December 2022 Supplemental Proposal, we proposed ``to
require that if owners and operators anticipate that there may be
interruptions in the ability to route the associated gas to a sales
line or to use it for another beneficial purpose, they must provide a
technical or safety demonstration in their annual report and install
and operate a control device that achieves the required reduction
during these temporary periods'' (p. 74780).
While there was agreement among the commenters on the need to allow
temporary flaring, there was also universal objection to this proposed
requirement for technical or safety demonstrations to justify flaring.
One commenter \419\ urged the EPA to abandon the broad, unclear
technical infeasibility exemption. Another \420\ recommended the
replacement of the ``technical infeasibility'' exemption with clearly
delineated circumstances for temporary flaring. Another \421\ contended
that, for those situations where the gas from the well is connected to
a sales line and there are instances where the gas needs to be routed
intermittently to a control device for equipment maintenance, repairs,
emergencies, or other similar situations, this type of flaring should
not have to undergo repeated, onerous infeasibility determinations and
detailed recordkeeping requirements. Another commenter \422\ requested
that for wells where the operator has designed and configured the
separator to recover and sell or beneficially use associated gas, the
EPA remove the requirement to provide an infeasibility or safety
justification for controlling associated gas when the primary means of
disposition is temporarily unavailable. Another commenter \423\
explained that when a facility is designed with a certain configuration
for handling the disposition of associated gas, it is unreasonable to
expect facilities to design for multiple uses based on emerging
technologies before they can resort to flaring, especially during these
short, intermittent periods. They did not support making technical or
safety demonstrations where disruptions or interruptions in the gas
gathering infrastructure result in the need to route the associated gas
to a control device for temporary periods. One commenter \424\
suggested that, rather than an infeasibility determination being
required for every instance, a one-time infeasibility determination
should suffice.
---------------------------------------------------------------------------
\419\ EPA-HQ-OAR-2021-0317-2408.
\420\ EPA-HQ-OAR-2021-0317-2433.
\421\ EPA-HQ-OAR-2021-0317-2403.
\422\ EPA-HQ-OAR-2021-0317-2326.
\423\ EPA-HQ-OAR-2021-0317-2428.
\424\ EPA-HQ-OAR-2021-0317-2403.
---------------------------------------------------------------------------
Commenters \425\ recommended that, rather than requiring an
infeasibility demonstration for specific instances, the EPA delineate
instances in the rule where temporary flaring is allowed. Commenters
generally indicated that flaring should be allowed during upset
conditions, which one commenter \426\ defined as emergency
circumstances outside of the control of an operator that can interrupt
its ability to comply with the standard. Commenters also provided
[[Page 16949]]
specific situations, including the following:
---------------------------------------------------------------------------
\425\ EPA-HQ-OAR-2021-0317-2408 and -2433.
\426\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------
Due to a temporary, unplanned loss of connection to, or
ability to route gas to, a gathering system.
During the commissioning of pipelines, equipment, or
facilities.
When the natural gas does not meet pipeline
specifications.
Temporary failure of equipment.
During startup and shutdown activities.
During maintenance activities.
During construction activities and facility modifications.
During well testing.
In addition to suggesting that the EPA delineate specific instances
when temporary flaring is allowed, commenters recommended that the EPA
establish clear time limitations during which the flaring is permitted.
In addition, one commenter \427\ identified circumstances where
venting may be warranted. The commenter acknowledged that venting may
be necessary for safety. In addition, they added that operators may
need to vent for a very brief period during downhole monitoring
activities, namely when monitoring the downhole pressure during
bradenhead monitoring and packer leakage tests.
---------------------------------------------------------------------------
\427\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------
Commenters stressed that state rules, specifically in Colorado and
New Mexico, allow operators to flare or vent gas for short periods of
time during upset conditions or emergencies, including temporary
unavailability of access to a gathering line. Further, both states list
specific instances and time frames when flaring is allowed. Examples
cited by the commenters include the following.
A commenter \428\ discussed circumstances where the EPA may
consider exemptions from its capture requirements in which flaring is
authorized. One circumstance that may give rise to an operator's need
to flare on a temporary basis is the commissioning of pipelines,
equipment, or facilities. The commenter provides that New Mexico allows
operators to flare temporarily during these circumstances, and even
then ``only for as long as necessary to purge introduced impurities.''
An operator may need to flare temporarily when it is first connecting
to a pipeline that has just been constructed if the pipeline was
cleaned out with substances that the midstream operator does not want
in the gas.
---------------------------------------------------------------------------
\428\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------
The commenters report that both Colorado and New Mexico allow
operators to vent or flare during bradenhead monitoring. Colorado
limits bradenhead monitoring to 30 minutes. New Mexico also allows
operators to flare or vent during packer leakage tests.
Commenters \429\ stated that New Mexico allows for temporary
venting or flaring during an emergency. An emergency means ``a
temporary, infrequent, and unavoidable event in which the loss of
natural gas is uncontrollable or necessary to avoid a risk of an
immediate and substantial adverse impact on safety, public health, or
the environment'' other than in certain exceptions. One such exception
is ``venting or flaring of natural gas for more than 8 hours after
notification that is caused by an emergency, an unscheduled
maintenance, or a malfunction of a natural gas gathering system.'' In
other words, an upstream operator may vent or flare during a temporary,
infrequent, and unavoidable event involving loss of connection to a
sales line provided the midstream operator notifies the producer of the
disruption to the operator of the sales line. However, an upstream
operator cannot vent longer than 8 hours in this circumstance.
---------------------------------------------------------------------------
\429\ EPA-HQ-OAR-2021-0317-2433 and -2408.
---------------------------------------------------------------------------
One commenter \430\ provided that both Colorado and New Mexico
allow operators to flare or vent gas for a short period of time during
upset conditions or emergencies which include temporary unavailability
of access to a gathering line. The commenter explained that the
Colorado rules provide a concise, clear definition of upset condition
combined with a limit on the amount of time an operator may flare or
vent during such circumstances. Colorado allows operators to vent or
flare for up to 24 cumulative hours during an upset condition while New
Mexico allows operators to vent or flare for up to 8 hours during an
emergency. Loss of a connection to a pipeline qualifies as an upset
condition under the Colorado rules and an emergency under the New
Mexico rules.
---------------------------------------------------------------------------
\430\ EPA-HQ-OAR-2021-0317-2408.
---------------------------------------------------------------------------
The commenter added that New Mexico allows for temporary venting or
flaring during an emergency. An emergency means ``a temporary,
infrequent, and unavoidable event in which the loss of natural gas is
uncontrollable or necessary to avoid a risk of an immediate and
substantial adverse impact on safety, public health, or the
environment'' other than in certain exceptions.
Response: As discussed in section XI.F.2.b of this document, the
representative well and the BSER analysis are focused on associated gas
emissions during routine operations. We appreciate the information and
insights provided by the commenters, and overall we agree with the
recommendations.
First, we recognize that there are circumstances that could arise
that are beyond the control of the owner or operator and that could
result in the temporary inability to comply with the standards, and we
do not believe it is appropriate to require the shut-in of the well in
such instances.
We agree with the commenters that the proposed requirement to
demonstrate infeasibility based on technical or safety reasons for each
of these temporary instances is not the most efficient solution.
Rather, in the final rule, we have incorporated an approach similar to
requirements adopted by New Mexico and Colorado. The final rule
identifies specific circumstances in which temporary flaring or venting
are allowed. The final rule also includes maximum timeframes for each
circumstance. Following are the specifics included in the final rule.
Temporary flaring (or routing to a control device to achieve 95 percent
reduction) is allowed:
For up to 24 hours during a deviation caused by a
malfunction.
For up to 72 hours during repair, maintenance including
blowdowns, a packer leakage test, a production test, or commissioning.
For up to 30 days during temporary interruption in service
from the gathering or pipeline system.
For up to 72 hours if associated gas does not meet
pipeline specifications.
While temporary flaring or routing to a control device is allowed
in these situations, it is important to ensure that, with the
additional gas that is being routed to the flare or control device
during this temporary period, the flare or control device continues to
operate properly. Therefore, the final rule includes the requirement
that the owner or operator demonstrate that applicable flare or control
device requirements are being met during the temporary period when the
associated gas is routed to the control.
Comment: One commenter \431\ supported the use of temporary control
devices for situations when the associated gas could not be routed to a
sales line, used as onsite fuel or for another beneficial purpose, or
injected/reinjected. The commenter explains that some sites may have
permanent control devices for these scenarios. However, temporary
controls can be used to
[[Page 16950]]
minimize emissions during planned maintenance, startup, and shutdown
activities. Emissions from these temporary controls are permitted as an
alternate operating scenario, as a part of normal operations. Another
commenter supported flaring the gas by using a permanent or temporary
control device that achieves 95 percent efficiency during periods of
time when the associated gas is routed to the control device.
---------------------------------------------------------------------------
\431\ EPA-HQ-OAR-2021-0317-2218.
---------------------------------------------------------------------------
Response: In the December 2022 Supplemental Proposal, we stated
that we anticipated that a control device used to reduce emissions
during these temporary periods ``would need to be permanently
installed.'' However, we specifically requested comment on whether the
use of temporary controls could also serve this purpose. Commenters
responded that such control devices would likely be permanent controls,
albeit control systems that are present for reasons other than
providing redundant control for associated gas.\432\
---------------------------------------------------------------------------
\432\ EPA-HQ-OAR-2021-0317-2326.
---------------------------------------------------------------------------
The EPA has determined that it is not necessary that a control
device be permanently installed for these situations. However, if a
temporary flare or control device is used, it is required to meet the
same control device requirements as a permanent control device.
In addition to the allowance for temporary flaring or routing to a
control device, the final rule allows venting in the following
circumstances and durations:
For up to 12 hours to protect the safety of personnel.
For up to 30 minutes during bradenhead monitoring.
For up to 30 minutes during a packer leakage test.
The final rule requires that detailed records be kept of each of
these venting situations.
g. Infeasibility Demonstration and Certification
The proposed NSPS OOOOb regulation and EG OOOOc presumptive
standards both included the allowance that associated gas could be
routed to a flare or control device after a demonstration and
certification that it is infeasible to route the associated gas to a
sales line or to comply with the other options. The December 2022
Supplemental Proposal required that this demonstration include a
detailed analysis documenting and certifying the technical or safety
infeasibility for all options. It also listed specific types of other
useful purposes that owners and operators were required to address,
specifically methane pyrolysis, compression of gas for transport to
another facility, conversion of gas to liquid, and production of
liquified natural gas. The proposal required that this demonstration be
certified by a professional engineer or another qualified individual
with expertise in the uses of associated gas.
As discussed in section XI.F.2.f of this document, there were many
comments submitted that objected to the proposal to require a
demonstration of infeasibility based on technical or safety reasons for
temporary use of a flare or control device in instances when the
primary option (e.g., routing the associated gas to a sales line, using
it as onsite fuel or for another beneficial purpose, or injecting/
reinjecting it) is unavailable. Rather they suggested that the rule and
presumptive standards include specific instances when such temporary
flaring or routing to control is allowed. As also discussed in section
XI.F.2.f of this document, the final rule includes such a list of
specific circumstances. Therefore, the infeasibility demonstration and
certification provisions in the final rule are applicable to situations
where routing the associated gas to a sales line, using it as onsite
fuel or for another beneficial purpose, or injecting/reinjecting it are
not feasible and routing to a flare or control device is routine.
On a related topic, one commenter \433\ suggested that safety
concerns are by their nature temporary and would never give rise to the
need to flare indefinitely. The commenter suggested that the EPA should
therefore require that any safety-related flaring cease when the safety
concern no longer exists. The EPA agrees that the need to flare or
route to control for safety reasons is a temporary issue, and not a
reason that would warrant long-term routine flaring. Therefore, the
final rule allows routine flaring or routing to control based only on
technical infeasibility, and not safety.
---------------------------------------------------------------------------
\433\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------
Comment: Commenters \434\ suggested that the EPA not require
consideration of predetermined beneficial uses for oil well associated
gas, and, if the EPA retains such a list, any included beneficial use
must be commercially viable. One commenter stated that the EPA proposed
that operators must certify that use of ``recovered gas for another
useful purpose that a purchased fuel or raw material would serve'' is
not feasible ``due to technical or safety reasons'' before the operator
may control associated gas onsite. They added that the EPA proposed
that the feasibility analysis must include consideration of using gas
for ``methane pyrolysis, compressing the gas for transport to another
facility, conversion of gas to liquid, and the production of liquified
natural gas.'' The commenter fully supports the beneficial use of
natural gas where reasonably feasible and cost-effective and further
supports development of additional technologies that would provide a
broader range of potential beneficial uses. The commenter believed that
the EPA's inclusion of a predetermined list of uses suggests that the
EPA has determined each of these beneficial uses to be technically
feasible, commercially available, and appropriately included as part of
the associated gas BSER. The commenter contends that the EPA, however,
has provided no support for this apparent determination. Accordingly,
the commenter requested that the EPA remove this list of beneficial
uses. Further, to the extent the EPA maintains such a list of
beneficial uses, the commenter requested that the EPA remove any
unproven ``emerging technologies.'' The commenter stated that CAA
section 110(j) provides the appropriate pathway for sources to evaluate
emerging technologies to meet NSPS. According to the commenter,
requiring evaluation of unproven emerging technologies sidesteps both
the BSER demonstration and the CAA section 110(j) process in violation
of the CAA. Another commenter, a state agency,\435\ supported emerging
technologies as potential methods for controlling emissions from oil
and gas facilities and recommended that the rules allow the use of
emerging technologies as a recognized method of achieving a beneficial
use for associated gas. The commenter reported that some companies use
the associated gas as fuel for electric generating units or compress
the gas and send it to another site for processing. The commenter
believed that useful purpose should include, but not be limited to,
uses or purposes that a purchased fuel or raw material would serve. The
commenter also believed that useful purpose should not be explicitly
defined in the rule language, and that the owner or operator can
provide a demonstration or certification that they meet this criterion.
Due to the unpredictable nature of technological advancement, the
commenter believed it would be shortsighted for the EPA to limit this
aspect of the rule to only narrowly defined or specified processes or
technologies. Certain technologies for
[[Page 16951]]
reducing methane and other GHG emissions, such as gas compression for
offsite transport, can also result in collateral emissions of other
regulated pollutants which are subject to the national ambient air
quality standards (NAAQS).
---------------------------------------------------------------------------
\434\ EPA-HQ-OAR-2021-0317-2326 and -2218.
\435\ EPA-HQ-OAR-2021-0317-2218.
---------------------------------------------------------------------------
Response: The EPA reviewed these comments and concluded that the
regulation should not include a specific list of other beneficial uses,
for the reasons pointed out by the commenters. However, as discussed in
section X.F.2.a of this document, it is the responsibility of the owner
and operator, along with the qualified professional engineer or other
qualified personnel performing the evaluation, to conduct due diligence
by ensuring that the list of options evaluated be comprehensive and
address commercially viable solutions.
Comment: One commenter \436\ argued that the EPA must limit the
exemption by clearly delineating specific ``technical'' reasons that
would justify flaring in lieu of the four gas recovery options. They
stated that the EPA must require operators to demonstrate the physical
impossibility of each of the gas recovery options to claim the
exemption to flare. The commenter provided potential physical
impossibility demonstrations for each abatement method.
---------------------------------------------------------------------------
\436\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------
Response: The EPA believes that including specific criteria in the
rule would be short-sighted and potentially eliminate legitimate
reasons that an option is technically infeasible. As discussed in
section X.F.2.a.1 of this document, the EPA generally characterizes
acceptable reasons in the general categories of physically,
logistically, or technically infeasible. Examples are provided in that
section.
Comment: One commenter \437\ suggested that the BSER opt-out should
include economic factors in addition to technical feasibility. The
commenter reported that the EPA concedes that it is proposing multiple
regulatory requirements whose implementation would be so burdensome
that they would be ``technically infeasible'' for some set of affected
facilities. According to the commenter, the EPA thus gives affected
facilities the ability to ``opt out'' of the performance standard if
the affected facility can show that compliance with the performance
standard would be infeasible for technical or safety reasons. The
commenter contends that ``technically infeasible'' is a misnomer and
that the EPA should explicitly include economic factors in addition to
a technical feasibility analysis. The commenter stated that, instead of
conflating technical feasibility and economic considerations, the EPA
in its final rule should transparently state that economic factors must
be part of an affected facility's ability to opt out of the regulatory
requirement. A state agency commenter \438\ asked what factors or
thresholds should be considered if economic feasibility needs to be
assessed.
---------------------------------------------------------------------------
\437\ EPA-HQ-OAR-2021-0317-2326.
\438\ EPA-HQ-OAR-2021-0317-2247.
---------------------------------------------------------------------------
Response: The EPA disagrees that economic feasibility is a valid
criterion on which to allow routine flaring or routing to control as
part of the standard. As shown in Table 23, the EPA has determined that
the costs associated with the control option determined to be BSER
(routing to a sales line) are reasonable. Put another way, the EPA has
already considered costs when setting the standard. As such, there is
no reason to allow for the type of ``economic feasibility'' showing
that commenters are requesting. Further, to include economic
feasibility as a criterion would necessarily take into account many
aspects of plant operation that are not related to the cost of the
control option (the BSER). The approach that commenters suggest could
result in a situation where wells that are operating close to the
margin due to inefficiencies and poor operation obtain an allowance to
routinely flare while more efficiently operated wells do not. The EPA
does not believe that allowing for this type of outcome is appropriate
because it would unfairly provide preferential treatment to certain
owners and operators based solely on the fact that their operation is
less efficient. Lastly, allowing the type of economic feasibility that
commenters are asking for would necessarily entail a certain degree of
subjectivity that the EPA does not find to be appropriate in this
context. The EPA believes that it would be inappropriate to establish
such thresholds in this context and does not find it necessary.
Comment: One commenter \439\ points out that the EPA proposal
contemplated four abatement alternatives to deal with associated gas
from oil wells. While each alternative has its pros and cons, the
alternatives are also necessarily based upon, to some extent, well and/
or lease economics. The predominant methodology used by regulators,
including the EPA, and operators, is to evaluate these economic
decisions on the gas production only and its prevailing pricing. The
commenter held that the entire well/lease revenue stream--including
revenue from oil--needed to be considered, especially if the decision
to get to a sales line is the question. The commenter stated that
considering gas revenue only actually promotes waste and negative
environmental impact. Therefore, according to the commenter, the EPA
rejects economic viability as a criterion to be considered in the
infeasibility determination that would allow routine flaring.
---------------------------------------------------------------------------
\439\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------
Response: The EPA agrees with the premise of the comment that the
standards for associated gas should not be limited to those options
whose cost can be covered by the recovery of associated gas. The EPA's
BSER analysis acknowledges that cost recovery through the sale or use
of associated gas will contribute to the cost effectiveness of some
methods of reducing emissions from associated gas, but the EPA did not
make the ability to recover the gas for sale the defining criteria to
select BSER or the equivalent alternatives. For example, an operator
who chooses to inject the gas into the well or another well may not
derive any financial benefit to injecting the gas in the form of
greater oil production, but injecting the gas is acceptable in lieu of
routing to a sales line because it achieves emissions reductions
equivalent to those for routing the associated gas to a sales line.
Comment: One commenter \440\ believed that the exemption for
technical infeasibility presents enforcement challenges. While an
operator's demonstration of technical infeasibility must be signed and
certified as to its truth, accuracy, and completeness, the commenter
provided that there is no requirement that the EPA review and approve
this demonstration prior to an operator's flaring. Rather, the proposal
only required that operators retain records of the certified
demonstration and provide them to the EPA as part of annual reporting.
The commenter indicated that this lack of requirement raises the
possibility that flaring will occur in the absence of a full, accurate,
complete, or otherwise adequate demonstration. The commenter indicated
that in order for the EPA to identify any problems or shortcomings in
the certified demonstration, the EPA must review the operator's
documentation, but this review will necessarily occur after an operator
has flared, potentially for a considerable amount of time. The
commenter states that this opens the door to extended periods of
flaring in violation of the rules. Another
[[Page 16952]]
commenter \441\ asserted that the technical infeasibility exemption
places a significant compliance monitoring burden on the EPA, or on
states with delegated air quality programs.
---------------------------------------------------------------------------
\440\ EPA-HQ-OAR-2021-0317-2433.
\441\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------
Response: The EPA does not agree with these commenters. As
explained above, the final NSPS OOOOb and EG OOOOc include provisions
that allow owners and operators to make certain technical infeasibility
demonstrations in limited circumstances. To the extent that an owner or
operator makes such a showing, the EPA believes that the requirement to
submit the demonstration and certification of infeasibility in the
annual report provides the opportunity for the EPA and/or state agency
to conduct a review. In the event that the owner or operator submits an
inadequate or fraudulent determination, or no determination at all when
they should have, they could be subject to penalties. In addition, the
professional engineer or other individual who certified the
demonstration could be subject to penalties, including criminal
charges. Therefore, no changes were made to the proposed requirements
for submission of the demonstrations and certifications.
Comment: With respect to the certification process, one commenter
\442\ recommended that the EPA require certification by an independent
third party. The commenter pointed out that the EPA proposed to allow
certification by either a professional engineer or a ``qualified
individual with expertise in the uses of associated gas.'' Notably, per
the EPA's proposal, an operator could use an in-house engineer or other
qualified individual, such as a contractor. The commenter noted that
there is no requirement that the individual be independent from the
operator. Certification by an independent third party, rather than a
professional engineer or a ``qualified individual with expertise in the
uses of associated gas,'' either of whom could be an in-house
individual or a person with significant ties to the company, will
enhance the credibility and reliability of the report. Certification by
an independent third party of all demonstrations seeking a flaring
exception is necessary to ensure a robust, complete, and accurate
demonstration of the reasons underlying the flaring request.
---------------------------------------------------------------------------
\442\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------
Response: The EPA does not agree that it is necessary for the
certifier to be an independent third party. In many cases, a person
most knowledgeable about the well characteristics and specifics of the
operation may be someone employed by the company. While the EPA
understands the concern raised by the commenter about the certification
being made entirely ``in-house,'' the EPA points out the severe
penalties and repercussions that could occur for both the owner/
operator and the certifier, as discussed here.
Comment: The commenter \443\ requested that the EPA further clarify
that both the certifier and the owner/operator may be subject to
penalties for submission of a fraudulent or significantly flawed
certification. The commenter notes that this clarification is
consistent with the EPA's proposal for pneumatic pumps. The EPA
proposed to include a technical infeasibility exemption from the zero-
emissions pneumatic pump standard, provided an operator submits a
demonstration certified by a qualified professional engineer or in-
house engineer with relevant experience. The EPA notes that it ``is
committed to ensuring that this technical infeasibility provision is
not abused or used as a loophole . . . ,'' pointing to the potential
for enforcement actions to be levied against both the owner/operator
and the certifier upon submission of a ``fraudulent, or significantly
flawed'' certification. The commenter urges the EPA to clarify that
this same potential penalty is applicable to the submission of
``fraudulent, or significantly flawed'' certifications in the context
of associated gas at the affected well facility, if the EPA retains the
technical infeasibility exemption.
---------------------------------------------------------------------------
\443\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------
Response: The EPA agrees with the commenter. Flaws in a certified
engineering analysis may result in an exception being inapplicable and
a related enforceable violation of the standards. Fraudulent or
significantly flawed certifications may result in both civil and
criminal liability and penalties for the owner, operator, and the
person that makes the certification.
Comment: One commenter \444\ suggested that operators seeking to
routinely flare must submit a thorough analysis and engineering
certification comparable to the initial certification each year. The
commenter recommended that this demonstration include the same
information as the initial demonstration, namely a detailed analysis
documenting the technical infeasibility or safety reasons for the
infeasibility and an explanation as to why none of the four gas
recovery options are technically feasible or safe. Each annual
demonstration must be certified.
---------------------------------------------------------------------------
\444\ EPA-HQ-OAR-2021-0317-2433.
---------------------------------------------------------------------------
Response: The EPA agrees with this comment and has clarified that
the exemption is only valid for a 1-year period and that a
demonstration and certification must be conducted each year to continue
to flare or route to control.
3. Gas Well Liquids Unloading Operations
In section X.F.3 of this document, the final NSPS OOOOb and EG
OOOOc requirements for gas well liquids unloading operations are
summarized. The BSER analysis is unchanged from what was presented in
the November 2021 Proposal (see 86 FR 63211-14, section XII.D: Proposed
Standards for Well Liquids Unloading Operations). Two regulatory
approaches were proposed in the November 2021 Proposal. As discussed in
the December 2022 Supplemental Proposal, the EPA considered the
comments submitted and revised the proposed requirements. Details of
these comments, the EPA's responses, and the rationale for the
supplemental proposal are provided in the December 2022 Supplemental
Proposal Federal Register preamble. As discussed in section X.F.1 of
this preamble, in the December 2022 Supplemental Proposal, the EPA
proposed to define the ``affected facility'' as a single well. Further,
the EPA proposed the ``modification'' definition to apply to a single
well that undergoes hydraulic fracturing or refracturing. Significant
comments were received on the December 2022 Supplemental Proposal on
the following topics: (1) the EPA's proposed zero-emissions standard,
and (2) the EPA's proposed recordkeeping and reporting requirements.
For each of these topics, a summary of the proposed rule, the comments,
the EPA responses, and changes made in the final rule (if applicable),
are discussed as follows. These comments and the EPA's responses to
these comments would apply to the standards proposed in both the NSPS
OOOOb and EG OOOOc because the same standards apply for both new and
existing sources. The EPA's full response to comments on the November
2021 Proposal and December 2022 Supplemental Proposal, including any
comments not discussed in this preamble, can be found in the EPA's RTC
document for the final rule.\445\
---------------------------------------------------------------------------
\445\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (6 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
---------------------------------------------------------------------------
[[Page 16953]]
a. Zero-Emissions Standard
In the December 2022 Supplemental Proposal, the EPA proposed
regulatory text specifying that all gas well liquids unloading
operations would be subject to the regulatory requirements. The BSER
proposed was to employ techniques or technologies that eliminate
methane and VOC emissions. Where meeting the zero-emissions standard is
infeasible due to technical or safety reasons, the EPA proposed to
require the employment of best management practices to minimize methane
and VOC emissions during well liquids unloading operations to the
extent possible.
The December 2022 Supplemental Proposal, however, specifically
requested further comment and additional information on an alternative
approach to applicability, where the standards for gas well liquids
unloading would only apply to well liquids unloading operations that
result in vented emissions.\446\
---------------------------------------------------------------------------
\446\ 87 FR 74782.
---------------------------------------------------------------------------
Comment: Several commenters \447\ opposed the EPA's proposed zero-
emissions standard or asserted that the EPA should only regulate
unloading operations that vent emissions.
---------------------------------------------------------------------------
\447\ EPA-HQ-OAR-2021-0317-0777, -0808, -2227, -2238, -2254, -
2258, -2294, -2391, and -2446.
---------------------------------------------------------------------------
Another commenter \448\ stated that the BSER must be technically
feasible for the source category. The commenter provided a brief
overview of the proposed standard under NSPS OOOOb that requires owners
or operators to perform liquids unloading with zero methane or VOC
emissions (86 FR 63179). The commenter mentioned that the proposed
standard is based on a determination that non-emitting techniques
constitute the BSER for these sources. At the same time, the commenter
pointed out that the EPA acknowledged that non-emitting techniques are
not always feasible or safe and that the EPA provides alternative
standards to cover those situations.
---------------------------------------------------------------------------
\448\ EPA-HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------
In general, the commenter supported this approach as a practical
matter and agreed that non-emitting measures and methods should be used
where they are technically feasible and cost-effective. The commenter
highlighted that the EPA rightly understands that non-emitting
approaches are not always practicable and that imposing an absolute
requirement would constitute an unwarranted prohibition on necessary
operations, such as liquids unloading, in many situations. With that in
mind, the commenter believed that the proposed alternative best
management practice measures are a common-sense solution.
Another commenter \449\ argued that the EPA should replace what the
commenter believed was an infeasible zero-emissions standard with a
requirement that the affected well liquids unloading operations
minimize emissions through best management practices. The commenter
stated that they have significant experience using a variety of
practices to safely and effectively minimize the emissions associated
with gas well liquids unloading but are concerned that those practices
would not satisfy the EPA's proposed zero-emissions requirement.
According to the commenter, there are many reasons why liquids may
accumulate in a wellbore and require liquid unloading, some of which
reasons are due to external factors not in the control of the well
operator. The commenter stated that the proposed standard would
necessitate a detailed review and discussion of infeasibility for each
event with no benefit to emissions.
---------------------------------------------------------------------------
\449\ EPA-HQ-OAR-2021-0317-0777.
---------------------------------------------------------------------------
The commenter recommended that, rather than establishing the
proposed zero-emissions standard with an exception for unloading with
minimized emissions when zero-emissions unloading is technically
infeasible, the EPA establish the use of best management practices to
minimize methane and VOC emissions during liquids unloading events to
the extent possible as the standard itself. The commenter warned that
the program contemplated by the EPA sets an impossible compliance bar,
and the commenter further reiterates that a standard to develop and use
best management practices to minimize methane and VOC emissions during
liquids unloading events to the extent possible will achieve the same
emissions reductions while eliminating the unnecessary burdens
associated with demonstrating that zero-emissions unloading is
infeasible.
Another commenter \450\ asserted that the rule should only apply to
venting during liquids unloading. The commenter added that industry
innovated to address the environmental problem of venting during
liquids unloading, and they believe that the EPA's proposal would
disincentivize this innovation. The commenter explained that
malfunctions of designed zero[hyphen]emissions liquids unloading events
would be addressed with designed venting events, with required best
management practices that minimize emissions, and with recordkeeping
and reporting.
---------------------------------------------------------------------------
\450\ EPA-HQ-OAR-2021-0317-2227.
---------------------------------------------------------------------------
Similarly, another commenter \451\ contended that the
implementation of the rule would be easier if the standards only
applied to wells that vent. However, the commenter suggested that the
EPA only develop emissions requirements for facilities that vent
emissions, not for facilities that would only vent emissions if
something goes wrong or not as planned. In these situations, the
commenter recommended the EPA develop separate requirements that would
apply.
---------------------------------------------------------------------------
\451\ EPA-HQ-OAR-2021-0317-2258.
---------------------------------------------------------------------------
One commenter \452\ requested that, with respect to the emissions
standards for liquids unloading, the EPA revise the rule so that an
unloading event which does not result in venting to the atmosphere is
not an affected facility.
---------------------------------------------------------------------------
\452\ EPA-HQ-OAR-2021-0317-2238.
---------------------------------------------------------------------------
Conversely, another commenter \453\ supported the November 2021
Proposal to define affected facilities to cover all wells undergoing
liquids unloading as a critical requirement to ensure that operators do
not simply claim to conduct liquids unloading events with zero-
emissions techniques, when venting is occurring. The commenter noted
that the EPA has recognized, ``under some circumstances venting could
occur when a selected liquids unloading method that is designed to not
vent to the atmosphere is not properly applied (e.g., a technology
malfunction or operator error).'' \454\ The commenter contended that in
some cases, the malfunction or error could be so great that it results
in venting 100 percent of the gas intended to be captured. Because of
this possibility, the commenter argued, the EPA must require
recordkeeping so it is aware of these events and overall emissions, and
to build an understanding of what causes these errors and how they can
be prevented. The commenter recommended that the EPA finalize the
December 2022 Supplemental Proposal's option 1 and require operators of
all wells undergoing liquids unloading to maintain records of the
number of unloading events that occur, the method used, and any venting
that occurred.
---------------------------------------------------------------------------
\453\ EPA-HQ-OAR-2021-0317-2433.
\454\ 86 FR 63179, November 15, 2021.
---------------------------------------------------------------------------
Response: The December 2022 Supplemental Proposal required that all
liquids unloading events employ techniques or technologies that
[[Page 16954]]
eliminate methane and VOC emissions (i.e., a ``zero-emissions
standard''). If this was not feasible for safety or technical reasons,
the EPA proposed to allow for the employment of best management
practices to minimize venting of emissions to the extent possible. The
EPA received comments that provided arguments against the proposed
zero-emissions standard. These commenters generally emphasized that
liquids unloading operations vary widely and standards should only
apply to events that vent to the atmosphere. While we proposed a zero-
emissions standard, we recognized that not every well that undergoes
liquids unloading will be able to eliminate venting.
The EPA has determined that, because of the intermittent and
necessary nature of allowing for variable methods and technologies
employed to unload liquids, the inability to measure emissions during
events, and the often-unpredictable timing as to when owners and
operators may need to vent emissions, a work practice standard is more
appropriate than an emissions standard for liquids unloading
operations. When evaluating whether it is appropriate to establish an
emissions standard, one of the things the EPA considers is whether the
application of a measurement methodology is practical due to
technological or economic limitations. While emissions can be measured
from an unloading event, it may not be practical for many unloading
events to be directly measured (e.g., venting may not be anticipated or
planned, type of technology employed to unload liquids does not lend
itself to direct measurement of emissions). This is reflected in GHGRP
subpart W required measurement and calculation methodologies. While in
the August 2023 GHGRP subpart W proposal, the EPA proposed that
emissions from liquids unloading under GHGRP subpart W must be
calculated using direct measurements (calculation method 1) at least
once every 3 consecutive years for each well, the proposal would
continue to allow flexibility by allowing for the use of non-
measurement calculation methods to accommodate times where direct
measurement is not feasible or practical. For example, GHGRP subpart W
calculation method 1 includes direct measurements, and methods 2 and 3
are non-measurement calculation methods. A very small percentage of
events reported to the GHGRP (less than 3 percent for years 2015 to
2019) for liquids unloading events were based on calculation method
1.\455\
---------------------------------------------------------------------------
\455\ 2023 Final Rule-Liquids Unloading GHGRP Basic
Analysis.xlsx. [See 2023 Final Rule TSD Supporting Spreadsheet
Attachments.]
---------------------------------------------------------------------------
The EPA also agrees that, by requiring that the proposed best
management practices be implemented for liquids unloading events that
vent, the same emissions reductions would be achieved, while
eliminating the requirement for an owner or operator to have to
document why it is infeasible to utilize a non-venting method due to
technical, safety, or economic reasons. The EPA believes that best
management practices can be implemented to safely and effectively
minimize the emissions associated with gas well liquids unloading.
However, with respect to commenters who believe that a well affected
facility/designated facility that conducts gas well liquids unloading
should only include liquids unloading events that vent, we disagree. As
one of the commenters noted, and we agree, unintended/unplanned venting
could occur from a malfunction or error and the EPA would want owners
and operators to be required to follow best management practices and
other reporting and recordkeeping requirements. Owners or operators can
and should develop best management plans to minimize venting during
liquids unloading, to include both planned/designed venting events and
those venting events that occur that are unplanned.
To conclude, the EPA has maintained its proposal that each well
affected facility that unloads liquids is subject to the requirement to
employ techniques or technology(ies) that minimize or eliminate venting
of emissions during liquids unloading events to the maximum extent. For
unloading technologies or techniques that result in venting to the
atmosphere, the final rule requires that owners or operators employ
best management practices that meet minimum specified criteria to
minimize venting of methane and VOC emissions for each gas well liquids
unloading operation. Unloading events that employ non-venting liquids
unloading technologies and techniques that do not result in venting of
methane and VOC emissions to the atmosphere are not subject to best
management plan requirements and the associated recordkeeping and
reporting requirements under the rule. An owner or operator of a well
affected facility that employs non-venting liquids unloading
technologies and techniques is only required to comply with minimal
recordkeeping and reporting requirements. In instances where there may
be an unplanned venting event, that event would be subject to the best
management practices to minimize venting of emissions and the
associated recordkeeping and reporting requirements. The EPA believes
that the final work practice standard and associated recordkeeping and
reporting requirements will incentivize owners or operators of well
affected facilities and well designated facilities to minimize or
eliminate the venting of emissions to the extent possible during
liquids unloading events.
b. Recordkeeping and Reporting Requirements
In the December 2022 Supplemental Proposal, the EPA proposed
specific recordkeeping and reporting requirements related to well
liquids unloading operations. Wells that utilized a non-venting method
would have been required to maintain records of the number of well
liquids unloading operations that occur within the reporting period and
the method(s) used for each well liquids unloading operation. A summary
of this information would also have been required to be reported in the
annual report. In recognition that under some circumstances, venting
could occur when a selected liquids unloading method that is designed
to not vent to the atmosphere is not properly applied (e.g., a
technology malfunction or operator error), under the proposed rule,
owners and operators in this situation would have been required to
record and report these instances, as well as document and report the
length of venting and what actions were taken to minimize venting to
the extent possible. Additionally, for wells that utilize methods that
vent to the atmosphere, the proposed rule would have required: (1)
Documentation explaining why it is infeasible to utilize a non-venting
method due to technical, safety, or economic reasons; (2) development
of best management practices that ensure that emissions during liquids
unloading are minimized; (3) employment of the best management
practices during each well liquids unloading operation and maintenance
of records demonstrating that the best management practices were
followed; and (4) reporting in the annual report both the number of
well liquids unloading operations and any instances where the well
liquids unloading operations did not follow the best management
practices.
[[Page 16955]]
Comment: Several commenters \456\ requested that the EPA not
require recordkeeping and reporting of non-venting liquids unloading
events. One commenter \457\ suggested that operators conducting liquids
unloading operations with zero methane and VOC emissions should not be
subject to burdensome recordkeeping, reporting, and other requirements.
One of the commenters \458\ noted that the non-vented liquids unloading
reporting requirements are not feasible due to the nature of those
events and because of the administrative burden associated with the
reporting requirements with no net gain in emissions reductions.
Similarly, one commenter \459\ requested that the EPA remove reporting
requirements that do not provide valuable emissions-related
information.
---------------------------------------------------------------------------
\456\ EPA-HQ-OAR-2021-0317-0599, -0749, -2227, -2238, -2294, -
2326, -2391, and -2428.
\457\ EPA-HQ-OAR-2021-0317-2227.
\458\ EPA-HQ-OAR-2021-0317-0749.
\459\ EPA-HQ-OAR-2021-0317-2258.
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Another one of the commenters \460\ opposed the proposed
recordkeeping and reporting obligations on owners or operators, on the
grounds that they would be burdensome and yield no environmental
benefit for well unloading activities that do not vent. For example,
they noted, owners or operators of well affected facilities where gas
well liquids unloading occurs must submit annual reports: (1)
identifying the well affected facility; (2) disclosing the number of
gas well liquid unloading operations that occurred there during the
reporting period; (3) describing the unloading operation method used
each time; and (4) reporting any deviations in detail along with
corrective actions. See, e.g., proposed 40 CFR 60.5410b(b) and
60.5415b(b). The commenter stated that when unloading operations do not
result in any vented emissions, these reports serve no purpose. To
avoid this result, the commenter recommended that the EPA clarify that
the standards for gas well liquids unloading operations apply only to
those operations that result in emissions to the atmosphere. The
commenter stated that this action would appropriately limit the
recordkeeping and reporting obligations and would still allow the EPA
to gather compliance information for a well that vents to the
atmosphere during liquid unloading. The commenter added that the EPA
should also make similar changes to proposed 40 CFR 60.5390c in EG
OOOOc.
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\460\ EPA-HQ-OAR-2021-0317-2391.
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One commenter \461\ recommended that proposed recordkeeping and
reporting for liquids unloading operations be simplified into a
manageable framework for operators and streamlined for liquid unloading
operations that vent to the atmosphere. The commenter noted that the
information proposed by the EPA within 40 CFR 60.5420b and 40 CFR
60.5420c for the recordkeeping and reporting as it pertains to liquid
unloading operations is focused more on an operator's tracking and
certifying techniques and less on allowing an operator to perform the
necessary procedures to unload liquids accumulated within the wellbore
and maintain natural gas production with as minimal emissions as
possible. To address this shortcoming, the commenter suggested that the
EPA define the data that operators should track per unloading operation
and remove all superfluous records that generate additional burden for
the operator and the EPA without added environmental benefit. The
commenter provided that these suggestions assume that liquid unloading
operations are to be conducted using a work practice standard.
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\461\ EPA-HQ-OAR-2021-0317-2428.
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Furthermore, the commenter contended that the current proposed
recordkeeping requirements do not offer a reasonable framework for
operators to maintain compliance assurance. In fact, the commenter
stated, the EPA has included a certification by a professional engineer
for every instance a well unloading operation vents emissions to the
atmosphere, in 40 CFR 60.5420b(c)(2)(ii)(B) and 40 CFR
60.5420b(b)(3)(ii)(B), based on the proposed zero-emissions standard.
The commenter noted that an owner or operator may not know about gas
well liquids unloading events that result in venting of emissions to
the atmosphere until the liquid operation is taking place, based on a
variety of parameters. For context, the commenter stated that a single
well affected facility may undergo multiple liquid unloading operations
in a single compliance period. For example, one well may necessitate an
unloading schedule of four times in a year. Based on best management
procedures, three of these events may occur with zero emissions, while
one of the events might vent to atmosphere for a short duration using
the same technique. The commenter believed the justification provisions
in 40 CFR 60.5420b(c)(2)(ii)(B) to be untenable when the same technique
used on a well may result in zero emissions during some liquid
operations but not during all liquid unloading operations in the same
compliance period. The commenter asserted that the fact is that in some
instances a well liquid unloading operation may need to vent emissions
for a short duration, sometimes as little as 30 minutes, to safely
perform the liquid unloading operation. The commenter therefore
requested that the EPA:
1. Remove the additional engineering certification statements under
the guise of technical demonstrations. These additional certifications
would be unnecessary if the standard followed a work practice
procedure.
2. Limit recordkeeping and reporting to liquid unloading operations
that result in emissions. This would reduce the administrative burden
for thousands of liquid unloading operation events. This is also
consistent with how both Colorado and New Mexico have organized
recordkeeping and reporting for their state regulations.
Similarly, another commenter \462\ requested that the recordkeeping
and reporting requirements be amended to be a workable framework for
operators to assure compliance, including removal of the certification
statement by an engineer in every instance that venting may occur.
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\462\ EPA-HQ-OAR-2021-0317-2248.
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Another commenter \463\ similarly argued that the EPA should not
require recordkeeping or reporting for each well liquid unloading
operation conducted during the year unless the EPA has defined ``well
liquid unloading operation'' to mean only those well liquid unloading
operations intended to vent to the atmosphere. As the EPA recognized in
its supporting documentation, the commenter reports that one primary
methodology that may be used to reduce or eliminate venting from
removal of liquids of gas wells is a plunger lift. In most operational
scenarios, a plunger lift will assist with liquid removal from the
wellbore without any venting to the atmosphere. The plunger lift will
operate either on a set cycle or based upon pressures reflected in the
wellbore. However, not all plunger lifts are designed to have the
necessary equipment onsite to track each cycle of the plunger lift.
Thus, the commenter explains, the EPA's proposal could require
installation of equipment to track the plunger cycles while providing
no emissions reductions benefits. The commenter noted that the EPA has
not fully evaluated the cost of installing and operating such tracking
[[Page 16956]]
equipment in the BSER analysis, and given that there will be no
emissions benefits, the EPA cannot show that such a requirement would
be cost-effective. The commenter added that even where equipment is
available to track the number of wellbore liquids removal events that
do not vent to the atmosphere, the operational costs of undertaking
that tracking are considerable and the data collected would be
significant. According to the commenter, the EPA has provided no
reasonable explanation for its need to obtain and track data relating
to the number of wellbore liquids removal events that do not vent to
the atmosphere. The commenter also stated that the EPA provides
virtually no explanation for its decision to stick with option 1, other
than the fact that ``malfunctions'' can result in vented emissions from
liquids removal operations that would otherwise meet the zero-emissions
standard. The commenter added that the EPA has no basis for concern
with respect to malfunctions as it has implemented a robust AVO and OGI
inspection program that would be expected to identify wells that have
emissions during liquids removal that were not expected or intended.
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\463\ EPA-HQ-OAR-2021-0317-2326.
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The commenter concluded that one simple solution to this problem is
to define well liquids unloading to mean only those wellbore liquids
removal events that are intended to vent to atmosphere. By defining
well liquids unloading in such a manner, the commenter believed, the
EPA would encourage operators to find solutions that eliminate venting
and to ensure that operators not only implement certain emissions
reduction requirements to reduce venting to atmosphere but also record
and report on those instances that do result in venting to the
atmosphere.
One commenter \464\ cited from the EPA-referenced study by Dr.
Allen, University of Texas, Environmental Science & Technology,
December 9, 2014, Methane Emissions from Process Equipment at Natural
Gas Production Sites in the United States: Liquids Unloadings, ``Some
wells with plunger lifts are automatically triggered and unload
thousands of times per year.'' The commenter stated that just a single
well with thousands of unloading events per year would create a
significant reporting burden, and when wells do not vent, they argued,
this reporting should not be required.
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\464\ EPA-HQ-OAR-2021-0317-2446.
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Response: The EPA considered the commenters' concerns and examples
provided regarding the burden associated with the proposed liquids
unloading operations recordkeeping and reporting requirements. These
concerns were evaluated along with the comments received on the zero-
emissions standard. The EPA agrees that requiring an owner or operator
to comply with some of the proposed recordkeeping and reporting
requirements in instances where an unloading event does not result in
venting to the atmosphere would impose a burden without any added
benefit environmentally (e.g., requiring that the number of liquids
unloading events that occurred when implementing a non-venting liquids
unloading technology or technique be tracked and reported).
As discussed under section X.F.3.a of this document, the EPA has
determined that the intermittent and necessary nature of the variable
methods and technologies employed to unload liquids, the inability to
reliably measure emissions, and the unpredictable nature as to when it
may be necessary to vent emissions makes a work practice standard more
practical and appropriate for liquids unloading operations than a zero-
emissions standard. As a result of this determination, the final rule
requires owners or operators of an affected gas well facility that
unloads liquids to employ techniques or technology(ies) that minimize
or eliminate venting of emissions during gas well liquids unloading
events to the maximum extent. For unloading events that result in
venting to the atmosphere, the final rule requires owners or operators
of well affected facilities/well designated facilities employ best
management practices to minimize venting of methane and VOC emissions
for each gas well liquids unloading operation, in addition to having to
comply with the associated recordkeeping and reporting requirements.
Where liquids unloading events were conducted using a technology/
technique that eliminates venting to the atmosphere, the final rule
only requires owners and operators to report the identification of the
well along with the non-venting technology or technique used in their
annual report. Where unplanned venting occurs from these wells during a
compliance period, an owner or operator would be required to follow
their best management practices plan for such events and comply with
the associated recordkeeping and reporting requirements for those
events.
As a work practice standard, the engineering certification
statement that would be required under the December 2022 Supplemental
Proposal, which would have required an explanation of why it is
infeasible to utilize a non-venting method due to technical, safety, or
economic reasons, is unnecessary and has been removed from the final
rule. Additionally, because there is no longer a requirement to comply
with a zero-emissions standard, there is no longer a need to maintain
records or reports containing information on a change of compliance
method from a zero-emissions standard to the implementation of best
management practices and vice versa.
4. Well Completions
In the November 2021 Proposal, the EPA proposed to retain the
requirements found in NSPS OOOO and NSPS OOOOa for reducing methane and
VOC emissions through REC and completion combustion. The BSER analysis
is unchanged from what was presented in the November 2021 Proposal (see
86 FR 63234-36, section XII.I: Proposed Standards for Well
Completions). The proposed regulatory text included in the December
2022 Supplemental Proposal was similar to the regulatory text found in
40 CFR 60.5375a for NSPS OOOOa. While the regulatory text was similar,
the EPA was made aware of potential confusion related to the well
completion requirements and well completion recordkeeping requirements
for wildcat wells, delineation wells, and low-pressure wells.
Therefore, the proposed regulatory text for NSPS OOOOb included
language to clarify these particular standards for new, modified, and
reconstructed sources moving forward. First, the EPA proposed
regulatory text at 40 CFR 60.5375b(f) to clearly state the requirement
to route emissions from wildcat well, delineation well, and low-
pressure well completions to a completion combustion device in any
instance (unless combustion creates a fire or safety hazard or can
damage tundra, permafrost, or waterways). The EPA was also made aware
from implementation of NSPS OOOOa that owners and operators were
unclear as to whether they can choose to comply with 40 CFR
60.5375a(f)(3)(ii) and make a claim of technical infeasibility for the
separator to function, which then precludes the requirement to route
recovered emissions to a completion combustion device. The EPA noted in
the December 2022 Supplemental Proposal that this preclusion was not
the EPA's intent in NSPS OOOOa and for this reason, we proposed to
clearly specify at 40 CFR 60.5375b(f) that an alternative to routing to
a separator (instead of routing all
[[Page 16957]]
flowback to a completion combustion device) is available only when the
owner or operator is able to operate a separator and has the separator
onsite (or otherwise available for use) and ready for use to comply
with the alternative during the entirety of the flowback period.
Second, the EPA proposed to eliminate recordkeeping requirements which
are not necessary for wildcat wells, delineation wells, and low-
pressure wells that had previously been included in NSPS OOOOa.
Specifically, the EPA proposed to not require records for
``beneficial'' use of recovered gas (i.e., routed to the gas flow line
or collection system, reinjected into the well or another well, used as
an onsite fuel source, or used for another useful purpose that a
purchased fuel or raw material would serve) nor records of ``specific
reasons for venting in lieu of capture.'' These records were not
required for wildcat wells, delineation wells, and low-pressure wells
because the well completion standards at 40 CFR 60.5375b(f) require
that all flowback, or gas recovered from flowback through the operation
of a separator, be routed to a completion combustion device (i.e.,
there will not be an instance, when complying with 40 CFR 60.5375b(f),
that beneficial use of recovered gas will occur).
The EPA did not receive comments on the EPA's well completion
proposed requirements that would lead the EPA to change what was
proposed in the December 2022 Supplemental Proposal and the EPA has
finalized the well completion requirements as proposed for both the
NSPS OOOOb and EG OOOOc.
G. Centrifugal Compressors
In section X.G of this document, the final NSPS OOOOb and EG OOOOc
requirements for centrifugal compressors are summarized. The BSER
analysis for wet seal centrifugal compressors is unchanged from what
was presented in the December 2022 Supplemental Proposal (see 87 FR
74784-85, section IV.G: Centrifugal Compressors). However, detailed
comments were received on the December 2022 Supplemental Proposal on
the following topics: (1) redefining the affected facility to include
compressors with dry seals and the proposed standard, (2) the EPA's
proposal to base the standard of performance as a numeric standard for
self-contained wet seal compressors and centrifugal compressors
equipped with dry seals, (3) the need to clarify that the standard is
on a per-seal basis, (4) other inherently low-emitting compressor
configurations, (5) the EPA's extension of requirements to centrifugal
compressors located at centralized production facilities, and (6) wet
seal compressors equipped with a seal oil gas separation system
utilized on the Alaska North Slope (ANS). For each of these topics, a
summary of the proposed rule (where relevant), the comments, the EPA
responses, and changes made in the final rule (if applicable), are
discussed here. These comments and the EPA's responses to these
comments generally apply to the standards proposed in both the NSPS
OOOOb and EG OOOOc. The instances where the comment and/or response
only applies to the NSPS OOOOb or EG OOOOc are noted. The EPA's full
response to comments on the November 2021 Proposal and December 2022
Supplemental Proposal, including any comments not discussed in this
preamble, can be found in the EPA's RTC document for the final
rule.\465\
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\465\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
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1. Redefining the Affected Facility To Include Centrifugal Compressors
With Dry Seals and the Proposed Standard
In the December 2022 Supplemental Proposal, the EPA redefined the
affected facility to include compressors with dry seals and proposed a
dry seal volumetric flow rate of 3 scfm (per seal) as a numeric
emissions standard.
Comment: Several commenters \466\ stated that the EPA should not
adopt the proposed dry seal standard of 3 scfm (per seal) because that
standard is unsupported and not adequately justified. Specifically, two
commenters \467\ stated that the EPA must first obtain data--both on
cost and, more importantly, on feasibility and reasonableness of the
standard itself--to support a proper BSER analysis.\468\ Any other
approach, according to the commenters, would be arbitrary and
capricious. The commenters described three main concerns (with support
for each of their concerns detailed in the RTC document for this
action) with the BSER determination. These concerns included the
following:
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\466\ EPA-HQ-OAR-2021-0317-2282, -2366, -2399, -2428, and -2483.
\467\ EPA-HQ-OAR-2021-0317-2282 and -2483.
\468\ For example, the commenters noted that the EPA has
recently proposed to require measurements for dry seal compressors
under the GHGRP, proposed ``Revisions and Confidentiality
Determinations for Data Elements Under the Greenhouse Gas Reporting
Rule,'' 87 FR 36920, 36974 (June 21, 2022). If the EPA finalizes
that requirement, it will start collecting data for dry seal
emissions.
---------------------------------------------------------------------------
(1) The commenters stated that the BSER determination contains
insufficient data to support the proposed standard or the cost that
would be required to maintain it. The commenters specifically dispute
the appropriateness of reliance on section 95668(d)(4-9), California's
Regulations \469\ for Greenhouse Gas Emission Standards for Crude Oil
and Natural Gas Facilities, to support the standard. Research into the
underlying sources of the California Air Resources Board (CARB)
regulation does not yield supporting information for the development of
the 3 scfm standard. According to the commenters, there is no data in
the California rulemaking supporting any numeric standard for dry
seals, much less a specific rate of 3 scfm.
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\469\ https://ww2.arb.ca.gov/sites/default/files/2020-03/2017FinalRegOrdersGHGEmissionStandards.pdf.
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(2) The commenters stated that the BSER determination does not
consider data showing that seal emissions rate is a function of
compressor size and suction pressure, and consequently, the standard
does not properly account for compressor size; and
(3) The commenters stated that record is devoid of any information
(or data) indicating that proper maintenance and repair could reduce
such compressors' dry seal emissions rate to 3 scfm or less, or any
information regarding the associated costs of doing so.
Several commenters \470\ emphasized that more reliable information
and data are or will be available that could be used in developing a
dry seal emissions standard. One of the commenters stated that based on
data submitted to the EPA pursuant to GHGRP subpart W for the 2021
calendar year, dry seal compressor driver power output ranged between 5
and 42,000 horsepower and for wet seals the compressor driver power
output ranged between 40 and 53,665 horsepower.\471\ The commenter
expressed that it does not believe compressors associated with the
higher end of this range should be expected to operate the same as
compressors closer to the lower end of this range.
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\470\ EPA-HQ-OAR-2021-0317-2282, -2366, -2428, and -2483.
\471\ Information was extracted from the EPA's Envirofacts
database using the GHG query builder: https://enviro.epa.gov/query-builder/ghg.
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Several commenters \472\ stated that, for transmission and storage,
the majority of turbines are manufactured by Solar Turbines. The
commenters suggested
[[Page 16958]]
that the Solar Turbine Product Information Letter (PIL) \473\ be
considered as a superior reference compared to the Natural Gas STAR
document. Information available from Solar shows that dry seal
emissions rates are a function of compressor type (e.g., size) and
operating (suction) pressure. The commenters reported that the PIL
provides data plots for a range of compressor sizes and suction
pressures. The commenters stated that the PIL data plots clearly
indicate that 3 scfm will be exceeded during standard operations for
many units and/or at many suction pressures that are common on
transmission systems. Since that data shows higher emissions rates for
many applications, the commenters contended that it alone refutes the
basis of the EPA's proposed 3 scfm emissions rate. According to the
commenters, if the EPA insists on proceeding with a standard for dry
seal compressors at this time, the EPA should establish a standard
based on function/operating conditions for the seal (i.e., unit size
and suction pressure); or, if the standard is a single emissions rate,
it must be high enough to address the largest units and highest suction
pressures in natural gas operations.
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\472\ EPA-HQ-OAR-2021-0317-2282, -2366, and -2483.
\473\ Solar Turbines Product Information Letter (PIL) 251,
``Emissions from Centrifugal Compressor Gas Seal Systems,'' January
2013 (Attachment C of their Comments). [Attachment C was redacted in
full in Docket.]
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As a result of these concerns, some commenters provided
recommendations to the EPA for development of a dry seal emissions
standard:
One commenter \474\ stated that the EPA should supplement
the docket with information to support why the proposed value is
representative of the population of dry seal compressors across the
nation (taking into consideration compressor size variability).
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\474\ EPA-HQ-OAR-2021-0317-2428.
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Several commenters \475\ recommended that the EPA postpone
establishing any type of quantitative threshold for dry seal
centrifugal compressors until after it finalizes amendments to GHGRP
subpart W. See 87 FR 36920 (June 21, 2022) (proposed rule). Once those
amendments are implemented, the commenters contended, the EPA would
have thousands of data points to give a more accurate dry seal
centrifugal compressor measurements that can be used for a subsequent
emissions threshold.
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\475\ EPA-HQ-OAR-2021-0317-2282, -2305, -2399, and -2428.
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Several commenters \476\ stated that if the EPA decides to
re-propose a numeric emissions standard for dry seal compressors, it
must first identify reliable information about emissions rates that are
achieved by well-maintained dry seal compressors and the maintenance/
replacement activity needed to achieve them. Because of the functional
dependence on unit size and suction pressure, they contended, it is
likely that a single emissions rate is not sufficient, unless that rate
is high enough to address the largest units and highest suction
pressures in natural gas operations.\477\ Second, they suggested that
any emissions rate standard must be expressed as a per-seal
standard.\478\ Finally, they stated that, if the standard would require
yearly measurements and monitoring of these compressors for the first
time, as the current proposal does, the cost of monitoring \479\ would
be part of the proposed standard and should be accounted for in the
BSER analysis.
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\476\ EPA-HQ-OAR-2021-0317-2282, -2399, and -2428.
\477\ One of the commenters expressed that they also believed
the EPA should investigate whether the types of onboard sensors that
Solar Turbines provides with some of its models are prevalent in the
industry. If that is the case, these sensors--even if they do not
measure emission rates specifically--may be adequate to provide
information about the health of the dry seals, possibly supporting a
standard requiring seal replacement as recommended by the
manufacturer.
\478\ The source information cited by the EPA (the California
regulation and EPA Natural Gas STAR document) clearly indicates that
this is an emission rate per seal, as does the Solar Turbines PIL.
If a dry seal emission rate threshold is retained in the final rule,
the commenters stated, it should be clearly indicated that the rate
applies on a per-seal basis.
\479\ For example, a flow meter is estimated to cost upwards of
$10,000 and installation also costs upwards of $10,000.
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One commenter \480\ noted that, in principle, they do not object to
a standard for dry seal compressors. However, they suggested that the
EPA should: (1) recognize that 3 scfm is an approximate average rate
for some dry seal compressors, but it is not characteristic of units
that may have an emissions rate several times higher--e.g., large
compressors with relatively high suction pressure; (2) consider the
upper end range or tiered emissions rates in the standard; (3) conduct
analysis and consider cost effectiveness of installing a seal vent
recovery/control system if the emissions rate cannot be met; (4)
account for the cost of additional monitoring that a numeric standard
would require; (5) clarify that the selected standard applies for each
dry seal, not for the entire compressor; and (6) if a standard is
retained (considering the factors above), propose a work practice
standard and define the schedule for operators to resolve the issue
when a unit exceeds its defined emissions rate threshold.
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\480\ EPA-HQ-OAR-2021-0317-2366.
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While several of the commenters \481\ specifically recommended that
the EPA wait for more accurate data based on GHGRP subpart W, they
added that, if the EPA is intent on establishing a dry seal emissions
threshold before receiving the GHGRP subpart W reports, they
recommended relying upon the manufacturer's specified maximum leak rate
for a particular unit. The commenters noted that a recent review of dry
seal leak curves from a major supplier of centrifugal compressors to
the natural gas industry indicates that dry seal leakage rates can vary
from 2 to 20 scfm per compressor (with two seals per compressor),
depending on the make, model, and operating suction pressure of the
compressor. If the EPA wishes to set one threshold applicable to all
dry seal centrifugal compressors in this rulemaking, the commenters
recommended that the EPA set the threshold at 10 scfm per primary dry
seal to allow for sufficient variability among existing dry seal leak
rates.
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\481\ EPA-HQ-OAR-2021-0317-2282, -2305, -2399, and -2428.
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Response: The EPA has evaluated these comments and acknowledges
that the data available on dry seal compressor emissions and flow rates
was limited and that a 3 scfm volumetric flow rate performance standard
may not be achievable for some centrifugal compressors equipped with
dry seals, even when properly maintained and the dry seal is not in
need of repair. Prior to receipt of these comments and based on
available information and data, it was believed that these higher-
emitting dry seal compressors represented compressors in need of repair
or maintenance. In fact, the EPA had not previously regulated
centrifugal compressors equipped with dry seals because they were
considered low-emitting when compared with compressors equipped with
wet seals. What has become evident, however, is that some centrifugal
compressors equipped with dry seals emit more than previously believed
and that a properly functioning compressor equipped with a dry seal can
be higher-emitting than a centrifugal compressor equipped with a wet
seal that is subject to requirements under NSPS OOOOb.
Given that compressors equipped with wet seals are regulated under
NSPS OOOO, NSPS OOOOa, and the final NSPS OOOOb, and given that
compressors equipped with dry seals are known to emit more than some
[[Page 16959]]
compressors with wet seals, the final rule retains the requirement to
conduct volumetric flow rate monitoring and associated maintenance and
repair (as needed) of these compressors consistent with what is
required for centrifugal compressors equipped with wet seals. However,
the EPA has revised the proposed volumetric flow rate performance
standard for centrifugal compressors with dry seals to be 10 scfm/seal
(i.e., representing a maximum flow rate applicable to all dry seals).
Based on manufacturer data provided on dry seal rate curves for
differing compressor models and configurations, a 10 scfm per seal flow
rate performance standard is supported as a maximum flow rate
performance standard that could be applicable to all dry seals until
additional flow rate and emissions data are obtained under GHGRP
subpart W.
The 10 scfm per seal flow rate performance limit reflects ordinary
performance of a well-maintained unit, therefore minimal additional
costs are expected. In many instances, compressors equipped with dry
seals will already be required to conduct annual compressor vent
volumetric flow rate monitoring under GHGRP subpart W. Owners or
operators of these compressors will be subject to minor recordkeeping
and reporting requirements, and maintenance and repair requirements
would only apply where the volumetric flow rate performance standard of
10 scfm per seal is exceeded. For owners or operators not already
required to conduct annual compressor vent volumetric flow rate
monitoring under GHGRP subpart W, the only additional cost is the cost
of conducting the required volumetric flow rate monitoring. See
discussion in section XI.G.2 of this document on the EPA's decision to
establish centrifugal compressor flow rate performance standards as
work practice standards and not as numeric limits where an exceedance
would be considered a violation.
As commenters noted, the EPA has requested flow rate/emissions
information under GHGRP subpart W for compressors equipped with dry
seals. Based on information received, the EPA may revisit and revise
the 10 scfm per seal volumetric flow rate performance standard for
compressors equipped with dry seals in the future.
2. Numeric Standard Versus Work Practice Standard
In reviewing the BSER determination and standards for centrifugal
compressors proposed in November 2021, the EPA stated that it is
feasible to prescribe a standard of performance, rather than a work
practice standard, for centrifugal compressors complying with the NSPS
OOOOb self-contained wet seal centrifugal compressor and EG OOOOc wet
seal compressor volumetric flow rate performance standards. The BSER
was therefore proposed to conduct repair and maintenance activities to
maintain emissions at or below a specified flow rate. Based on this
rationale, the EPA proposed a numeric emissions limit requirement. The
major difference between the numeric emissions limit standard proposed
under the December 2022 Supplemental Proposal and what the EPA proposed
in November 2021 was that under the December 2022 Supplemental
Proposal, owners and operators would be required to maintain emissions
at or below the specified emissions limit (a measured emissions flow
rate) whereas under the November 2021 Proposal, owners or operators
would have been required to conduct repairs and maintenance after
discovering an exceedance of a flow rate of the specified numeric
emissions limit (a measured emissions flow rate).
Comment: Several commenters \482\ asserted that the rule should
clarify the required compliance obligations, include a repair or
replacement timeline, and eliminate avoidable emissions from repair to
wet and dry seals. According to the commenters, the proposed NSPS rule
was drafted to require an emissions flow rate limit for wet and dry
seals. If the individual seal exceeds the 3 scfm (or a group of seals
exceeds the applicable standard), the EPA expects the operator to
repair or replace that seal, as appropriate.\483\ The proposed rule did
not describe what is required if the measurement at the seal vent
exceeds the applicable flow rate. The commenters recommend that dry
seal centrifugal compressors and self-contained wet seal compressors be
regulated through work practice standards. The commenters also
recommend that the rule provide a proposed timeline for repair or
replacements, as well as delay-of-repair provisions, consistent with
nearly all other NSPS drafted by the EPA.
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\482\ EPA-HQ-OAR-2021-0317-2258, -2282, -2305, -2326, -2399, -
2428, and -2483.
\483\ See, e.g., 87 FR at 74711-12 (table 3).
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According to one commenter,\484\ the EPA, without sufficient
explanation, summarily turned California's work practice standard into
an emissions rate limitation. The commenter alleged there is nothing in
the record about what measures would need to be implemented, and the
associated cost, to meet such a limitation. The commenter stated that a
delay-of-repair provision in such a regulatory scheme appropriately
recognizes that the unit must be shut down to effect any such repair
and replacement and that parts availability and supply chain
disruptions may be relevant to how quickly the repair or replacement
can be made. In addition, the commenter stated there is no record
information indicating that it is feasible for the source to anticipate
that a well-functioning wet seal that meets the 3 scfm limitation for 1
year will exceed it before the next year's test, or the cost of doing
so (if possible).
---------------------------------------------------------------------------
\484\ EPA-HQ-OAR-2021-0317-2483.
---------------------------------------------------------------------------
Several commenters \485\ suggested that the EPA allow one of the
following corrective actions by an operator within 2 years if the
applicable flow rate performance standard is exceeded:
---------------------------------------------------------------------------
\485\ EPA-HQ-OAR-2021-0317-2282, -2305, -2399, and -2428.
---------------------------------------------------------------------------
(1) repair or replace the dry seal, wet seal, or internal seal gas
recovery system; and
(2) route emissions from the dry seal vent through a closed vent
system or from the degassing vent using a cover and closed vent system
a control device; or
(3) route emissions from the primary dry seal vent through a closed
vent system or route the degassing vent using a cover and closed vent
system to a process.
The commenters \486\ recommended that if an operator cannot
complete the corrective action within 2 years, then a corrective action
plan with work scope and alternate schedule be submitted to the EPA
under a work-practice-based framework. According to the commenters, 2
years is a reasonable corrective action period since the corrective
actions listed can require significant planning, scheduling,
engineering, and construction. They explain that exceedance of the flow
rate performance standard after 2 years (in the absence of a corrective
action plan), or after the time stated in the corrective action plan,
would result in a deviation subject to recordkeeping and reporting
requirements similar to other types of compressors.
---------------------------------------------------------------------------
\486\ EPA-HQ-OAR-2021-0317-2282, -2305, -2399, and -2428.
---------------------------------------------------------------------------
Some commenters \487\ stated that the delay-of-repair provision is
consistent with delay-of-repair requirements under 40 CFR
60.5397a(h)(3), requiring repair within 2 years, or the next scheduled
shutdown (whichever is earlier), where repairs are technically
infeasible, where repairs would require a vent blowdown,
[[Page 16960]]
a compressor station shutdown, a well shutdown, or well shut-in, or
where it would be unsafe to repair. Further, the commenters added that
the EPA has taken this approach before in most of its NSPS
regulations.\488\ In fact, the EPA has also proposed a delay-of-repair
approach in other contexts of the December 2022 Supplemental Proposal
for the NSPS where emissions caused by the repair would exceed the
existing leak rate.\489\
---------------------------------------------------------------------------
\487\ EPA-HQ-OAR-2021-0317-2282 and -2399.
\488\ See, e.g., 40 CFR 60.482-9(c)(1) (delay of repair allowed
if emissions of purged material resulting from immediate repair are
greater than the fugitive emissions likely to result from delay of
repair), and 40 CFR 60.5416(b)(10) (delay of repair permitted if
emissions resulting from immediate repair would be greater than the
fugitive emissions likely to result from delay of repair).
\489\ See, e.g., proposed 40 CFR 60.5400b(h)(6)(ii)(A) (Delay of
repair showing requires in part ``that emissions of purged material
resulting from immediate repair are greater than the fugitive
emissions likely to result from delay of repair.'').
---------------------------------------------------------------------------
One commenter \490\ suggested 90 days as a reasonable timeframe
given the significant variety of repair methods (including replacement)
that may be appropriate for these units, as the EPA recognizes in its
preamble.
---------------------------------------------------------------------------
\490\ EPA-HQ-OAR-2021-0317-2282.
---------------------------------------------------------------------------
Several commenters \491\ proposed revisions to regulatory language
to implement the requested work practice approach and delay-of-repair
provision.
---------------------------------------------------------------------------
\491\ EPA-HQ-OAR-2021-0317-2282 and -2483.
---------------------------------------------------------------------------
Response: The EPA acknowledges that the record for the 3 scfm per
seal volumetric flow rate performance standard supports a work practice
standard and not a numeric standard for centrifugal compressors
equipped with wet seals. This is because the application of a
measurement methodology to centrifugal compressors is not always
practicable due to technological or economic limitations. It is not
practicable here for an exceedance of the 3 scfm per seal volumetric
flow rate to be a violation when the annual performance-based flow rate
reflects whether there are performance issues with a seal that need to
be addressed in order to take action to minimize the emissions/leak.
This is similar to the basis and monitoring established for fugitive
emissions component requirements, where a leak based on periodic
monitoring triggers requirements to minimize the emissions/leak.
The final rule has therefore been revised so that the format of the
3 scfm per-seal performance-based volumetric flow rate performance
standard for compressors equipped with wet seals is implemented as a
work practice standard and not as a numeric limit where an exceedance
would be considered a violation. Specifically, the final rule for
reducing GHGs and VOC from new centrifugal compressors is repair or
replacement of the wet seal where, based on the required monitoring,
the per-seal volumetric flow rate performance standard is exceeded. If
the volumetric flow rate measurement of the centrifugal compressor is
greater than 3 scfm (in operating or standby pressurized mode) or a
combined compressor seal rate greater than the number of compressor
seals multiplied by 3 scfm, an owner or operator must repair or replace
the centrifugal compressor seal within 30 calendar days after the date
of the volumetric emissions measurement. As such, for centrifugal
compressors equipped with wet seals, the volumetric flow rate of 3 scfm
is an action level that, if exceeded, triggers the action of repairing
or replacing the seal and is not a numeric limit.
Delay-of-repair provisions under a work practice standard
appropriately recognize that the unit must be shut down to affect any
such repair and replacement and that parts availability and supply
chain disruptions may be relevant to how quickly the repair or
replacement can be made. As such, the final rule allows for a delay of
repair if the repair or replacement would require a vent blowdown, or
it would otherwise be infeasible or unsafe, until the next process unit
shutdown. Specifically, delay of repair would be allowed if the repair
or replacement of a seal (1) is technically infeasible, (2) would
require a vent blowdown, (3) would require a process unit or facility
to shut down, (4) needs to be delayed because parts or materials are
unavailable, or (5) would be unsafe to repair during operation of the
unit. In cases where there is a need for a delay of repair, the repair
must be completed during the next scheduled process unit or facility
shutdown for maintenance, after a scheduled vent blowdown, or within 2
years, whichever is earliest.
Delay-of-repair provisions under a work practice standard
appropriately recognize that the unit must be shut down to effect any
such repair and replacement and that parts availability and supply
chain disruptions may be relevant to how quickly the repair or
replacement can be made. As such, the final rule allows for a delay of
repair if the repair or replacement would require a vent blowdown, or
it would otherwise be infeasible or unsafe, until the next process unit
shutdown. Specifically, delay of repair would be allowed if the repair
or replacement of a seal (1) is technically infeasible, (2) would
require a vent blowdown, (3) would require a process unit or facility
to shut down, (4) needs to be delayed because parts or materials are
unavailable, or (5) would be unsafe to repair during operation of the
unit. In cases where there is a need for a delay of repair, the repair
must be completed during the next scheduled process unit or facility
shutdown for maintenance, after a scheduled vent blowdown, or within 2
years, whichever is earliest. Delay of repair beyond the next scheduled
compressor shutdown for maintenance is allowed for a centrifugal
compressor wet and dry seal, if seal replacement is necessary during
the compressor shutdown for maintenance, seal supplies have been
depleted, and seal supplies had been sufficiently stocked before the
supplies were depleted. Delay of repair beyond the next compressor
shutdown for maintenance will not be allowed unless the next compressor
shutdown for maintenance occurs sooner than 6 months after the first
compressor shutdown for maintenance.
The format of the volumetric flow rate performance standard for
centrifugal compressors equipped with dry seals has also been revised
in the final rule as a work practice standard and not as a numeric
limit. However, for centrifugal compressors equipped with dry seals,
the volumetric flow rate performance standard is 10 scfm per seal and
not 3 scfm per seal (see section XI.G.1 of this document for discussion
on centrifugal compressors with dry seals). As such, for centrifugal
compressors equipped with dry seals, the volumetric flow rate of 10
scfm is an action level that, if exceeded, triggers the action of
repairing or replacing the seal and is not a numeric limit.
3. Clarification That the Standard Is Based on a Per-Seal Basis
Comment: Several commenters \492\ requested clarification that the
volumetric standard applies to each seal and not each compressor and
that the rule text clearly address manifolded vents on a combined basis
to reflect this. The commenters cited the precedent set by the CARB
where wet seal compressors in California are restricted to 3 scfm per
seal, and not per compressor as set forth in 17 Code of Colorado
Regulations (CCR) section 95668.
---------------------------------------------------------------------------
\492\ EPA-HQ-OAR-2021-0317-2258, -2282, -2305, -2366, -2399, -
2428 and -2483.
---------------------------------------------------------------------------
One of the commenters \493\ noted that the EPA's preamble
discussion, and at least some of the proposed rule text, imply that the
emissions rate would be
[[Page 16961]]
on a per-seal basis, and the commenter understands this to be the EPA's
intent. The commenter asserted that it is important that the EPA's
final rule more clearly reflect this intent. Specifically, according to
the commenter, the proposed text provided in 40 CFR 60.5380b or 40 CFR
60.5385b(a) (and parallel EG OOOOc language) does not provide the
distinction that the limits are per seal. The commenter asserted that
it would be impractical for a compressor with multiple seals
(centrifugal) to operate in the same way as a compressor with only a
single seal.
---------------------------------------------------------------------------
\493\ EPA-HQ-OAR-2021-0317-2282.
---------------------------------------------------------------------------
The commenter \494\ stated that the rule language must more clearly
address manifolded vents on a combined basis. The commenter noted that
the December 2022 Supplemental Proposal preamble provided that the
manifolded wet and dry seal flow rate must be ``less than or equal to
the number of compressors multiplied by 3 scfm (in operating or standby
pressurized mode).'' The commenter supported this approach, as it
reflects the practicalities of measuring emissions from manifolded
seals. The commenters also note that the approach is supported by the
2006 Natural Gas STAR report, which states that emissions rates from
two seal systems would be double the emissions from a single seal
system.
---------------------------------------------------------------------------
\494\ EPA-HQ-OAR-2021-0317-2282.
---------------------------------------------------------------------------
The commenters elaborated on why they believed that this was the
EPA's intent (for the standard to be based on a per-seal basis) and
several commenters provided in-line regulatory text changes where they
believed the clarification was needed.
Response: The EPA agrees that the basis and intent of the standard
is that it be applied on a per-seal basis and that clarity was needed
in the NSPS OOOOb and EG OOOOc regulatory text. The final rule
regulatory text has been revised to make this clear as suggested by the
commenters. Specifically, clarifying changes have been made to 40 CFR
60.5380b, paragraphs (a)(5) through (7) of NSPS OOOOb, and 40 CFR
60.5392c, paragraphs (a)(1) and (2), of EG OOOOc.
4. Other Inherently Low-Emitting Compressor With Wet Seal
Configurations
Comment: In their comments on the November 2021 Proposal, one
commenter \495\ stated that one type of low-emissions wet seal utilized
in compressors in the transmission and storage sector is a mechanical
seal, in which metal (tungsten carbide) is seated against carbide, with
oil pressing against the outside of the actual seal. Because the oil is
not in contact with the natural gas, the commenter explains that these
wet seals have generally zero degassing emissions. According to the
commenter, it makes no sense to subject such a zero-emissions wet seal
to control requirements. Accordingly, the EPA should exclude
compressors utilizing mechanical wet seals from the requirements
otherwise applicable to wet seal compressors.
---------------------------------------------------------------------------
\495\ EPA-HQ-OAR-2021-0317-0415 and -1391.
---------------------------------------------------------------------------
The commenter \496\ provided additional information on mechanical
seals in their comments on the December 2022 Supplemental Proposal for
the EPA to evaluate that provided support that, with respect to
mechanical wet seals, when a differential pressure is maintained on the
system, there is no off-gassing of the lube oil. The commenter attached
an example to their comment letter that shows that the oil is pumped
via the seal oil pump to the seal gas bottle, when the seal oil
pressure is maintained at 32 psi above discharge gas pressure.
---------------------------------------------------------------------------
\496\ EPA-HQ-OAR-2021-0317-2483.
---------------------------------------------------------------------------
Response: The EPA has evaluated the information provided by the
commenter on mechanical seals for both the November 2021 Proposal and
the December 2022 Supplemental Proposal. The EPA has made the
determination that mechanical wet seals are inherently low-emitting
where (1) a differential pressure is maintained on the system, (2)
there is no offgassing of the lube oil, and (3) the mechanical seal is
integrated into the compressor housing. As such, the final rule
definition of self-contained wet seal compressor has been revised, for
purposes of regulation, to include mechanical wet seals where (1) a
differential pressure is maintained on the system, (2) there is no off-
gassing of the lube oil, and (3) the mechanical seal is integrated into
the compressor housing. Self-contained wet seal centrifugal compressors
are allowed to meet a 3 scfm/seal volumetric flow rate limit in lieu of
being required to route emissions via a CVS to a control device or
process under NSPS OOOOb.
5. Applicability of Requirements to Compressors Located at Centralized
Production Facilities
The EPA proposed in the November 2021 Proposal \497\ to define
centralized production facilities separately from well sites because
the numbers and sizes of equipment, particularly reciprocating and
centrifugal compressors, are larger than for standalone well sites,
which would not be included in the proposed definition of ``centralized
production facilities.'' In the 2016 NSPS OOOOa, the EPA exempted
reciprocating and centrifugal compressors located at well sites from
the applicable compressor standards. However, the EPA believed the
definition of ``well site'' in NSPS OOOOa may have caused confusion
regarding whether centrifugal compressors located at centralized
production facilities were also exempt from the standards, which was
not our intent.
---------------------------------------------------------------------------
\497\ See 86 FR 63110 at 63184-85 (November 15, 2021).
---------------------------------------------------------------------------
To clarify our intent, the EPA defined centralized production
facility as follows in the December 2022 Supplemental Proposal in both
the NSPS OOOOb and EG OOOOc:
Centralized production facility means one or more storage
vessels and all equipment at a single surface site used to gather,
for the purpose of sale or processing to sell, crude oil,
condensate, produced water, or intermediate hydrocarbon liquid from
one or more offsite natural gas or oil production wells. This
equipment includes, but is not limited to, equipment used for
storage, separation, treating, dehydration, artificial lift,
combustion, compression, pumping, metering, monitoring, and
flowline. Process vessels and process tanks are not considered
storage vessels or storage tanks. A centralized production facility
is located upstream of the natural gas processing plant or the crude
oil pipeline breakout station and is a part of producing operations.
Additionally, the EPA defined the affected facility under the NSPS
OOOOb (and designated facility under EG OOOOc) as:
(b) Each centrifugal compressor affected facility [and
designated facility under the EG OOOOc], which is a single
centrifugal compressor. A centrifugal compressor located at a well
site is not an affected facility under this subpart. A centrifugal
compressor located at a centralized production facility is an
affected facility under this subpart.
For purposes of analyses, the EPA determined it was appropriate to
apply the same emission factors to centrifugal compressors located at
centralized production facilities as those used for centrifugal
compressors at gathering and boosting compressor stations. Given the
results of that analysis, the EPA proposed to apply the proposed NSPS
OOOOb requirements to centrifugal compressors located at centralized
production facilities. At that time, the EPA proposed a new definition
for ``centralized production facility'' intended to distinguish
compressors at standalone well sites where the EPA has determined that
the standard should not apply.
[[Page 16962]]
Comment: One commenter \498\ requested that the EPA clarify the
applicability of compressor standards to well sites. The commenter
stated that the definition proposed for central[ized] production
facilities may extend applicability to compressors located at well
sites, which have historically been exempt from the compressor
standards. As the EPA stated they have not updated their cost analyses
with new information with respect to well sites, the commenters believe
that extending applicability to well sites was not the EPA's intent.
Another commenter \499\ urged the EPA to keep the current compressor
exemptions shown in both subparts NSPS OOOO and OOOOa. The commenter
specifically requests that the EPA maintain that each compressor
``located at a well site, or an adjacent well site and servicing more
than one well site, is not an affected facility.''
---------------------------------------------------------------------------
\498\ EPA-HQ-OAR-2021-0317-0808.
\499\ EPA-HQ-OAR-2021-0317-0923.
---------------------------------------------------------------------------
Response: The EPA has finalized the proposed requirements related
to the definitions of the centrifugal compressor affected facility/
designated facility and centralized production facility. Some of the
commenters suggested that, by extending requirements to centralized
production facilities, the EPA was extending requirements to well sites
where centrifugal compressors were not previously regulated. That
interpretation confirms that clarity was needed. Based on the proposed
definition of the centrifugal compressor affected facility/designated
facility, in addition to the proposed definition for centralized
production facility as proposed in the December 2022 Supplemental
Proposal, we believe that we clarified our intent. That intent is that
centrifugal compressors located at well sites are not subject to
requirements. However, centrifugal compressors located at centralized
production facilities that consist of equipment at a single surface
site used to gather, for the purpose of sale or processing to sell,
crude oil, condensate, produced water, or intermediate hydrocarbon
liquid from one or more offsite natural gas or oil production wells
(including centrifugal compressors) are subject to centrifugal
compressor requirements.
6. Wet Seal Compressors Equipped With a Seal Oil Gas Separation System
Utilized on the Alaska North Slope (ANS)
Comment: One commenter \500\ representing Alaska oil and natural
gas companies requested that the EPA revise the proposed EG for
existing wet seal centrifugal compressors to address the
characteristics of the wet seal compressors deployed in Alaska oil
production operations. The commenter reported that their members use
wet seal compressors at their Alaska North Slope (ANS) and Cook Inlet
production fields to increase the pressure of residual gas captured in
production operations to enable delivery to gas processing plants and/
or reinjection into well fields. They noted that there are about 40
compressor trains on the ANS installed for this purpose. The
compressors in use on the ANS were installed in the late 1970s through
mid-1980s and have not been modified or reconstructed. They range in
size from 15,140 hp to 53,665 hp. None are currently subject to NSPS
OOOO or NSPS OOOOa.
---------------------------------------------------------------------------
\500\ EPA-HQ-OAR-2021-0317-2317.
---------------------------------------------------------------------------
The commenter stated that all the wet seal centrifugal compressors
in Alaska are equipped with a seal oil gas separation system that
separates gas from the sour seal oil exiting the compressor seal
assembly, upstream from the degassing drum. On the ANS the gas captured
in the seal oil trap is routed to various outlets for use as turbine
fuel, low-pressure fuel gas, compressor suction, flare purge or to
flare (for destruction). In Cook Inlet the gas is processed for
delivery to market. The commenter noted that the EPA described this
technology enthusiastically in the 2014 Natural Gas STAR Report.\501\
Sour seal oil passes through a ``seal oil trap,'' a type of separator,
prior to routing to the seal oil degassing drum. The commenter
described the seal oil traps in their comments on the November 2021
Proposal, which they resubmitted on the December 2022 Supplemental
Proposal. The commenter included a process flow diagram of the seal oil
recovery system on an ANS wet seal compressor. The commenter added that
the EPA's 2014 Natural Gas STAR Report praised the seal gas recovery
system deployed on the ANS as ``highly effective at capturing degassing
emissions from wet seal centrifugal compressors . . .'' \502\
---------------------------------------------------------------------------
\501\ EPA, Wet Seal Degassing Recovery System for Centrifugal
Compressors (2014) at 3 (``2014 Natural Gas STAR Report''), included
as attachment A to their comment letter.
\502\ 2014 Natural Gas STAR Report.
---------------------------------------------------------------------------
While the commenter supported the concept of adopting a volumetric
limit based on diligent maintenance and repair as BSER for control of
emissions from wet seal compressor vents, they asserted that the record
does not support that the proposed 3 scfm limit can be met for all wet
seal compressors. The commenter expressed support for the concept of
adopting a flow rate limit based on maintenance and repair as BSER for
control of emissions from wet seal compressor vents because they
believe that such an option avoids the safety risks, engineering
challenges, and extravagant cost of capturing and flaring low-volume,
low-pressure vent streams. They asserted that the problem with the EG
OOOOc proposal is that the 3 scfm proposed limit does not account for
variability in the size and configuration of wet seal compressors
within the source category and is not demonstrated or achievable for
wet seal compressors of the size and configuration of those deployed in
oil and gas production operations in Alaska.
The commenter stated that they would support the designation of
seal oil traps as an EG OOOOc compliance option for Alaska wet seal
compressors. For several reasons, however, Alaska wet seal compressors
equipped with seal oil traps do not uniformly meet the proposed 3 scfm
limit. They explained that the volume of seal oil slip from a wet seal
compressor correlates with compressor shaft size, pressure, and speed.
Alaska wet seal compressors span a broad range of capacities, and the
degassing drums serving the larger units vent higher volumes of seal
gas. Attachment C to their comments provides a table showing flow rate
data from 27 wet seal compressor degassing vents sampled by AOGA member
Hilcorp for the EPA GHG emissions reporting. The table shows the flow
rate per seal, but a single degassing drum can discharge gas from up to
four seal oil traps. The variability in the data reflects the
variability in size and configuration of the compressors and the fact
that each seal oil trap operates on a discharge cycle, and a degassing
drum may receive sour seal oil from up to four different seal oil traps
at any moment. Depending on when in the cycle the sample is taken, the
per-seal flow rate can exceed 3 scfm.
Based on the degassing drum flow rate data summarized in table 1
(of attachment C to their comment letter), the commenter proposed a
volumetric flow limit for Alaska wet seal compressor vents of 9 scfm of
methane and VOCs per seal, multiplied by the number of compressor seals
venting through a common stack. For example, they note that a two-stage
compressor has four seals (two per stage), all of which are manifolded
into one vent to the atmosphere. If the per-seal flow limit was 9 scfm,
the flow limit for the common vent should be 36 scfm.
Response: The EPA reviewed information materials submitted by
commenters related to the wet seal
[[Page 16963]]
centrifugal compressors in Alaska equipped with a seal oil gas
separation system that separates gas from the sour seal oil exiting the
compressor seal assembly, upstream from the degassing tank. These
compressors are considered inherently low-emitting based on Natural Gas
STAR and emissions/process information provided by the commenter. These
wet seal compressors with the sour seal oil traps recapture gas and
route the gas to the flare (simple pit flares), not to the ``compressor
suction [as with defined self-contained wet seal compressors].'' These
systems cannot always meet a 3 scfm limit due to the intermittent
process affecting flow.
The final EG OOOOc rule provides a new definition for a
``centrifugal compressor equipped with sour seal oil separator and
capture system'' and requires that, in Alaska, such compressors be
allowed to meet a performance-based volumetric flow rate standard of 9
scfm/seal, in lieu of the 3 scfm/seal performance-based volumetric flow
rate standard to account for the variability in the flow rate data
provided by the commenter that reflects the variability in size and
configuration of these compressors and the fact that each seal oil trap
operates on a discharge cycle, and a degassing drum may receive sour
seal oil from up to four different seal oil traps at any moment.
The final rule definition reads as follows:
Centrifugal compressor equipped with sour seal oil separator and
capture system means a wet seal centrifugal compressor system which
has an intermediate closed process that degasses most of the gas
entrained in the sour seal oil and sends that gas to either another
process or combustion device. The de-gas emissions are routed back
to a process or combustion device directly from the intermediate
closed degassing process; after the intermediate closed process the
oil is ultimately recycled for recirculation in the seals to the
lube oil tank where any small amount of residual gas is released
through a vent.
Comment: In addition to the commenter's \503\ concerns related to
the proposed volumetric performance-based standard requirement, the
commenter added that the NSPS OOOOb capture and control requirements
for new wet seal compressors are also not reasonably achievable for
existing compressors in Alaska. The commenter noted that the December
2022 Supplemental Proposal's proposed EG OOOOc offers the NSPS OOOOb
control options as a fallback for wet seal compressors that cannot meet
the presumptive 3 scfm flow limit, but they stated that these options
would require a cover on the degassing drums, connected through a
closed vent system to process or to a control device that achieves a
95.0 percent reduction in emissions, should an existing compressor ever
be modified or reconstructed. The commenter stated that in Alaska oil
and gas production operations there is no cost-effective option to
recover degassing drum emissions. Degassing drums vent small volumes of
methane and VOCs at atmospheric pressure. They referred to flow rates
reported in attachment C \504\ of their comment letter. They explained
that the volumes reported are small because the seal oil traps capture
and recycle most of the seal gas upstream of the degassing drum. They
reported that operators would need to install new compression devices
to boost degassing drum vent gas pressure to the approximately 20 psi
that would enable delivery of those streams to the flare header line.
The commenter stated that larger new compression devices would be
required to boost vent gas to a much higher pressure that would enable
delivery to a process line for injection into subsurface reservoirs.
---------------------------------------------------------------------------
\503\ EPA-HQ-OAR-2021-0317-2317.
\504\ Attachment C--Table of data titled, ``Hilcorp Alaska Wet
Seal Combustion Turbines, Volumetric Flow Rate Per Seal (2016-2011).
(Attachment C of their comment letter.)
---------------------------------------------------------------------------
According to the commenter, the combination of low methane and VOC
recoveries with high capture costs makes the capture and control
alternative very expensive on a cost-per-ton basis. They referred to
Kinder Morgan's comments on the November 2021 Proposal, where Kinder
Morgan provides that the 95.0 percent reduction requirement is
technically infeasible and cost-prohibitive even for wet seal
compressors located on natural gas pipelines in the lower 48
states.505 506 For wet seal compressors deployed in Alaska
production operations with seal oil traps, the cost per ton of covering
the degassing drum vents and reducing emissions from those vents by
95.0 percent would be prohibitive.
---------------------------------------------------------------------------
\505\ Comments of Kinder Morgan Inc. on EPA Proposed Standards
and Emissions Guidelines for the Oil and Natural Gas Sector at 8-20,
Document ID No. EPA-HQ-OAR-2021-0317-1375 (``Kinder Morgan
Comments'').
\506\ The ``lower 48'' consists of the 48 adjoining U.S. states
and the District of Columbia of the United States of America. The
term excludes the only two noncontiguous states, which are Alaska
and Hawaii, and all other offshore insular areas, such as the U.S.
territories of American Samoa, Guam, the Northern Mariana Islands,
Puerto Rico, and the U.S. Virgin Islands.
---------------------------------------------------------------------------
Response: As discussed earlier in this document, the EPA agrees
that ANS compressors equipped with a sour seal oil separator and
capture system are inherently low-emitting and that the costs of
requiring routing to a control device or process would be cost-
prohibitive for these compressors due to technical and costly retrofits
that would be needed (e.g., would need to install new compression
devices to boost degassing drum vent gas pressure) if any of their
existing ANS compressors were to be modified or reconstructed. The
commenters provided information and data to support their request that
these sources be allowed to meet a performance-based volumetric flow
rate standard in lieu of having to route emissions to a control device
or process. As provided by the commenter, and the EPA agrees,
recovering degassing drum emissions that vent small volumes of methane
and VOC at atmospheric pressure because the seal oil traps capture and
recycle most of the seal gas upstream of the degassing drum would not
be cost-effective. The final standards for NSPS OOOOb have been revised
to be consistent with what is being required under the EG OOOOc
presumptive standards. As such, the NSPS OOOOb final rule has been
revised to include a new definition for a ``centrifugal compressor
equipped with sour seal oil separator and capture system'' and requires
that, in Alaska, such compressors be allowed to meet a performance-
based volumetric flow rate standard of 9 scfm/seal. The volumetric flow
rate of 9 scfm is an action level that, if exceeded, triggers the
action of repairing or replacing the seal and is not a numeric limit.
H. Combustion Control Devices
In section X.H of this preamble, the final NSPS OOOOb and EG OOOOc
requirements for combustion control devices are summarized. The
rationale for the proposed requirements was presented in the December
2022 Supplemental Proposal in section IV.H. Combustion Control
Devices.\507\ This section of the preamble presents a summary of
significant comments received on the proposed requirements for
combustion control devices and the EPA's response to those comments, as
well as changes the EPA has made to the control device requirements
since the December 2022 Supplemental Proposal. The EPA's full response
to comments on the November 2021 Proposal and December 2022
Supplemental Proposal, including any comments not discussed in this
preamble, can be found in the EPA's RTC document for the final
rule.\508\
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\507\ See 87 FR 74792-74796 (December 6, 2022).
\508\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
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[[Page 16964]]
1. Outlet Concentration Limit
Comment: Some commenters \509\ wanted to ensure that the
concentration limit included in NSPS OOOOa for existing enclosed
combustors will continue to be allowed in NSPS OOOOb and EG OOOOc. One
commenter \510\ explained that destruction efficiency testing requires
VOC sampling at the inlet and outlet of the control device but that
many existing control devices do not have an inlet sampling port. The
commenter notes that combined with the potential need to install
additional monitoring equipment, allowing the use of a 20 ppm
concentration limit will provide facilities that do not have inlet
testing ports an alternative to meet compliance requirements for both
NSPS OOOOb and EG OOOOc. Another commenter \511\ stated that the
continuous monitoring option for organic compound concentration in the
control device exhaust is meaningless without the corresponding outlet
concentration performance standard. Additionally, the commenter
requested that the EPA clarify how operators should handle compliance
for existing control devices that are complying with the total organic
compound concentration standard under NSPS OOOO or OOOOa.
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\509\ EPA-HQ-OAR-2021-0317-2399 and -2428.
\510\ EPA-HQ-OAR-2021-0317-2399.
\511\ EPA-HQ-OAR-2021-0317-2428.
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Response: The EPA agrees that it is likely that most enclosed
combustion devices that are being used to control affected facilities
in NSPS OOOO and NSPS OOOOa demonstrate compliance during the
performance test with the alternative outlet concentration limit
instead of testing both the inlet and outlet of the control device. It
remains the EPA's position that it is reasonable to allow owners and
operators to continue to demonstrate compliance for these units with an
outlet concentration. It is also plausible that owners and operators
will have affected facilities under both NSPS OOOOb and EG OOOOc
controlled by the same enclosed combustion device, and so we are adding
the outlet concentration limit to both NSPS OOOOb and EG OOOOc.
In response to the comments received, the EPA is adding an outlet
concentration limit of 275 ppm volume as propane on a wet basis to both
NSPS OOOOb and EG OOOOc. This is the same outlet concentration limit
that is in NSPS OOOO and NSPS OOOOa. We anticipate that carrying over
this limit would not require a new performance test for most of these
existing control devices until the next periodic performance test is
due or until operation of the control device changes in a manner that
warrants a new performance test.
2. Monitoring Flares
Comment: A commenter \512\ stated that while they support the
requirements for no visible emissions and for monthly monitoring using
EPA Method 22, the EPA could also consider alternative monitoring
technologies and methods that would achieve equivalent or superior
results. The commenter urged the EPA to also require flares and control
devices to be monitored for compliance assurance during all fugitive
emissions surveys, both under the OGI and AVO program and under the
alternative periodic screening options. The commenter noted that
control devices and flares, especially unlit and malfunctioning flares,
are among the most observed and largest sources of methane emissions,
and it is therefore critical that they are regularly inspected and
monitored to ensure proper operation.\513\ The commenter further stated
that multi-basin research has identified unlit flares across the entire
country, and a Permian Basin study using flights conducted in 2020
found that 5 percent of all active flares were unlit.\514\ Moreover,
the commenter contends that monitoring flares and control devices
during fugitive emissions surveys poses very little additional burden
and can ensure emissions events are avoided.
---------------------------------------------------------------------------
\512\ EPA-HQ-OAR-2021-0317-2433.
\513\ The commenter cited to Genevieve Plant, et al.,
Inefficient and Unlit Natural Gas Flares Both Emit Large Quantities
of Methane, 377 Sci. 6614 (2022), https://www.science.org/doi/10.1126/science.abq0385, and Daniel H. Cusworth, et al.,
Intermittency of Large Methane Emitters in the Permian Basin, 8
Env't Sci. Tech. Letters 567 (2021), https://pubs.acs.org/doi/abs/10.1021/acs.estlett.1c00173, as examples.
\514\ The commenter cited to David R. Lyon, et al., Concurrent
Variation in Oil and Gas Methane Emissions and Oil Price During the
COVID-19 Pandemic, 21 Atmos. Chem. Phys. 6605 (2021), https://acp.copernicus.org/articles/21/6605/2021/.
---------------------------------------------------------------------------
Response: The EPA agrees that requiring owners and operators to
check flare operation during a fugitive emissions inspection adds
little additional burden and can help to reduce the incidence of unlit
flares. This is something some owners and operators already do in
practice, because in reviewing reports submitted under NSPS OOOOa, we
noted that many owners and operators listed flares in the fugitive
emissions report. Additionally, for technologies used under the
provisions of the periodic screening and continuous monitoring advanced
methane detection technology work practices in the final NSPS OOOOb and
EG OOOOc, we anticipate that by the nature of the operation of these
technologies, these technologies will detect unlit flares. Therefore,
requiring owners and operators to look at flares during an OGI
inspection will also help to even the playing field for all
technologies used in fugitive emissions monitoring. In the final rule,
we are requiring owners and operators to view the operation of their
flares with an OGI camera during fugitive emissions inspections
conducted with OGI to ensure that the flare is lit and that there are
no uncontrolled emissions coming from the flare. We are also requiring
owners and operators to ensure that the flare is operating properly
during AVO inspections by visually confirming that the pilot flame is
lit and operating properly.
Comment: A commenter \515\ stated that with respect to the
alternative to continuous flow monitoring, the EPA must include
requirements to reassess the engineering assessment when there are
changes to the sources vented to the flare, such as when additional
sources are routed to the control device, or those upstream sources
change, because the flow rate could increase, and proper destruction
efficiency would not be ensured.
---------------------------------------------------------------------------
\515\ EPA-HQ-OAR-2021-2362.
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Response: The EPA agrees with the commenter that the assessment for
maximum flow rate to an enclosed combustor or flare must be updated
when there are changes to the device's operation that are expected to
impact the initial assessment. We have revised the language in the
final rule to reflect this requirement.
3. Visible Emissions Observations
Comment: Commenters suggested that the EPA should permit the use of
cameras for operators to perform visual inspections of flare and
combustor smoke under EPA Method 22.\516\ Visible light cameras such as
security cameras are widely available and deployed at oil and gas
sites, and they can be positioned such that they can view potential
smoke from combustors and flares. Therefore, commenters request that
the EPA clarify that operators can utilize visible light cameras to
remotely observe flares and combustors for smoke and specify
installation and operation requirements such cameras need to
[[Page 16965]]
meet. Another commenter \517\ noted that video camera systems are
allowed as an alternative to EPA Method 9 observation under broadly
applicable approved Alternative Test Method 82 (ALT-082).\518\
Commenters also suggested that artificial intelligence and machine
learning should be allowed to continuously screen the video feed for
smoke detection and if smoke is detected, alert the operator that an
EPA Method 22 follow-up is required.\519\
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\516\ EPA-HQ-OAR-2021-0317-2336, -2428, -2298, and -2326.
\517\ EPA-HQ-OAR-2021-0317-2428.
\518\ https://www.epa.gov/sites/default/files/2020-08/documents/alt082.pdf.
\519\ EPA-HQ-OAR-2021-0317-2336 and -2428.
---------------------------------------------------------------------------
Response: The EPA agrees that camera systems that monitor for
visible emissions are a viable alternative to monthly EPA Method 22
observations for this sector, and there is already precedent for use of
such systems in refineries under 40 CFR part 63, subpart CC. Therefore,
the EPA has added the option to use a camera system for visible
emissions observations to the final rule. In order for an owner or
operator to use this option, the owner or operator must provide real-
time, high-definition video surveillance camera output to the nearest
control room or other continuously manned location where the camera
images may be viewed at any time, with the output recorded
continuously. The camera must be located at a reasonable distance above
the flare flame and no further than 400 meters from the emissions
source, at an angle suitable for visual emissions observations with the
sun not in the field of view. With this option, observation via the
video camera feed can be conducted readily throughout the day and will
allow the operators of the flare to watch for visible emissions more
frequently. The operator must document that they observed the camera
feed for at least one minute each day. We note that this option is not
the same as the digital opacity camera alternative outlined in ALT-082
which is not applicable in this rulemaking, as there is no opacity
limit in the rule.
The EPA has not added an option that allows for automated viewing
of the camera feed with artificial intelligence or machine learning,
because we have no information demonstrating that these systems work
effectively or under what circumstances these systems may encounter
problems with adequately identifying visible emissions. Owners or
operators are welcome to use such systems in addition to the
requirements of the rule.
4. Measurement of NHV
Comment: Several commenters \520\ were concerned with the proposed
NHV monitoring provisions for flares, which would require continuous
monitoring of the NHV unless the initial NHV sampling demonstration
(hourly sampling for 10 days) shows that the NHV is consistently above
the applicable NHV value, which is dependent on the flare type.
Commenters stated that the initial NHV sampling demonstration to show
that the NHV of a gas stream is always above the required NHV in 40 CFR
60.18(b) is unnecessarily burdensome and is even more burdensome than
what is required for refineries.\521\ Commenters suggest that the
proposed initial NHV sampling demonstration as an alternative to
continuous NHV monitoring should be simplified, because the NHV of vent
streams from affected facilities is typically fixed or well above the
minimum NHV requirements, as these vent streams consist of mostly
hydrocarbons and the simplest hydrocarbon has a NHV of approximately
900 British thermal units per standard cubic foot (Btu/scf), which is
well above the minimum NHV requirement proposed by the EPA. One
commenter \522\ provided data collected from laboratories that analyze
samples of associated gas and flared gas in North Dakota. Out of 7,774
gas samples collected and analyzed from 2020 through 2022, the average
NHV was 1,459 Btu/scf, while the maximum and minimum values were 1,007
and 2,846 Btu/scf.
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\520\ EPA-HQ-OAR-2021-0317-2248, -2305, -2326, -2353, -2399, and
-2428.
\521\ The commenter pointed to 40 CFR 63.670(j)(6)(D).
\522\ EPA-HQ-OAR-2021-0317-2248.
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One commenter \523\ stated that since the vent streams from
affected facilities are expected to have sufficient heating value, both
the proposed continuous NHV monitoring and the initial NHV sampling
demonstration are economically unreasonable. For the minimum NHV
demonstration alternative, the commenter reports that the cost is
expected to be $250,000 or more per demonstration. The commenter
summarizes that the cost of a vendor-conducted 10-day continuous
monitoring campaign for the initial NHV sampling demonstration is
estimated at a minimum of $250,000 to $275,000 while the cost of 200
hourly samples is estimated at a total of $300,000 to $400,000 with an
average cost per sample of $1,500 to $2,000 including shipping and
analysis.
---------------------------------------------------------------------------
\523\ EPA-HQ-OAR-2021-0317-2428.
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One commenter \524\ suggested that the EPA require a 10-day test
period with one sample every 6 hours, for a total of 40 sample
analyses. Another commenter \525\ proposed a simplified sampling
protocol for samples to be taken twice a day for 7 days. A third
commenter \526\ stated that the 10-day initial NHV sampling
demonstration should be simplified to a single sample including the use
of an appropriate, representative sample or an initial flare compliance
assessment under 40 CFR 60.18, with the operator documenting why the
sample is characteristic of the vent stream composition. After the
initial NHV sampling demonstration, continuous compliance would be
demonstrated through subsequent samples once every 3 years. The
commenters also stated that neither the continuous NHV monitoring nor
the initial NHV sampling demonstration alternative should be required
if operators can demonstrate that the NHV is never expected to be below
the minimum required value using a design evaluation or applicable
engineering calculations including process simulation software and
pressurized liquids sampling. One commenter \527\ stated that
continuous monitoring of NHV presents inaccuracy issues associated with
low or intermittent gas streams due to technological limits. While the
commenter agrees with the availability of the initial NHV sampling
demonstration in lieu of continuous monitoring, the commenter requested
that the EPA allow operators to periodically (i.e., quarterly) sample
representative inlet gas streams to demonstrate compliance with any
applicable heating value requirement for control devices used to
control affected facilities with intermittent or low flow gas streams
under this rule.
---------------------------------------------------------------------------
\524\ EPA-HQ-OAR-2021-0317-2305.
\525\ EPA-HQ-OAR-2021-0317-2399.
\526\ EPA-HQ-OAR-2021-0317-2428.
\527\ EPA-HQ-OAR-2021-0317-2298.
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A different commenter \528\ stated that the EPA must require direct
NHV monitoring at all oil and gas flares and combustion devices on a
continuous basis. The commenter states the NSPS general provisions
mandate that the Agency establish monitoring for the general
provisions' NHV operating limits, especially since the general
provisions themselves contain no monitoring requirements for this
limit. The commenter also stated that the EPA correctly concludes that
the current operating and monitoring practices and
[[Page 16966]]
requirements for well sites and centralized production facilities are
not adequate to ensure that flare control systems are operated
efficiently. The commenter was concerned with the proposed alternative
initial NHV sampling demonstration. The commenter suggested that 10
days of sampling cannot capture the variability of gas streams at oil
and gas facilities, due in part to compositional variability, inert
gases, and impurities in gas streams, and that it may not capture the
lowest NHV streams, giving the false impression that these facilities
are meeting the NHV operating limit when in fact they are not. The
commenter also stated that the alternative to continuous monitoring is
contradicted by findings the EPA has made regarding the great
variability of gas compositions over short periods of time and the
resulting dramatic effects on combustion efficiencies.\529\ The
commenter contends that this alternative cannot ensure that flares and
other control devices destroy 95 percent of VOCs and methane and that
this alternative does not fulfill the requirements of 40 CFR 60.18(d).
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\528\ EPA-HQ-OAR-2021-0317-2362.
\529\ The commenter cited to the proposed CAA section 112(d)(6)
review for Miscellaneous Organic Chemical Manufacturing. See 84 FR
69203 (December 17, 2019).
---------------------------------------------------------------------------
Response: The EPA disagrees with the comments that neither
continuous monitoring nor the initial NHV sampling demonstration (which
the EPA proposed as an alternative to continuous monitoring) is
unnecessarily burdensome or its cost unreasonable because the NHV value
will always (or is expected to always) be above the NHV values that we
proposed and are finalizing in this action. Specifically, we disagree
with the commenters' assumption that the NHV value will always (or is
expected to always) be above the minimum NHV values. As noted by a
commenter, the variability of gas compositions can have a dramatic
effect on the combustion efficiency of flares. This is especially true
for streams that may contain large amounts of inert materials.
Additionally, the EPA does not have data to support the assertion made
by the commenter that continuous sampling systems have technological
issues with sampling low and intermittent gas streams.
Nevertheless, in response to the comments received, the EPA has
reevaluated the proposed alternative initial NHV sampling demonstration
to see whether the burden can be reduced without compromising its
adequacy. We do not think it is appropriate to allow quarterly sampling
or a one-time sample, as suggested by some commenters, since there is
some variability in the streams that are sent to flares and enclosed
combustion devices which will likely be missed by not sampling daily.
However, we are reducing the number of daily samples associated with
the initial NHV sampling demonstration. Specifically, we are finalizing
a requirement to conduct twice daily sampling for 14 days, reducing the
total number of samples from 240 to 28. However, due to the significant
reduction in the initial sampling, we need to confirm that the vent gas
NHV remains above the required minimum value. Therefore, we are adding
to the NHV demonstration alternative an ongoing compliance
demonstration requirement to sample the vent gas to confirm that the
NHV remains above the required minimum value. We are requiring three
samples to be taken every 5 years. This ongoing demonstration timeline
aligns with the timeline for conducting periodic performance tests of
enclosed combustion devices, which is required every 5 years, so owners
and operators who are using enclosed combustion devices to meet the
applicable emission standards in this rule will be able to combine the
NHV vent gas sampling with the performance test, which will help to
reduce the burden associated with the ongoing compliance demonstration.
Additionally, where associated gas from a well affected facility is the
only inlet stream to the enclosed combustion device or flare, we are
not requiring owners and operators to conduct continuous monitoring of
the NHV or the alternative NHV sampling demonstration. In this case,
because associated gas is high in methane content and similar in
quality to sales grade gas, the NHV of the inlet stream to the enclosed
combustion device or flare is considered to be sufficiently above the
minimum required NHV for the inlet gas, and sampling is not needed to
confirm the NHV of the inlet stream. With the changes discussed above,
we believe that the burden of the NHV demonstration alternative in the
final rule is much reduced since proposal.
While the EPA agrees with the comment that the variability of gas
compositions can have a dramatic effect on the combustion efficiency of
flares, the EPA disagrees with the commenter's contention that the
alternative initial NHV demonstration is somehow contradicted by the
EPA's prior statements in the proposed CAA section 112(d)(6) review for
Miscellaneous Organic Chemical Manufacturing (84 FR 69203 (December 17,
2019)). The EPA notes that the great variability of gas compositions
over short periods of time and the resulting dramatic effects on
combustion efficiencies is especially true for streams that may contain
large amounts of inert materials, such as nitrogen padding from storage
vessels, which is common in the refining and chemical sectors. However,
in general, we do not expect to see those situations in the upstream
oil and gas sector, where most vent gas streams consist of high
percentages of methane, which has an NHV well above the required
minimum flare gas NHV. We also note that, in the preamble for the
Miscellaneous Organic Chemical Manufacturing risk and technology review
cited by the commenter, the flare discussion focused on flares that
burn ethylene oxide and olefins/polyolefins.\530\ Olefins and
polyolefins are more difficult to combust than the small, straight-
chain hydrocarbons generally found in the upstream oil and gas sector.
Therefore, the EPA does not believe that the alternative provided in
the final rule is contradicted by the findings in the Miscellaneous
Organic Chemical Manufacturing risk and technology review.
---------------------------------------------------------------------------
\530\ See 84 FR 69198-69199 (December 17, 2019).
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Comment: One commenter \531\ stated that some vent streams from
affected facilities could potentially be below the minimum NHV
requirement, including compressors in acid gas service or those at
enhanced oil recovery facilities. The commenter notes that either
situation could have high CO2 content which would lower the
NHV, so operators typically add assist gas or another vent stream with
sufficient heating value to facilitate proper control device operation.
In these limited situations, the commenter proposed that flow
monitoring of the assist gas and vent streams should be allowed as an
alternative to the continuous monitoring of NHV.
---------------------------------------------------------------------------
\531\ EPA-HQ-OAR-2021-0317-2428.
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Response: The EPA disagrees that monitoring assist gas flow rates
is an appropriate measure for ensuring proper combustion of inerts, as
assist gas does not contain any heating value. Therefore, the
introduction of assist gas will further reduce the heating value of the
gas, possibly to a point where proper combustion cannot be sustained.
Therefore, while monitoring or limiting assist gas is an important part
of ensuring proper flare operation, the EPA does not believe that
monitoring assist gas on its own can compensate for the drop in vent
gas NHV caused by inerts or provide enough information for the
[[Page 16967]]
owner or operator to ensure that proper combustion is occurring.
The introduction of inerts can greatly affect the NHV of the vent
stream sent to a flare. While the EPA agrees that most flare gas
streams at upstream oil and gas facilities will have no issue meeting
the required minimum NHV on a continuous basis, we are concerned about
situations where inerts may be introduced into the vent gas stream. To
guard against the possibility of unacceptable flare gas NHV in these
situations, we are including as part of the alternative NHV
demonstration a requirement that owners and operators consider sources
of inerts that may be sent to the flare, and that sampling must occur
when the highest percentage of inerts are sent to the flare to ensure
that NHV remains above the required minimum. If an owner or operator
cannot ensure that the NHV remains above the required minimum due to
the introduction of inerts, the owner or operator must continuously
monitor the NHV of the vent stream.
5. Assisted Flares
Comment: A commenter \532\ urged the EPA to require any assisted
flares in the oil and gas sector to meet an operating limit for the NHV
in the combustion zone (NHVcz), as the EPA has done for flares at
refineries and petrochemical sources. The commenter stated that, as the
EPA found in its 2014-15 refinery NESHAP rulemaking, many studies have
shown that the flare requirements in the general provisions cannot
ensure that flares achieve 98 percent destruction efficiency, which is
required under the refinery NESHAP.\533\ The commenter also referenced
an Enforcement Alert \534\ the EPA distributed regarding flaring
violations, in which the Agency recognized that certain needed
parameters affecting the efficiency of flares are not captured within
the general provisions, including maintaining the appropriate steam-to-
vent-gas ratio and ensuring that the NHVcz is high enough to maximize
combustion efficiency. The commenter explained that the EPA noted that
reliance on the NHV of the vent gas--the parameter that the NSPS and
NESHAP general provisions flare requirements use as an indicator of
good combustion--ignores any effect of steaming. Therefore, the
commenter stated that to incorporate steaming, a NHVcz is calculated to
include the assist steam.\535\ The commenter stated that because
complying with an operating limit for the heating value of the vent gas
cannot ensure 95 percent or greater destruction efficiency of VOCs and
methane by assisted flares, it is appropriate to update the flare
requirements for any assisted flares to ensure proper destruction
efficiencies. The commenter stated that the EPA must require owners and
operators to comply with an operating limit for NHVcz and must
promulgate monitoring requirements to ensure compliance with that
limit.
---------------------------------------------------------------------------
\532\ EPA-HQ-OAR-2021-0317-2362.
\533\ The commenter cited 79 FR 36905 and 80 FR 75189.
\534\ The commenter cited to EPA, EPA Enforcement Targets
Flaring Efficiency Violations, Enforcement Alert (August 2012).
\535\ EPA (U.S. Environmental Protection Agency). 2012.
Parameters for Properly Designed and Operated Flares. Prepared for
U.S. Environmental Protection Agency, Office of Air Quality Planning
and Standards, Research Triangle Park, NC. April 2012. Available at:
https://www3.epa.gov/airtoxics/flare/2012flaretechreport.pdf. See p.
3-32.
---------------------------------------------------------------------------
Response: The EPA is aware that some companies are installing air-
assisted flares to improve combustion efficiency, reduce smoking
incidence of flares, and facilitate operation when inerts are added to
the vent gas stream.\536\ We are still not aware of a prevalence of
steam-assisted flares in this sector, but it is possible to over-assist
an air-assisted flare. Therefore, in the final NSPS OOOOb, we are
adding requirements to ensure that these flares are operated in a
manner that will ensure good combustion efficiency, by adding operating
parameters for NHVcz and the NHV dilution parameter (NHVdil).
Specifically, the final rule includes the operating parameter values of
270 Btu/scf for NHVcz and 22 Btu/sqft for NHVdil that the EPA
established for the petroleum refineries sector (40 CFR part 63,
subpart CC).\537\ We recognize that these limits were intended to
demonstrate compliance with a destruction efficiency of 98 percent and
therefore are conservatively high for demonstrating compliance with the
applicable standards in NSPS OOOOb. We have added provisions similar to
those in 40 CFR 63.670(j)(6) which allow reduced monitoring for owners
and operators with flare gas streams that have a consistent composition
or a fixed minimum NHV. As stated above, we expect many flares in the
upstream oil and gas sector to burn high NHV streams and anticipate
that most owners and operators would be able to use these provisions.
Additionally, for air-assisted flares, we have added provisions that
allow a demonstration that based on the highest fixed or highest air-
assist rate used, the device will meet or exceed NHVdil in lieu of
continuously monitoring the air-assist rate.
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\536\ See, e.g., EPA-HQ-OAR-2021-0317-2409 and -2428.
\537\ See discussion in EPA-HQ-OAR-2010-0682-0206.
---------------------------------------------------------------------------
We are not adding these requirements to the final EG OOOOc because
we are concerned about the ability of existing sites to retrofit flares
in order to meet these requirements. While we do expect that most
owners and operators will be able to demonstrate compliance through
flare assessments, those who cannot demonstrate compliance through an
assessment will have to conduct continuous sampling of flare vent
streams and flowrate monitoring of both the flare vent stream and the
air assist stream. These accommodations can easily be made for a new
flare. For an existing flare at an existing site, these retrofits
require taking the flare out of service and may require adding ports to
set up these monitoring systems. Additionally, there is no guarantee
that ports can be placed at an appropriate location. Without additional
information on assisted flares at existing sites and the ability of
owners and operators to retrofit these flares, we are reluctant to
place these requirements on existing sources, and as such, we are not
adding these requirements to the final EG OOOOc.
6. Alternative Flare Monitoring
Comment: A commenter \538\ recommended that the EPA consider adding
an alternative approach for monitoring flares that is more cost-
effective and will achieve the same objective. The commenter pointed
out that there have been significant advancements in the field of flare
performance monitoring technology in recent years, including the Video
Imaging Spectral Radiometry (VISR) technology which has been developed
to remotely and directly monitor flare combustion efficiency and the
Simplified VISR technology which has been developed to remotely monitor
NHVcz for steam-assisted flares and NHVdil for air-assisted
flares.\539\ The commenter noted that in November 2022 the EPA funded
additional testing with focus on the Simplified VISR technology on both
steam-assisted and air-assisted flares at the John Zink flare testing
facility in Tulsa, Oklahoma. The commenter summarized the test results
in exhibit 3 of their letter and stated that, based on these results,
Simplified VISR technology can be easily deployed for a short-term
study or long-term continuous monitoring of NHVcz for steam-assisted
flares or NHVdil for air-assisted flares at a cost comparable to an OGI
camera. The commenter requested
[[Page 16968]]
that the EPA allow operators to use the Simplified VISR method to
demonstrate compliance and give operators a choice between a
calorimeter and the Simplified VISR. Additionally, if an operator
chooses to do the 10-day initial NHV sampling demonstration instead of
continuous monitoring of NHV, the Simplified VISR device could be
installed to monitor the flare for 10 days and could operate
autonomously and continuously--a significant advantage over manually
collecting 200 hourly samples.
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\538\ EPA-HQ-OAR-2021-0317-2457.
\539\ See EPA-HQ-OAR-2021-0317-0604.
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To facilitate the described alternative approach, the commenter
stated, the flare NHV standard needs to be supplemented. The current
NHV limit is based on the heat content in the gas stream that is fed to
the flare, but the Simplified VISR measures NHVcz, which the commenter
stated represents a better surrogate parameter for flare performance
than vent gas NHV. To facilitate the Simplified VISR as an alternative
to the proposed NHV limit, the commenter recommended that the final
rule allow the operator to comply with the NHVcz and NHVdil limits
promulgated in other rules.\540\ The commenter points out that these
standards correspond to a combustion efficiency of 96.5 percent and a
destruction efficiency of 98 percent, which is higher than the control
efficiency required in the December 2022 Supplemental Proposal,
representing a 60 percent methane emissions reduction (from 5 percent
of the flared process stream down to 2 percent).
---------------------------------------------------------------------------
\540\ The referenced limits are 270 Btu/scf NHVcz for steam-
assisted flares and of 22 Btu/sqft NHVdil for air-assisted flares.
These standards were first promulgated in 40 CFR part 60, subpart
CC, at 40 CFR 63.670.
---------------------------------------------------------------------------
Response: The EPA notes that it has been reviewing the development
of VISR to monitor flare combustion efficiency for several years. While
we are not including it as an alternative in the final rule, as we have
not yet developed a standard method for its use, the final rule
provides a pathway to allow for the use of VISR, Simplified VISR, or
other similar technology. In this pathway, an owner or operator could
request an alternative test method to use a technology such as VISR
that continuously monitors combustion efficiency or a technology such
as Simplified VISR that continuously monitors NHVcz and NHVdil. The
approval of such a request may be site-specific or may instead become
broadly applicable, approved for a class of combustion devices, and
listed on the EPA's website as an alternative test method.
To facilitate the pathway for potentially allowing these
alternatives, the EPA is finalizing limits of 270 Btu/scf for NHVcz and
22 Btu/sqft for NHVdil. Destruction efficiency is a measure of how much
of the hydrocarbon is destroyed, and combustion efficiency is a measure
of how much of the hydrocarbon burns completely to yield CO2
and water vapor. As such, combustion efficiency will always be less
than or equal to the destruction efficiency. In the EPA's report \541\
on the development of parameters for properly operated flares, we
stated that the relationship between destruction and combustion
efficiency is not constant and changes with different compounds, but
that we considered that a flare with a combustion efficiency of 96.5
percent achieved a destruction efficiency of 98 percent. We are
uncertain if the relationship continues to hold at the same level as
combustion efficiency continues to decrease. Therefore, in this final
rule, which includes 95 percent emissions reduction standards, we are
taking a conservative approach. If an owner or operator uses an
alternative test method, such as VISR, to demonstrate compliance with
the emissions reduction standards for a combustion control device and
uses a test method that continuously monitors the combustion
efficiency, we are requiring that the combustion device used to meet
such standard have at least 95 percent combustion efficiency, as this
will ensure a destruction efficiency of at least 95 percent.
---------------------------------------------------------------------------
\541\ EPA (U.S. Environmental Protection Agency). 2012.
Parameters for Properly Designed and Operated Flares. Prepared for
U.S. Environmental Protection Agency, Office of Air Quality Planning
and Standards, Research Triangle Park, NC. April 2012. Available at:
https://www3.epa.gov/airtoxics/flare/2012flaretechreport.pdf.
---------------------------------------------------------------------------
In this final rule, owners and operators approved for an
alternative test method that uses a technology that continuously
monitors combustion efficiency or NHVcz and NHVdil would not be
required to monitor flare vent gas flow rate or vent gas NHV. If the
alternative test method uses a technology that continuously monitors
combustion efficiency, the owner or operator would not be required to
continuously monitor for the presence of a pilot flame or have an alert
to the control room for the pilot flame. If the alternative test method
uses a technology that can identify periods of visible emissions, the
owner or operator would not be required to perform monthly EPA Method
22 observations. The EPA has also added a pathway to use an alternative
test method to demonstrate continuous compliance with 95 percent
combustion efficiency as part of the NHV initial sampling
demonstration. In lieu of conducting vent gas NHV sampling during the
initial demonstration period, the owner or operator would demonstrate
that the combustion control device continuously achieves at least 95
percent combustion control, thus demonstrating that the heating values
of the streams sent to the flare are consistently above the minimum
level necessary to achieve proper combustion.
7. Other Changes to Control Device Requirements
Additionally, the EPA has made a number of clarifications and minor
adjustments to the regulatory text in response to comments received:
Revised 40 CFR 60.5412b(a)(1)(ii) and (f)(1)(vii)(D)(1) to
allow owners and operators to set the minimum temperature limit for
combustion devices based on operation during the performance test.
Revised 40 CFR 60.5412b(a)(1)(viii), 60.5412b(a)(3)(viii),
60.5413b(e)(2), 60.5415b(f)(1)(vii)(A)(1), and 60.5417b(d)(8)(i) to add
a requirement that an alert be sent to the control room when a pilot
flame is no longer lit.
Revised 40 CFR 60.5412b(a)(1)(ix), 60.5413b(e)(3),
60.5415b(f)(1)(vii)(A)(2), and 60.5417b(d)(8)(v) to allow the duration
of the visible emissions observation to be less than 15 minutes if the
observer sees visible emissions for at least 1 minute prior to the end
of the 15-minute period.
Revised 40 CFR 60.5412b(a)(3)(vi) and 60.5417b(d)(8)(iv)
and added 40 CFR 60.5415b(f)(1)(vii)(A)(6) to clarify that the minimum
flow rate requirement applies to both enclosed combustion devices and
flares.
Revised 40 CFR 60.5413b(b)(5)(ii) to allow control devices
to be tested 30 days after returning to service if the control device
is not operational at the time that a performance test is due.
Revised 40 CFR 60.5413b(b)(5)(ii) to remove the conflict
with 40 CFR 60.5413b(a) as to whether enclosed combustion devices must
be periodically tested.
Revised 40 CFR 60.5413b(d)(11)(iii) to indicate that when
the manufacturer meets the testing requirements outlined for an
enclosed combustion device, the control device will meet the
requirement for 95.0 percent destruction of both VOC and methane.
Revised 40 CFR 60.5413b(d)(12) to update submittal
addresses.
Revised 40 CFR 60.5413b(e), 60.5417b(d)(7), and
60.5417b(g)(6) to align the monitoring requirements for
[[Page 16969]]
all enclosed combustion devices, regardless of whether they are tested
by the manufacturer or the owner or operator.
Revised 40 CFR 60.5417b(c) to clarify that monitoring
systems that check for the presence of a pilot flame must record a
reading at least once every 5 minutes and to clarify how to average
monitored parameters.
Revised 40 CFR 60.5417b(c)(2) through (4) to change site-
specific monitoring plan to a company-defined area monitoring plan, to
align the terminology with the terminology used for fugitive emissions
monitoring.
Revised 40 CFR 60.5417b(d)(8)(ii) to allow owners and
operators the option to use gas chromatographs, mass spectrometers, and
grab sampling systems to monitor NHV.
Revised 40 CFR 60.5417b(d)(8)(ii) to exempt operators from
conducting monitoring of NHV for associated gas routed to an enclosed
combustion device or flare if the device or flare is receiving only
associated gas (as defined in 40 CFR 60.5430b).
Revised 40 CFR 60.5417b(d)(8)(iv) to change the required
flow meter accuracy requirement from 2 percent to 10 percent in order
to allow owners and operators additional metering device options and to
reduce burden, considering the large range of flows that may be
encountered in some control devices.
Revised 40 CFR 60.5417b(d)(8)(iv) to clarify ``line
pressure'' to ``inlet line pressure.''
Revised 40 CFR 60.5417b(d)(8)(iv) to change the
terminology ``backpressure preventer'' to backpressure regulator valve
and to add continuing operational and maintenance requirements for the
backpressure regulator valve.
Deleted 40 CFR 60.5417b(e)(2) in order to change the
averaging time for gas flow rate from 1 hour to 3 hours to align with
other operating parameters.
Clarified the requirements for carbon adsorption systems
in 40 CFR 60.5417b(f)(1).
I. Reciprocating Compressors
In section X.I of this document, the final NSPS OOOOb and EG OOOOc
requirements for reciprocating compressors are summarized. The BSER
analysis is unchanged from what was presented in the November 2021
Proposal (see 86 FR 63214-20, section XII.E. Proposed Standards for
Reciprocating Compressors). However, significant comments were received
on the December 2022 Supplemental Proposal on the following topics: (1)
the EPA's proposal to format the performance-based volumetric flow rate
standard of performance as a numeric standard, (2) scheduled-based
packing replacement approach, (3) need to clarify that the standard is
on a per-cylinder basis, (4) request that the EPA allow the alternative
compliance option of routing to a control device in addition to routing
to the process, and (5) the EPA's extension of requirements to
reciprocating compressors located at centralized production facilities.
For each of these topics, a summary of the proposed rule (where
relevant), the comments, the EPA responses, and changes made in the
final rule (if applicable), are discussed here. These comments and the
EPA's responses to these comments generally apply to the standards
proposed in both the NSPS OOOOb and EG OOOOc as the standards proposed
under the NSPS OOOOb and EG OOOOc were the same. The EPA's full
response to comments on the November 2021 Proposal and December 2022
Supplemental Proposal, including any comments not discussed in this
preamble, can be found in the EPA's RTC document for the final
rule.\542\
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\542\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
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1. Numeric Standard Versus Work Practice Standard
In reconsidering the BSER determination and standards for
reciprocating compressors proposed in November 2021, the EPA recognized
that it is feasible to prescribe a standard of performance, rather than
a work practice standard,\543\ for reciprocating compressors.
Accordingly, the EPA proposed a numeric emissions limit requirement in
the December 2022 Supplemental Proposal. The major difference between
that proposed standard and what the EPA proposed in November 2021 was
that under the supplemental proposal, owners and operators would be
required to maintain emissions at or below the emissions limit
(emissions flow rate of 2 scfm) whereas under the November 2021
Proposal, owners or operators would have been required to replace rod
packing only after discovering an exceedance of 2 scfm. The BSER was
therefore proposed to be the replacement of the rod packing and/or
other necessary repair and maintenance activities to maintain emissions
at or below 2 scfm.
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\543\ Under CAA section 111(h)(1), work practice standards are
appropriate only where ``it is not feasible to prescribe or enforce
a standard of performance.'' CAA section 111(h)(2) defines such
infeasibility as ``any situation in which the Administrator
determines that (A) a pollutant or pollutants cannot be emitted
through a conveyance designed and constructed to emit or capture
such pollutant, or that any requirement for, or use of, such a
conveyance would be inconsistent with any Federal, state, or local
law, or (B) the application of measurement methodology to a
particular class of sources is not practicable due to technological
or economic limitations.''
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Comment: The EPA received several comments from industry \544\ that
asserted that a numeric emissions standard in lieu of a work practice
standard is unsupported and unworkable. One commenter \545\ stated that
in the November 2021 Proposal, the EPA described a work practice
standard that would require yearly monitoring and replacement of the
rod packing when the measured emissions exceed 2 scfm. The commenter
noted that the EPA cited the Natural Gas STAR document in the November
2021 Proposal that described a work practice approach for rod packing
replacement. The commenter added that the work practice approach,
including a 2 scfm threshold for triggering rod packing replacement,
was further demonstrated at the EPA's November 2019 Natural Gas STAR
and Methane Challenge Workshop.\546\ The commenter added that the
California regulation \547\ cited by the EPA in the December 2022
Supplemental Proposal TSD is also a work practice standard with a 2
scfm threshold. The commenter stated that the December 2022
Supplemental Background TSD does not include any information to support
an emissions standard rather than a work practice--and the November
2021 Proposal TSD \548\ envisioned a work practice standard. Thus, the
commenter stated that if the EPA intended to propose an emissions
limitation standard, the EPA gave no justification for, or analysis of,
the change, which the commenter believed is arbitrary and capricious.
The
[[Page 16970]]
commenter believed that based on the two TSDs, it appeared that the EPA
intended to propose a work practice standard that triggers rod packing
maintenance when the threshold is exceeded. The commenter expressed
that the extensive and case-by-case nature of rod packing replacement
makes it particularly unsuitable for an emissions limitation standard.
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\544\ EPA-HQ-OAR-2021-0317-2305, -2326, -2399, -2428, and -2483.
\545\ EPA-HQ-OAR-2021-0317-2483.
\546\ ``DTE Energy Rod Packing Evaluation and Replacement
Program,'' U.S. EPA 2019 Natural Gas STAR & Methane Challenge
Workshop (November 2019).
\547\ CARB. ``[Regulation for Greenhouse Gas Emission Standards
for Crude Oil and Natural Gas Facilities.]'' Oil and Gas Final
Regulation Order (ca.gov).
\548\ EPA, Oil and Natural Gas Sector: Emission Standards for
New, Reconstructed, and Modified Sources and Emissions Guidelines
for Existing Sources: Oil and Natural Gas Sector Climate Review,
Background TSD for the Proposed New Source Performance Standards
(NSPS) and Emissions Guidelines (EG) (October 2021), Document ID
No.-HQ-OAR-2021-0317-0166 (hereinafter ``2021 Background TSD'').
---------------------------------------------------------------------------
Several commenters \549\ expressed concern that, as an emissions
standard, the proposed rod packing requirements are unworkable. They
explained that operators would be forced to decide between continuing
to operate out of compliance until a maintenance shutdown can be
scheduled or shutting down the compressor immediately to conduct the
repair and venting or flaring gas that can no longer be compressed and
transported during the unscheduled shutdown. The commenters added that
a forced shutdown would likely result in significantly more emissions
than continuing to operate until the next scheduled maintenance
shutdown. For systems that are at capacity, shifting the incoming gas
to another station is not a feasible or reliable option, resulting in
additional flaring and venting, which is magnified given the time it
takes to have producers shut in wells. According to one of the
commenters,\550\ the December 2022 Supplemental Proposal made an
incorrect assumption that the gas can simply be rerouted to other
natural gas compression facilities, but the commenter explained that
often that is not a possibility as piping is not in place to bypass a
facility, or there may not be an alternative facility available.
Another commenter \551\ added that while it is true that flow can be
measured, it is not technically or economically practicable to install
measurement systems that would assure compliance with a numeric
emissions limitation. See CAA section 111(h)(2)(B).
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\549\ EPA-HQ-OAR-2021-0317-2305, -2399, and -2428.
\550\ EPA-HQ-OAR-2021-0317-2305.
\551\ EPA-HQ-OAR-2021-0317-2428.
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A couple of commenters \552\ suggested that under a work practice
framework (which they state to be the only supported option), companies
be required to complete a corrective action within 720 hours of
operation (equivalent to 30 days) and allow for delay of repair,
similar to that for leak monitoring programs, of up to 2 years if
repair goes beyond the replacement of rod packing. The commenters noted
that exceeding the vent rate threshold after the time for corrective
action would be a deviation, but exceeding the vent rate within the
time allotted to correct would not.
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\552\ EPA-HQ-OAR-2021-0317-2305 and -2399.
---------------------------------------------------------------------------
One commenter \553\ stated that the EPA proposed to establish the 2
scfm flowrate as a not-to-exceed standard of performance, such that a
violation occurs if flow rate exceeds that value (87 FR 74797). In
doing so, the commenter suggested, the EPA fundamentally misconstrued
the manufacturers' recommendations (on which the flow rate is based).
In practice, the commenter explained, exceeding a manufacturer-
recommended flow rate is an indication that a repair should be made.
Exceeding that rate does not necessarily compromise operability of the
unit and, in fact, the values are selected to allow continued operation
for the period necessary to arrange for needed repairs to be made.
According to the commenter, the EPA without explanation proposed to
transform what in practice constitutes an action level into a
regulatory cap that cannot be exceeded without the prospect of
incurring a violation. The commenter argued that the EPA's proposal is
at odds with the facts and is an unreasonable reinterpretation of
standard maintenance practices.
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\553\ EPA-HQ-OAR-2021-0317-2428.
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The commenter \554\ argued that, if the EPA is intent on setting a
numeric standard of performance, the value must be well above the 2
scfm that the EPA believes to be the standard manufacturer
recommendations. They asserted that the value must accommodate
operations for a reasonable and potentially significant period of time
that may be needed to accomplish needed repairs. If the EPA takes this
path, the commenter contended that a reproposal would be necessary so
that commenters would know the newly proposed value, understand the
EPA's rationale, and have an opportunity to submit comments on the
record.
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\554\ EPA-HQ-OAR-2021-0317-2428.
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Response: The EPA acknowledges that the record for the 2 scfm
performance volumetric flow rate standard supports a work practice
standard and not a numeric standard. The EPA has determined that, for
reciprocating compressors, the application of a measurement methodology
to reciprocating compressors is not always practicable due to
technological or economic limitations. It is not practicable here for
an exceedance of the 2 scfm per cylinder volumetric flow rate to be a
violation when the annual performance-based flow rate reflects whether
there are performance issues with the rod packing that need to be
addressed in order to take action to minimize the emissions/leak. This
is similar to the basis and monitoring established for fugitive
emissions component requirements, where a leak based on periodic
monitoring triggers requirements to minimize the emissions/leak.
In the final rule, therefore, the 2 scfm performance-based
volumetric flow rate standard will be implemented as a work practice
standard and not as a numeric limit where an exceedance would be
considered a violation. As such, the volumetric flow rate of 2 scfm is
an action level that, if exceeded, triggers the action of repairing or
replacing the rod packing and is not a numerical limit. Specifically,
the final rule for reducing GHGs and VOC from new reciprocating
compressors requires repair or replacement of the rod packing where,
based on the required monitoring, the performance-based volumetric flow
rate standard is exceeded. If the volumetric emissions measurement of
the reciprocating compressor rod packing has a flow rate greater than 2
scfm (in operating or standby pressurized mode) or a combined rod
packing flow rate greater than the number of compressor cylinders
multiplied by 2 scfm, an owner or operator must repair or replace the
reciprocating compressor rod packing within 30 calendar days after the
date of the volumetric emissions measurement. Delay-of-repair
provisions under a work practice standard appropriately recognize that
the unit must be shut down to effect any such repair and replacement
and that parts availability and supply chain disruptions may be
relevant to how quickly the repair or replacement can be made. As such,
the final rule allows for a delay of repair if the repair or
replacement would require a vent blowdown, or it would otherwise be
infeasible or unsafe, until the next process unit shutdown--
specifically, if the repair or replacement (1) is technically
infeasible, (2) would require a vent blowdown, (3) would require a
process unit or facility shutdown, (4) needs to be delayed because
parts or materials are unavailable, or (5) would be unsafe to repair
during operation of the unit. In cases where there is a need for delay
of repair, the repair must be completed during the next scheduled
process unit or facility shutdown for maintenance, after a scheduled
vent blowdown, or within 2 years, whichever is earliest.
[[Page 16971]]
2. Rod Packing Changeout Schedule-Based Approach
Comment: Several commenters \555\ expressed concern over the EPA's
changing in the proposed NSPS OOOOb and EG OOOOc the requirements that
the commenters have been meeting under NSPS OOOOa to replace rod
packing on a fixed schedule. The commenters noted that given the
uncertainties of the assumptions underlying the BSER evaluations for
the two options (the rod packing changeout schedule-based approach and
monitoring limit approach) and given that the cost effectiveness values
of the two options are very close, they urged the EPA to provide
flexibility to affected facilities by adopting both standards as BSER
alternatives with the operator selecting their preferred approach.
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\555\ EPA-HQ-OAR-2021-0317-2227, -2258, -2282, -2298, -2326, -
2366, -2399, -2428, and -2483.
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According to one commenter,\556\ retaining the schedule-based
approach is warranted because that compliance option has been
implemented not only at NSPS OOOOa facilities but also through state
regulations and voluntary actions by companies. The commenter added
that the prescribed maintenance schedule is also an EPA-approved best
management practice for the voluntary Methane Challenge program. Due to
these EPA decisions, the commenter reported, many companies have
``built out'' reciprocating compressors rod packing maintenance
programs using scheduled maintenance, including existing compressors
not subject to the Federal mandate or state rules. The commenter
expressed that it is critical that these existing and successful
company programs not be supplanted by different requirements in NSPS
OOOOb and EG OOOOc.
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\556\ EPA-HQ-OAR-2021-0317-2366.
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Several commenters noted specific suggestions with respect to a
fixed schedule:
Several commenters \557\ requested that the EPA allow rod
packing replacement every 8,760 operating hours.
---------------------------------------------------------------------------
\557\ EPA-HQ-OAR-2021-0317-2258, -2298, and -2326.
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One commenter \558\ requested that the EPA allow
replacement annually or 8,760 hours (whichever comes first), which is
similar in approach but more frequent than the current requirements in
NSPS OOOO and NSPS OOOOa.
---------------------------------------------------------------------------
\558\ EPA-HQ-OAR-2021-0317-2428.
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Another commenter \559\ requested retaining the NSPS OOOOa
approach, requiring the replacement of rod packing every 3 years or
26,000 hours of operation (if operating hours are monitored).
---------------------------------------------------------------------------
\559\ EPA-HQ-OAR-2021-0317-2366.
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Several commenters \560\ requested that the EPA specify that where
operators choose to replace rod packing on a fixed schedule, they are
not required to measure volumetric flow rates.
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\560\ EPA-HQ-OAR-2021-0317-2227, -2298, -2326, -2399, and -2428.
---------------------------------------------------------------------------
Response: The contention by commenters that requiring the
performance-based volumetric flow rate monitoring would result in
owners or operators having to do more rod packing changeouts on
reciprocating compressors and/or would lead to an increase in baseline
maintenance/piston rod replacement to ensure proper operation of the
compressor further supports requiring the performance-based volumetric
flow rate monitoring standard over a fixed-schedule rod packing
changeout every 26,000 hours to mitigate emissions. This is also
consistent with the EPA's BSER determination that greater and more-
efficient emissions reductions would be achieved by implementing an
annual performance-based 2 scfm volumetric flow rate monitoring
standard. For these reasons, the EPA is not including the 26,000-hour,
fixed-schedule rod packing replacement as an alternative option to the
condition-based 2 scfm volumetric flow rate monitoring option. However,
under the final rule, the EPA has clarified that an owner or operator
would be allowed to replace rod packing on or before 8,760 hours of
operation after last rod packing replacement or monitoring and forgo
the need to conduct the required performance-based volumetric flow rate
monitoring. The final rule also specifies that owners or operators are
allowed to forgo volumetric flow rate measurements if they replace the
rod packing at or before 8,760 hours of operation after the last rod
packing replacement or flow rate measurement.
The final rule has also been revised to state that the first
volumetric flow rate measurements from a reciprocating compressor
affected facility are to be conducted at or before 8,760 hours of
operation after the effective date of the final rule (i.e., 60 days
after publication of the final rule in the Federal Register), or at or
before 8,760 hours of operation after the last rod packing replacement,
or at or before 8,760 hours of operation after startup, whichever is
later. Subsequent volumetric flow rate measurements from your
reciprocating compressor are to be conducted at or before 8,760 hours
of operation after the previous measurement that demonstrates
compliance with the 2 scfm volumetric flow rate, or at or before 8,760
hours of operation after the last rod packing replacement, whichever is
later. As an alternative to conducting required volumetric flow rate
measurements, the final rule allows an owner or operator the option to
comply by replacing the rod packing at or before 8,760 hours of
operation after the effective date of the final rule, at or before
8,760 hours of operation after the previous flow rate measurement, or
at or before 8,760 hours of operation after the date of the most recent
compressor rod packing replacement, whichever is later.
3. Clarification That the Standard Is Based on a Per-Cylinder Basis
Comment: Several commenters \561\ requested clarification that the
volumetric standard applies to each rod packing (or throw) or set of
packing and not to the entire compressor and that the rule text clearly
addresses manifolded vents on a combined basis. The commenters cite the
precedent set by the CARB where reciprocating compressors in California
are restricted to 2 scfm per rod packing, and not per compressor, as
set forth in 17 CCR section 95668(c)(4)(D), Greenhouse Gas Emission
Standards for Crude Oil and Natural Gas Facilities (allowing for ``a
combined rod packing or seal emission flow rate greater than the number
of compression cylinders multiplied by two (2) scfm'') which states:
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\561\ EPA-HQ-OAR-2021-0317-2258, -2282, -2305, -2326, -2366, -
2391, -2399, -2428, and -2483.
(6) with a rod packing or seal with a measured emission flow
rate greater than two (2) standard cubic feet per minute (scfm), or
a combined rod packing or seal emission flow rate greater than the
---------------------------------------------------------------------------
number of compression cylinders multiplied by two (2) scfm.
These commenters generally stated that this approach makes sense
and is consistent with the proposed BSER from the November 2021
Proposal. In addition, the EPA based its proposal to measure the flow
rate of each cylinder on volumetric emission factors used in the 1996
EPA/GRI report quantifying methane emissions from the U.S. natural gas
industry--which the EPA notes are per cylinder. The commenters
elaborated on why they believed that this was the EPA's intent and
several commenters provided in-line regulatory text changes where they
believed the clarification was needed.
Response: The EPA agrees that the basis and intent of the standard
is that it be applied on a per-cylinder basis and that clarity was
needed in both the
[[Page 16972]]
NSPS OOOOb and EG OOOOc regulatory text. The final rule regulatory text
has been revised to make this clear as suggested by the commenters.
Specifically, clarifying changes have been made to: 40 CFR 60.5385b,
paragraphs (a) through (c) of NSPS OOOOb; and 40 CFR 60.5393c,
paragraphs (a) through (c) of EG OOOOc.
4. Routing to Process or Control Device
In the December 2022 Supplemental Proposal, the EPA proposed to
allow an alternative reciprocating compliance option of routing rod
packing emissions to a process via a CVS. Several commenters \562\
requested that they also have the option to use proven add-on controls,
such as an existing combustor or flare, in addition to routing to a
process. A commenter explained that such options may be key for
existing units and units that are modified or reconstructed.
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\562\ EPA-HQ-OAR-2021-0317-2258, -2305, -2399, and -2428.
---------------------------------------------------------------------------
Comment: A few commenters \563\ provided several reasons for why it
may not always be feasible to route rod packing vents back to the
process:
---------------------------------------------------------------------------
\563\ EPA-HQ-OAR-2021-0317-2305, -2399, and -2428.
---------------------------------------------------------------------------
Depending on the pressure differential between nearly
ambient rod packing vents and pressurized piping, substantial
horsepower may be required to achieve capture.
Recompression designs require substantial horsepower and
could require gas engines of variable horsepower to achieve the
recompression, negating some of the emissions reductions this rule
seeks to achieve.
Currently available rod packing capture systems attempted
by Williams and others in the industry have performed poorly or are
ineffective in certain applications or configurations.
Rod packing vents are essentially at ambient pressure,
creating a situation where oxygen (O2) could be introduced
into the process gas, leading to safety concerns.
The gas quality in the rod packing vents may not be
compatible with the only technically feasible location in the process,
based on pressure differentials, for the gas to be routed. For example,
if the gas in the compressor is sour gas, but the only technically
feasible place for the gas to be absorbed in the process is the fuel
gas system, the sour gas is often not a good candidate for fuel gas use
due to the detrimental effect on components.
According to one commenter,\564\ currently available rod packing
capture systems that have been attempted by the commenter and their
members have not performed as intended and, in some applications, have
not worked at all. They explained that even if these systems were as
effective as advertised, timing is a significant concern as the supply
is not currently available to meet demand. The commenter recommended
that where rod packing vents are routed to a control device, the EPA
could require that the flow be measured every 26,000 hours of
operation. The commenter noted that this would ensure that rod packing
is appropriately maintained while overall emissions are greatly
reduced.
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\564\ EPA-HQ-OAR-2021-0317-2399.
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Another commenter \565\ provided that the incremental benefit
achieved between monitoring and subsequent repair (if applicable)
versus capturing and venting to a control device that achieves 95
percent destruction efficiency has not been substantiated by the EPA
within its BSER analysis. This, according to the commenter, is
especially true for any compressor that already is designed and
configured to route rod packing emissions to a flare or other
combustion device.
---------------------------------------------------------------------------
\565\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------
Response: The EPA evaluated allowing the alternative option of
routing to a control device that achieves 95 percent control of
emissions and has determined that it would be acceptable as an
alternative control option. The volumetric 2 scfm performance-based
volumetric flow rate standard is estimated to reduce VOC and methane
emissions by approximately 92 percent, and a flow rate of 40 scfm
reduced by 95 percent would meet a 2 scfm flow rate. As a result, we
have concluded that allowing for routing to a control device achieving
a 95 percent reduction in VOC and methane emissions has merit and would
provide equivalent or better emissions reduction compared to BSER.
Accordingly, we have included this measure as an alternative option for
compliance in the final rule.
5. Applicability of Requirements to Compressors Located at Centralized
Production Facilities
The EPA proposed (86 FR 63184-85, November 15, 2021) to define
centralized production facilities separately from well sites because
the numbers and sizes of equipment, particularly reciprocating and
centrifugal compressors, are larger than for standalone well sites,
which would not be included in the proposed definition of ``centralized
production facilities.'' In the 2016 NSPS OOOOa, the EPA exempted
reciprocating and centrifugal compressors located at well sites from
the applicable compressor standards. Reciprocating compressors that are
located at well sites are not affected facilities under the 2016 NSPS
OOOOa. The EPA previously excluded them because the EPA found the cost
of control to be unreasonable. 81 FR 35878. However, we believed the
definition of ``well site'' in NSPS OOOOa may have caused confusion
regarding whether reciprocating compressors located at centralized
production facilities were also exempt from the standards, which was
not our intent.
To clarify our intent, we proposed to define centralized production
facility as follows in the December 2022 Supplemental Proposal:
Centralized production facility means one or more storage
vessels and all equipment at a single surface site used to gather,
for the purpose of sale or processing to sell, crude oil,
condensate, produced water, or intermediate hydrocarbon liquid from
one or more offsite natural gas or oil production wells. This
equipment includes, but is not limited to, equipment used for
storage, separation, treating, dehydration, artificial lift,
combustion, compression, pumping, metering, monitoring, and
flowline. Process vessels and process tanks are not considered
storage vessels or storage tanks. A centralized production facility
is located upstream of the natural gas processing plant or the crude
oil pipeline breakout station and is a part of producing operations.
Additionally, we proposed to define the affected facility as:
(c) Each reciprocating compressor affected facility, which is a
single reciprocating compressor. A reciprocating compressor located
at a well site is not an affected facility under this subpart. A
reciprocating compressor located at a centralized production
facility is an affected facility under this subpart.
For purposes of analyses, we proposed to determine that it was
appropriate to apply the same emission factors to reciprocating
compressors located at centralized production facilities as those used
for reciprocating compressors at gathering and boosting compressor
stations. Given the results of that analysis, the EPA proposed to apply
the proposed NSPS OOOOb requirements to reciprocating compressors
located at centralized production facilities. At that time, the EPA
proposed a new definition for centralized production facilities to
distinguish compressors at standalone well sites where the EPA has
determined that the standard should not apply.
[[Page 16973]]
Comment: One commenter \566\ requested that the EPA clarify the
applicability of compressor standards to well sites. The commenter
stated that the definition proposed for ``centralized production
facility'' may extend applicability to compressors located at well
sites, which have historically been exempt from the compressor
standards. The commenter noted that the EPA had not updated its cost
analyses with new information with respect to well sites and believed
that extending applicability to well sites was not the EPA's intent.
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\566\ EPA-HQ-OAR-2021-0317-0808.
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Another commenter \567\ urged the EPA to keep the current
compressor exemptions shown in both subparts NSPS OOOO and NSPS OOOOa.
The commenter specifically requests that the EPA maintain that each
compressor ``located at a well site, or an adjacent well site and
servicing more than one well site, is not an affected facility.''
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\567\ EPA-HQ-OAR-2021-0317-0923.
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Conversely, another commenter \568\ supported the EPA's proposed
definition of a centralized production facility and supported the
extension of compressor standards to these sites. While the GHGI does
not contain data on the number of compressors in the production
segment, the commenter reported that they analyzed data submitted in
response to the EPA's 2016 ICR to assess the number of compressors
across different facility types in the production segment. While the
ICR data are not a full inventory, the commenter contended that the ICR
illustrates that there are a significant number of compressors utilized
in the production segment, with most reciprocating compressors located
at centralized production facilities.
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\568\ EPA-HQ-OAR-2021-0317-0844.
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A couple of commenters \569\ recommended that the EPA continue the
exemption of each centrifugal and reciprocating compressor ``located at
a well site, or an adjacent well site and servicing more than one well
site'' as provided in both 40 CFR part 60, subpart OOOO, and 40 CFR
part 60, subpart OOOOa. The commenters explained that well operators
visit and service these wells and associated compressors daily to
inspect for proper operation, to inspect for leaks, and to conduct
maintenance and repairs activities. Any necessary repairs are
implemented as soon as possible to avoid product loss and to maximize
profit returns. If the EPA wishes to propose monitoring for well site
compressors, the commenters recommended that the EPA allow the more
feasible and cost-effective monthly AVO inspection and documentation,
similar to the requirements allowed under 40 CFR 60.5416a.
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\569\ EPA-HQ-OAR-2021-0317-0465 and -0946.
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Some commenters \570\ expressed that applying the proposed
monitoring requirements to reciprocating compressors located at
``centralized production facilities'' may be beneficial in certain
operations and where larger oil and gas operators may have the
resources and equipment to monitor those emissions. However, they
suggested that it should be an option/alternative and not a mandatory
requirement, as it may unnecessarily create additional burdens and
costs for smaller operators that send production from several marginal/
low production wells to a ``centralized production facility.'' These
commenters reported that, for marginal/low production well operators,
centralized production facilities may be more cost-efficient than
having equipment at each well site and this practice reduces overall
the environmental footprint of the operation. The commenters suggested
that it would be an unnecessary additional cost on small businesses and
that it disincentivizes the use of centralized production facilities in
this scenario. The commenters requested that the EPA remove this
requirement for marginal/low production wells that send production to
centralized production facilities.
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\570\ EPA-HQ-OAR-2021-0317-0810 and -0814.
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Response: Most of these comments were based on the November 2021
Proposal prior to the EPA's December 2022 Supplemental Proposal
definitions cited earlier in this document for a reciprocating
compressor affected facility and centralized production facility. The
EPA has finalized the December 2022 Supplemental Proposal's proposed
requirements related to the definitions of the reciprocating compressor
affected facility and centralized production facility. Some of the
commenters suggested that, by extending requirements to apply to
centralized production facilities, the EPA was extending requirements
to well sites where reciprocating compressors were not previously
regulated. That interpretation confirms that clarity was needed. Based
on the proposed definition of the reciprocating compressor affected
facility, in addition to the proposed definition for centralized
production facility as proposed in the December 2022 Supplemental
Proposal, we believe that we clarified our intent. That intent is that
reciprocating compressors located at well sites are not subject to
requirements. However, reciprocating compressors located at centralized
production facilities that consist of equipment at a single surface
site used to gather, for the purpose of sale or processing to sell,
crude oil, condensate, produced water, or intermediate hydrocarbon
liquid from one or more offsite natural gas or oil production wells
(including reciprocating compressors) are subject to reciprocating
compressor requirements.
In response to the commenters that noted that small operators of
marginal/low production wells often send production from several
marginal/low production wells to a ``centralized production facility''
because it is uneconomic to have equipment at each well site, the EPA
does not understand why they would no longer be incentivized not to
have equipment at each well site. The commenters did not provide
sufficient information as to why an owner or operator of reciprocating
compressors at centralized production facilities would not continue
having reciprocating compressors at centralized production facilities
because they would be subject to requirements in lieu of having
equipment at each well site.
J. Storage Vessels
In section X.J of this document the final NSPS OOOOb and EG OOOOc
requirements for storage vessels are summarized. In the November 2021
Proposal, the EPA proposed that for NSPS OOOOb, a storage vessel
affected facility is a tank battery, which can be a single tank, with
the potential to emit equal to or greater 6 tpy VOC or 20 tpy methane.
The EPA proposed that an owner or operator of a tank battery must
determine the potential for VOC and methane emissions using a
``generally acceptable model or calculation methodology'' that accounts
for flashing, working, and breathing losses. The EPA proposed that the
determination may take into account requirements under a ``legally and
practicably enforceable limit'' in an operating permit or other
requirement established under a Federal, state, local, or Tribal
authority and proposed specific elements as to what constitutes a
``legally and practicably enforceable limit.'' The elements included: a
quantitative production limit and quantitative operational limit(s) for
the equipment, or quantitative operational limits for the equipment; an
averaging time period for the production limit, if a production-based
limit is used, that is equal to or less than 30 days; established
parametric limits for the
[[Page 16974]]
production and/or operational limit(s), and where a control device is
used to achieve an operational limit, an initial compliance
demonstration (i.e., performance test) for the control device that
establishes the parametric limits; ongoing monitoring of the parametric
limits that demonstrates continuous compliance with the production and/
or operational limit(s); and recordkeeping and reporting by the owner
or operator that demonstrates continuous compliance with the limit(s).
In the November 2021 Proposal, the EPA proposed that a tank battery is
a group of storage vessels which are physically adjacent and that
receive fluids from the same source or that are manifolded together for
liquid or vapor transfer. Regarding BSER, the EPA proposed that storage
vessel affected facilities must reduce emissions by 95 percent or
greater. The BSER analysis is unchanged from what was presented in the
November 2021 Proposal (see 86 FR 63199-201, section XII.B. Proposed
Standards for Storage Vessels). The EPA proposed similar requirements
for designated facilities under EG OOOOc, which have the potential to
emit greater than or equal to 20 tpy methane.
In the November 2021 Proposal, the EPA proposed specific actions
that would constitute ``modification'' of an existing tank battery for
purposes of determining whether NSPS OOOOb is triggered (if the
potential methane or VOC emissions are determined to be above the
applicability threshold). Some of the actions that could trigger
modification are actions that occur at the well site, such as
refracturing a well or adding a new well that sends these liquids to
the tank battery. The EPA did not propose specific provisions for
reconstruction in the November 2021 Proposal.
In the December 2022 Supplemental Proposal, the EPA proposed a
revised definition of storage vessel affected facility. In response to
comments on the November 2021 Proposal, the EPA removed the criterion
that the storage vessels in the tank battery are physically adjacent
and the criterion that the vapor lines are manifolded together.
In the December 2022 Supplemental Proposal, the EPA retained the
same provisions for ``legally and practicably enforceable'' criteria
which were proposed in the November 2021 Proposal. Regarding
modification and reconstruction, to address the resultant emissions at
a compressor station or onshore natural gas processing plant receiving
those liquids, where the emissions have already been accounted for in
the permit, in the December 2022 Supplemental Proposal, the EPA
proposed that for compressor stations or onshore natural gas processing
plants, the modification trigger occurs when the tank battery receives
additional fluids which cumulatively exceed the throughput used in the
most recent determination for VOC or methane emissions (e.g., permit)
based on the design capacity of such tank battery. In addition, the
December 2022 Supplemental Proposal retained the November 2021 criteria
that a modification is also triggered when a storage vessel is added to
an existing tank battery and/or one or more storage vessels are
replaced such that the cumulative storage capacity of the existing tank
battery increases. In the December 2022 Supplemental Proposal, the EPA
proposed two actions which constitute reconstruction: over half of the
storage tanks are replaced in an existing tank battery that consists of
more than one storage vessel; or the provisions of 40 CFR 60.15 are met
for the existing tank battery that consists of a single storage vessel.
The EPA received significant comments on the definition of legally
and practicably enforceable limits, modification, and reconstruction.
This section of this preamble presents a summary of those significant
comments and the EPA's response to those comments. These comments and
the EPA's responses to these comments apply to the standards proposed
in both the NSPS OOOOb and EG OOOOc. The EPA's full response to
comments on the November 2021 Proposal and December 2022 Supplemental
Proposal, including any comments not discussed in this preamble, can be
found in the EPA's RTC document for the final rule.\571\
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\571\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
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1. Legally and Practicably Enforceable Limits
As explained in the preamble to the November 2021 Proposal (86 FR
63201), from its years of experience of reviewing permits of legally
and practicably enforceable limits, the EPA has long been aware that
many owners and operators claim that storage vessels are not affected
facilities under 40 CFR 60.5365(e) and 40 CFR 60.5365a(e) by alleging
that the VOC emissions are less than 6 tpy. Since promulgation of NSPS
OOOO in 2012, the EPA has expended extensive resources in enforcement
actions nationwide to review permits, general permits, and permits-by-
rule for storage vessels and found that, in nearly in all cases, across
nearly 400 storage vessels, these permits or other requirements are not
legally and practicably enforceable. In nationwide ongoing enforcement
actions, the EPA continues to find permits or permits-by-rule that are
not legally and practicably enforceable. The EPA has repeatedly
expressed this concern in prior rulemaking actions. See, e.g., 83 FR
52085 and 85 FR 57425. The EPA believes that the new criteria being
finalized in this action will help to ensure that storage tank
batteries that rely on legally and practicably enforceable limits to
claim nonapplicability of NSPS OOOOb or EG OOOOc indeed have potential
emissions below the relevant applicability threshold(s).
As discussed in this section, several commenters failed to
acknowledge the EPA's concern, claiming that it does not exist; some
commenters insist that the criteria are unnecessary but do not offer
any alternative to address the EPA's concern. The EPA has provided
examples of limits that are not legally and practicably enforceable
\572\ later in this section and is finalizing the criteria as proposed
to ensure that, where an owner and operator is taking into account a
legally and practicably enforceable limit in determining the
applicability of the storage vessels standards under OOOOb or EG OOOOc,
those limits actually limit and maintain potential emissions below the
rule's applicability thresholds under NSPS OOOOb or designated
facilities under EG OOOOc. The EPA further notes that including legally
and practicably enforceable limits is an option, not a requirement, in
determining storage vessel affected facility/designated facility status
under NSPS OOOOb and EG OOOOc. The EPA will continue to evaluate the
use of permit limits in determining the applicability of the standards
for storage vessels pursuant to the criteria finalized in this action
to see whether the EPA's concern is fully addressed. If concerns about
the enforceability of the applicability criteria for the storage vessel
standards remain upon implementation of the revised regulatory
provision, the EPA may initiate further rulemaking in the future.
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\572\ See the RTC, volume 2, chapter 13, in EPA-HQ-OAR-2021-
0317.
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[[Page 16975]]
a. Need for a National Rulemaking To Address LPE Across CAA Programs
Comment: Several commenters \573\ urged the EPA to defer final
action on the proposed definition of legally and practicably
enforceable limits until such time as the Agency undertakes a national
rulemaking. A few of the commenters \574\ pointed out the potential for
inconsistencies among the various CAA programs that similarly require
legally and practicably enforceable limits to determine applicability
(e.g., an effective emissions limit used to avoid major NSR permitting
might, at the same time, not be effective for purposes of the NSPS
OOOOb and/or EG OOOOc storage vessel standards). One commenter \575\
opined that what constitutes an acceptable and effective ``legally and
practicably enforceable limit'' has been an open question since the
mid-l990s, when the prior ``Federal enforceability'' requirement was
remanded or vacated across the EPA's programs.\576\ Similarly the
commenter \577\ believed that these proposed provisions of the NSPS
OOOOb and EG OOOOc were driven by a July 2021 report from the EPA
Inspector General that criticized the EPA for not responding to these
judicial decisions.\578\ The commenter stated that the EPA's announced
plan to establish national rules for effective limits on PTE and to do
so in the relative near future \579\ lends strong additional support to
the view that the EPA should not address these issues in a premature
and piecemeal fashion. Another commenter \580\ stated that a national
rulemaking would avoid many potential inconsistencies and uncertainties
across CAA programs and would allow the EPA to establish reasonable
transition rules so that affected sources and states have time to
revise existing emissions limitations as needed to meet the new
effectiveness criteria.
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\573\ EPA-HQ-OAR-2021-0317-2298, -2301, -2326, and -2428.
\574\ EPA-HQ-OAR-2021-0317-2428, -2326, and -2298.
\575\ EPA-HQ-OAR-2021-0317-2298.
\576\ National Mining Ass 'n v. EPA, 59 F.3d 1351 (D.C. Cir.
1995); Chemical Mfrs. Ass 'n v. EPA, 70 F.3d 637 (D.C. Cir. 1995);
Clean Air Implementation Project v. EPA, 1996 WL 393118 (D.C. Cir.
1996).
\577\ EPA-HQ-OAR-2021-0317-2428.
\578\ EPA Should Conduct More Oversight of Synthetic-Minor-
Source Permitting to Assure Permits Adhere to EPA Guidance, Report
No. 21-P-0175, memorandum from Sean W. O'Donnell to Joseph Goffman
(July 8, 2021) at 17.
\579\ The commenter stated that the EPA intends to issue
national guidance by October 2023.
\580\ EPA-HQ-OAR-2021-0317-2326.
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Response: The final rule includes ``legally and practicably
enforceable'' criteria specific to oil and gas storage vessels. The EPA
is choosing to add regulatory certainty to describe legally and
practicably enforceable emissions limitations to address a common
problem that the EPA has observed over the past decade through
implementation of NSPS OOOO and OOOOa. Specifically, the EPA has
identified problems with permits that states and owners and operators
have characterized as legally and practicably enforceable. As discussed
in the November 2021 Proposal (see 86 FR 63201) and elaborated in
section XI.J.1 of this document, when the EPA has reviewed the limits
considered by facilities as legally and practicably enforceable, the
limits are often of such a general nature as to be unenforceable or
otherwise lack measures to ensure the required emissions reduction.
Unless the compliance with the permit limit can be determined, and the
permit limit achieves the desired emissions reductions, they are not
meaningful requirements. Excerpts of specific permits \581\ that the
EPA has reviewed and determined to be lacking legally and practicably
enforceable limits include:
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\581\ The EPA is not able to identify the permittees due to
ongoing investigations or enforcement actions.
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Permit 1--Applicable Emissions Limitations or Control Measures
In order to comply with the tons-per-month emissions
limit, utilize one or more of the following controls: Use of add-on
control (vapor recovery, flare, or equivalent) to control emissions
from storage vessels as needed to comply with the annual VOC emissions
limitations.
The permittee accepts a voluntarily limit to restrict the
potential VOC emissions from each storage vessel to less than 6 tpy.
In Permit 1, the control device is not specified and the permit
terms do not specify a destruction rate efficiency, combustion rate, or
availability for a VRU. The provision also does not specify emissions
testing, operational parameter monitoring, inspection requirements, or
recordkeeping or reporting requirements for the add-on control.
Additionally, the terms ``voluntarily limit'' in the second provision
indicate that controlling emissions below 6 tpy of VOCs is not a
requirement.
Permit 2--Combustor/Flare Requirements
All exhaust gas/vapors from the oil storage tanks must be
routed to the operating combustor/flare.
The combustor/flare shall operate with no visible
emissions.
Visual determination of smoke emissions from flares shall
be conducted according to 40 CFR 60, appendix A, EPA Method 22.
In Permit 2, a destruction rate efficiency of 95 percent or greater
is not specified. There is no testing requirement for the control
device, no continuous pilot light monitoring or inspection requirement,
no indication of how frequently EPA Method 22 inspections must be
conducted, and no recordkeeping or reporting requirements. Both Permit
1 and Permit 2 demonstrate provisions from permits that do not have
operational or parametric limits and therefore that the EPA has
determined not to be legally and practicably enforceable and thus
adequate to ensure that the storage vessels are below the applicability
thresholds for the applicable standards.
The EPA disagrees that it should delay establishing the criteria
for legally and practicably enforceable limits for purposes of
determining storage vessel affected facility/designated facility status
under NSPS OOOOb and EG OOOOc until such time as the Agency undertakes
a national rulemaking on legally and practicably enforceable limits for
other CAA provisions. The criteria in this final rule are unique and
specifically tailored toward their intended purpose, which is to ensure
that limits that are being taken into account in determining NSPS OOOOb
and EG OOOOc applicability do in fact cap the potential emissions of a
tank battery below the relevant applicability threshold and are
enforceable. There is no reason why the EPA needs to wait to address
this long-observed issue with respect to this emission source.
Moreover, general criteria for legally and practicably enforceable
limits would not necessarily provide the clarity and certainty that is
necessary to ensure that the issue observed in the implementation of
NSPS OOOO and OOOOa does not continue in the future in the
implementation of NSPS OOOOb and EG OOOOc. Nor would such general
criteria be timely, given the NSPS OOOOb standards will apply upon the
effective date of this action and states will need to begin developing
state plans pursuant to EG OOOOc. Finalizing the criteria now will
provide states and sources specificity and certainty as to what the EPA
considers legally and practicably enforceable for purposes of
determining potential tank battery emissions under NSSP OOOOb or a
state or Federal plan implementing EG OOOOc. The EPA believes that this
level of specificity and certainty will
[[Page 16976]]
serve to guide states and sources in establishing permit limits for
tank batteries that could be used in determining NSPS OOOOb/EG OOOOc
applicability.
b. LPE and Delegated Authorities
Comment: The EPA received multiple comments \582\ regarding the
interplay with delegated authorities other than the EPA, such as
concern that existing permits may not comply with the criteria proposed
by the EPA, how the criteria align with permit-by-rule or permits, and
the fact that many existing state permits lack methane limits.
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\582\ EPA-HQ-OAR-2021-0317-2298, -2301, -2221, -2254, -2428, -
2423, -2399, -2254, -2483, -2227, -2208, -2298, -2292, and -2202.
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Some commenters \583\ expressed concern with the proposed
definition for the term ``legally and practicably enforceable'' as it
relates to state emissions limits for ``storage vessel affected
facilities'' that limit their potential for VOC emissions below 6 tpy.
One commenter \584\ believed that in effect, if the EPA deems
applicable state standards not ``legally and practically enforceable,''
it would disregard the state limits and treat the storage vessels as
uncontrolled for purposes of Federal regulation.\585\ The commenter was
concerned that this proposal thus has the potential to create
substantial friction between the EPA and the states and could result in
many more facilities becoming subject to Federal emissions standards.
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\583\ EPA-HQ-OAR-2021-0317-2298, -2301, -2221, -2254, -2428, -
2423, -2399, -2254, -2483, -2227, and -2208.
\584\ EPA-HQ-OAR-2021-0317-2301.
\585\ See 86 FR at 63202 (``Only those limits that include the
elements described [in the proposed definition] will be considered
`legally and practicably enforceable' for purposes of determining
the potential for VOC emissions from a single storage vessel or tank
battery, and thus applicability (or nonapplicability) of each single
storage vessel or tank battery as an affected facility under the
rule.'').
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Another commenter \586\ opined that where a rule contains an
emissions threshold under which a given piece of equipment is not
subject to the rule's requirements, it is fair and logical that the
equipment be considered outside of rule coverage where emissions
controls or limitations are in place to keep emissions below the
threshold, even though in an uncontrolled state the equipment is
capable of producing emissions above threshold levels. The commenter
was concerned that that an owner or operator would be unable to claim
the existence of legally and practicably enforceable limits or
throughput limitations keeping a storage vessel below the applicability
threshold if they are unable to coordinate with the applicable permit
authority to work out specific limits, monitoring requirements, and
recordkeeping that will ensure that any permitted emissions limit is
achieved. The commenter also pointed out that some programs do not have
minor source permitting programs allowing for inclusion of GHG
emissions. The commenter summarized that a permit limit is a permit
limit, and it is inconceivable that there is any Federal, state, or
local permit that does not carry with it the ability of the issuing
authority to ensure and enforce compliance if permit limits are
exceeded. The commenter stated that they recognize that reporting,
recordkeeping, and monitoring requirements will vary from permit to
permit, but that all permits ultimately must be complied with or
enforcement consequences from the issuing authority may follow. To the
commenter's knowledge, they stated, there is no permit that does not
contain consequences for violations.
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\586\ EPA-HQ-OAR-2021-0317-2221.
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Another commenter \587\ likewise was concerned that existing
permits in many states may not meet the criteria that the EPA is
proposing for legally and practicably enforceable permit terms and
believes that the proposed changes will require states to review and
revise countless permits and also may require states to engage in
rulemakings over and above the efforts states will be required to
initiate to implement these rules. The commenter stated that the EPA
has neither explained nor justified this policy change, as it must, and
should retract it. Another commenter \588\ stated that the proposed
criteria for legally and practicably enforceable limits provide no
additional benefit and pose several permitting problems.
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\587\ EPA-HQ-OAR-2021-0317-2423.
\588\ EPA-HQ-OAR-2021-0317-2428.
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Similarly, another commenter \589\ believed that states are much
better equipped to determine the appropriate methods for the specific
circumstances facing industries within their state and that process is
required under the EPA's regulations (when the states meet certain
conditions). The commenter was concerned that the proposed requirements
conflict with the approach used in both the title V and NSR/PSD
permitting programs. Under these programs, the commenter explained,
operators may rely on control requirements to limit their PTE that
would no longer be available under the proposed rule. In effect, the
commenter was concerned, the proposed rule would arbitrarily require
operators to have two different PTE calculations--one for title V and
NSR permitting and another for NSPS/EG under this rule. The commenter
stated that the definitions of ``potential to emit'' and ``federally
enforceable'' show that the EPA's own regulations provide states with
substantial latitude to establish ``legally enforceable procedures.''
The commenter cited to 40 CFR part 51 for the definition of ``potential
to emit'' \590\ and ``federally enforceable'' \591\ and concluded that
the TCEQ (Texas Commission on Environmental Quality) emissions limits,
established under its EPA-approved SIP, are by the EPA's own part 51
definitions, federally enforceable. The commenter further noted that
the EPA previously determined that the regulations and permits issued
by both the TCEQ and the NMED (New Mexico Environment Department) were
legally and practicably enforceable. The commenter also stated that in
the preamble to the proposed 2013 amendments to NSPS OOOO, the EPA
reviewed the regulations in several states to determine which states
already had storage tank control requirements for calculating PTE.
Based on its evaluation of these regulations, the commenter stated, the
EPA determined that several states already had legally and practicably
enforceable regulations, including both Texas and New Mexico, such that
the EPA could subtract the storage vessels in these states ``from the
overall count of storage vessels that would be subject to the final
rule.'' The commenter believed that the EPA's proposal to require a new
definition of ``legally and practicably enforceable'' substitutes its
own judgment as to what is legally and practicably enforceable when its
own regulations say that determination should be left to the states,
subject to the EPA review. This commenter \592\ and another commenter
\593\ suggested that the SIP review process is the appropriate
mechanism as opposed to attempting to
[[Page 16977]]
make changes in this regulation. The commenter \594\ believed that,
when given the opportunity to review the regulations of Texas and New
Mexico with regard to calculating PTE, the EPA already has determined
that those regulations were federally enforceable.
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\589\ EPA-HQ-OAR-2021-0317-2254.
\590\ ``Potential to emit is the maximum capacity of a
stationary source to emit a pollutant under its physical and
operational design. Any physical or operational limitation on the
capacity of the source to emit a pollutant, including air pollution
control equipment and restrictions on hours of operation or on the
type or amount of material combusted, stored, or processed, shall be
treated as part of its design only if the limitation or the effect
it would have on emissions is federally enforceable.'' See, e.g., 40
CFR 51.165(a)(1)(iii).
\591\ ``. . . all limitations and conditions which are
enforceable by the Administrator . . . [and] requirements within any
applicable State implementation plan . . .''. Id. at 40 CFR
51.165(a)(1)(xiv).
\592\ EPA-HQ-OAR-2021-0317-2254.
\593\ EPA-HQ-OAR-2021-0317-2399.
\594\ EPA-HQ-OAR-2021-0317-2254.
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Among other concerns, some commenters \595\ noted that sources do
not have methane limits in permits and that prohibiting the use of
permits-by-rule and general permits would impose enormous burdens on
sources and delegated state authorities, for which the proposal makes
no provision. One commenter \596\ was concerned that this prohibition
would have a cascading effect on title V determinations across numerous
sources, imposing substantial additional burdens and complexities on
sources and states. The commenter stated that if the EPA decides to
finalize the text, the EPA should recognize that sources in good faith
went to the regulator and obtained a permit under the applicable state
minor source program and thus, at a minimum, the commenter stated, the
EPA should provide flexibility by phasing in the requirement and
applying the new definition only when a source needs to apply for a new
or revised permit or a permit renewal. Moreover, crucially, for all
existing sources, the commenter stated that the EPA should be clear
that existing permits authorizing a source to operate remain fully
effective, pending state processing of new permits.
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\595\ EPA-HQ-OAR-2021-0317-2399 and -2428.
\596\ EPA-HQ-OAR-2021-0317-2399.
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Another commenter \597\ similarly believed that the proposed
revisions are inconsistent with the EPA's reliance on states to
administer the CAA with regard to title V and PSD. That is, the
commenter stated, the EPA allows states to establish emissions limits
for sites to keep their emissions below title V and PSD permitting
thresholds. Monitoring, recordkeeping, and reporting requirements in a
permit should be tailored to align with the level of authorization,
with minor sources having fewer requirements than major sources,
according to the commenter. The commenter recommended that for
streamlined permitting mechanisms, such as Permits by Rule in Texas,
the state agency would have to engage in rulemaking before operators
could rely on such permits for determining storage vessel and tank
battery PTE. Such rulemaking could take months to years, meaning that
operators cannot rely on legally and practicably enforceable limits
until those rule updates are finalized and effective, according to the
commenter.
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\597\ EPA-HQ-OAR-2021-0317-2428.
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Response: The EPA recognizes that current permits for NSPS OOOO and
OOOOa sources may not entirely meet the criteria that the EPA is
finalizing for legally and practicably enforceable limits for purposes
of NSPS OOOOb and EG OOOOc. The EPA disagrees, however, that the final
rule necessitates that all existing permits be rewritten. These
specific criteria do not retroactively apply to permit limits or other
requirements that owners and operators had previously relied upon in
determining NSPS OOOO or OOOOa applicability to their storage vessels.
The criteria will apply when determining NSPS OOOOb applicability to
new storage vessels, i.e., those for which construction,
reconstruction, or modification commenced after December 6, 2022, and
when determining applicability for existing storage vessels covered by
the yet-to-be-developed state plans implementing EG OOOOc. For new
storage vessels constructed, reconstructed, or modified before the
effective date of this final rule, to the extent their owners or
operators decided to obtain legally and practicably enforceable limits
to cap the potential emissions from their storage vessels below the
proposed NSPS OOOOb applicability thresholds, those owners or operators
were on notice of the EPA's proposed LPE criteria when obtaining such
limits. Accordingly, the EPA does not agree that it is necessary to
provide a transitional period for sources to obtain or revise permits
before applying the new LPE criteria for determining applicability of
the storage vessel standards under NSPS OOOOb or under future state
and/or Federal plans implementing EG OOOOc.
With regard to existing sources, the EPA notes that existing
permits for designated facilities will need to be reopened to include
legally and practicably enforceable methane emission limits to the
extent facilities want to take into account such limits in determining
storage vessel standards applicability. States that use permit-by-rule
or general permits have the discretion to evaluate at any time
(including now or as they develop their state plans to implement EG
OOOOc) whether to modify those rules to incorporate the new criteria
for legally and practicably enforceable limitations.
The EPA notes that for both new and existing sources, it is a
voluntary decision on the part of an owner or operator to obtain a
permit with ``legally and practicably enforceable'' criteria in order
to avoid having to comply with the applicable standard in NSPS OOOOb or
a state or Federal plan pursuant to EG OOOOc. A source may opt to
comply with the underlying rule when the potential for VOC or methane
emissions exceeds the relevant applicability thresholds. In the future,
the EPA may initiate further rulemaking to address this provision if
its implementation merits further regulatory action.
The EPA disagrees that the criteria the EPA is promulgating
conflict with other CAA programs, such as title V and NSR programs. The
EPA cannot understand how more specific criteria for a specific purpose
within NSPS OOOOb can undermine compliance with title V and NSR
permits, and the commenter did not provide specific examples that the
EPA could review. Further, while the LPE criteria being finalized here
may be more stringent than what states are currently using for other
contexts, the commenter has not identified any direct conflict that
would prevent the commenter from meeting the criteria in other
programs, as more stringent criteria can be used to demonstrate
compliance with less stringent requirements.
In response to the comment that approved SIP rules are federally
enforceable, the EPA agrees. The EPA's promulgation of NSPS OOOOb and
EG OOOOc does not affect previously approved SIP actions that
incorporate NSPS OOOO or OOOOa. The EPA is establishing requirements
for sources subject to NSPS OOOOb and EG OOOOc to show ongoing
compliance with the NSPS, and if the revised NSPS subparts are adopted
and approved as part of a SIP, the LPE criteria provisions will be
federally enforceable for permits issued within the state. The EPA
routinely revises such standards to address the next generation of
sources. In this instance EPA is adding a pollutant and further
defining how legally and practicably enforceable limits must be
supported by site-specific information that supports an operator's
claim to be operating within those limits, in compliance with the rule.
As the commenters note, in 2013,\598\ the EPA found that 11 states
already required control devices for storage vessels, including both
Texas and New Mexico, such that the EPA could subtract the storage
vessels in these states ``from the overall count of storage vessels
that would be subject to the final rule.'' \599\ However, the purpose
of referring to those state regulations was in order to estimate the
total number of storage vessels that would need to be
[[Page 16978]]
controlled nationwide and evaluate whether there were enough control
devices available to owners and operators of storage vessels for
implementation of the rule in the process of considering a petition for
reconsideration. The EPA disagrees with the commenter's assertion that
the EPA made a ``determination'' as to the adequacy of the state
permitting regulations for purposes of determining applicability of the
NSPS. In particular, the EPA did not make any determination as to the
legal and practicable enforceability of the state permitting
regulations, including for Texas or New Mexico.
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\598\ 78 FR 22126 (April 12, 2013).
\599\ 78 FR 22130.
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Regarding the concern that existing sources do not have methane
limits in permits now, CAA section 111(d) and the EPA's implementing
regulations in 40 CFR part 60, subpart Ba, mandate that states adopt
plans to set performance standards for designated pollutants; for
purposes of EG OOOOc, the designated pollutant is GHGs, and the
presumptive standards in EG OOOOc are expressed in the form of methane.
Therefore, only permit limits on methane emissions can be included in
determining applicability of the methane standards for storage vessels
in the applicable state or Federal plan implementing EG OOOOc. The EPA
agrees with the commenter that a reasonable period of time may be
required to adopt state plans consistent with EG OOOOc, including to
revise permit limits for storage vessels that choose to be subject to a
legally and practicably enforceable limit below the methane
applicability threshold. For that reason, as discussed in section
XIII.E.2, the EPA has allowed states 24 months to carry out state
rulemaking activity to adopt the appropriate standards. In addition to
the 24 months, the EPA requires that states establish compliance
deadlines that require compliance with the final state plan within 36
months following the state plan submittal deadline, providing up to 5
years for existing sources to adapt their systems to new Federal and
state standards before compliance would be required. Further, because
permits for existing sources will need to be reopened to include the
final state plan criteria implementing the EG, the EPA does not believe
that there is a substantial additional burden in ensuring that the
``legally and practicably enforceable'' criteria are met.
Commenters are correct that, consistent with the finalization of
the ``legally and practicably enforceable'' criteria, the EPA may
determine that some permit limits do not meet the criteria and the tank
battery cannot use those limits when determining the potential for VOC
and methane emissions; however, the EPA always has the authority to
independently assess claims of nonapplicability. Regarding friction
with states, as stated previously, the EPA believes finalizing the
criteria will provide states with the needed level of specificity and
certainty to issue permits that meet the ``legally and practicably
enforceable'' criteria.
c. LPE Criteria
Comment: Several commenters \600\ were concerned with the specific
criteria provided for LPE. One commenter \601\ stated that permits have
proposed annual or rolling 12-month limits on emissions and production
because the tank PTE thresholds and NSR permitting thresholds are based
on annual emissions. The commenter believed that the EPA should clarify
that such annual limits meet the proposed 30-day averaging time for
production limits especially since facilities are typically permitted
for a worst-case scenario. Another criterion likely not in existing
permits is ``periodic reporting that demonstrates continuous
compliance,'' according to the commenter. Historically, the commenter
pointed out, periodic reporting has applied to major sources under
title V and affected facilities regulated under a NSPS or NESHAP, which
the commenter stated is a small fraction of the sites that will be
regulated under NSPS OOOOb and EG OOOOc.
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\600\ EPA-HQ-OAR-2021-0317-2222, -2483, -2399, and -2428.
\601\ EPA-HQ-OAR-2021-0317-2428.
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Another commenter \602\ stated that the requirements for legally
and practicably limiting the ``potential for methane emissions'' are
unclear and conflict with the definition of ``potential to emit.''
Specifically, the commenter stated:
---------------------------------------------------------------------------
\602\ EPA-HQ-OAR-2021-0317-2222.
---------------------------------------------------------------------------
It is unclear why the EPA has proposed that production
limits must be accompanied by operational limits in order to be legally
and practicably enforceable. 40 CFR 60.5386c(e)(2)(i)(A).
It is unclear how a source would establish parametric
limits for production and/or operational limits. 40 CFR
60.5386c(e)(2)(i)(C).
It is unclear how a source would use a control device to
meet an operational limit. 40 CFR 60.5386c(e)(2)(i)(C).
The same commenter stated that the EPA should refer to the
available caselaw and guidance on limiting ``potential to emit'' to
ensure that the use of terms such as ``production limit,''
``operational limit,'' and ``parametric limit'' in the proposed rules
are consistent with the widely accepted use of those terms in air
permitting programs. One commenter \603\ expressed concern that
proposed 40 CFR 60.5365b(e)(2)(i)(A), which requires a ``quantitative
production limit and quantitative operational limit(s) for the
equipment, or quantitative operational limits for the equipment,'' is
inconsistent with longstanding EPA policy. The commenter believed that
production and/or operational factors can be used as part of a
parametric calculation of emissions, but they need not be
standalone.\604\ Next, the commenter stated that proposed 40 CFR
60.5365b(e)(2)(i)(B) requires an averaging period of less than 30 days
when a production-based limit is used, but the commenter believed that
is arbitrary and capricious, as well as inconsistent with EPA policy
where the overall standard that the limit is intended to enforce is a
tpy (i.e., annual) standard. In such a case, as here, a 12-month
rolling limit, as long as it is well-defined in how it is calculated,
is more than adequate, according to the commenter.\605\ Finally, the
commenter stated that it takes issue with proposed 40 CFR
60.5365b(e)(2)(i)(C) which requires that ``where a control device is
used to achieve an operational limit, an initial compliance
demonstration (i.e., performance test) for the control device [ ]
establishes the parametric limits.'' While the commenter agreed that
the regulations should certainly allow the use of a compliance
demonstration, presumably in the form of a test, there is no reason for
the EPA to preclude other means of estimating the control device
efficiency, such as AP-42 factors or vendor-provided factors,
especially when these factors are known to be conservative.
---------------------------------------------------------------------------
\603\ EPA-HQ-OAR-2021-0317-2483.
\604\ See, e.g., In re. Salt River Project Agua Fria Generating
Station], Petition No. IX-2022-4, at 12-13 (Adm'r July 28, 2022),
available at https://www.epa.gov/system/files/documents/2022-08/SRP%20Agua%20Fria%20Order_7-28-22.pdf, (``EPA does not interpret the
Federal regulations to require production and/or operating limits in
all situations.'').
\605\ See, e.g., Memorandum from John S. Seitz, Director, EPA
Office of Air Quality Planning and Standards, to EPA Regional Air
Division Directors, Options for Limiting the PTE of a Stationary
Source Under Section 112 and title V of the Clean Air Act, at 6
(January 25, 1995), available at https://www.epa.gov/sites/default/files/documents/limit-pte-rpt.pdf (explaining that ``annual limits
such as rolling annual limits'' are appropriate to practically
enforce an annual emission limitation).
---------------------------------------------------------------------------
Response: With respect to the proposed 30-days-or-less averaging
time period for a production-based limit, the EPA agrees that a rolling
12-month
[[Page 16979]]
average is an acceptable alternative to a month-by-month determination,
where the rolling 12-month average is supported by 30-day subtotals,
beginning in the first 30 days, and redetermined every month. This is
consistent with the EPA's longstanding guidance, which expresses the
Agency's ``preference toward short term limits, generally daily but not
to exceed a month.'' \606\ The 30-day averaging time is particularly
needed here because determination of potential emissions (and in turn
storage vessel standards applicability) is required within the first 30
days after startup of production for tank batteries at well sites and
centralized production facilities; an averaging period longer than 30
days would mean there will not be sufficient data to estimate potential
emissions by the 30-day deadline whether the production limit
effectively caps a tank battery's potential emissions below the
applicable threshold(s) under NSPS OOOOb or EG OOOOc. Therefore, when
establishing permit limits on production or operation, the EPA believes
that such limits should not exceed 30 days. The EPA also points out
that a violation of a 12-month standard without any prior interval to
verify compliance has the potential to create a full year of
noncompliance and associated penalties for failure to demonstrate
ongoing compliance.
---------------------------------------------------------------------------
\606\ See memorandum, Options for Limiting the Potential to Emit
(PTE) of a Stationary Sources under Section 112 and Title V of the
Clean Air Act (Act). https://www.epa.gov/sites/default/files/2015-07/documents/ptememo.pdf.
---------------------------------------------------------------------------
Regarding production limits and operational limits, the final rule
provides that if a production limit is used, it must be accompanied by
operational limits to be legally and practicably enforceable because in
that situation, potential VOC and methane emissions from a storage
vessel are a function of both the facility's operational conditions and
production rates. Therefore, both are inputs to the storage vessel
emissions calculations. Also, because changes in either may result in
an increase in vessel emissions, monitoring is required for both the
operational conditions and the production rates used to establish
emissions from the storage vessel.
The EPA does not believe, and the commenter did not explain how,
the usage of ``production limit,'' ``operational limit,'' and
``parametric limit'' in the proposed rules is inconsistent with the
widely accepted use of those terms in air permitting programs. The EPA
clarifies that an operational limit on a control device is typically
the claimed reduction efficiency of the control system, such as the
destruction efficiency of a flare or availability of the VRU to route
vapors to process. To demonstrate compliance with such operational
limits, parametric limits for a control device are established during
manufacturer or source-specific performance testing of the device. The
EPA clarifies that ``parametric limits'' refer to limits on a parameter
that can act as a reliable indicator of an emissions-producing (or
emissions-reducing) activity or process. Parametric limits for control
devices can include flow rate, inlet pressure, residence time,
combustion zone temperature, or similar metrics.
Regarding the comment on the use of AP-42 and vendor-provided
emission factors for estimating control efficiency of control devices,
the EPA clarifies that the proposed LPE criteria do not preclude such
use of emission factors. Rather, the criteria require an initial
compliance demonstration (i.e., performance testing) for a control
device to establish parametric limits where a control device is used to
achieve an operational limit. It is not clear, and the commenter did
not explain how, AP-42 or vendor-provided emission factors could be
used to establish parametric limits. The EPA is therefore finalizing
the LPE criteria as proposed.
2. Modification
Comment: Several commenters \607\ expressed concern that the EPA
has departed from the definition of modification found at 40 CFR 60.14.
One commenter \608\ recommended that the EPA limit modifications to
where the operator increases emissions from the tank battery by
increasing the capacity of the tank battery. The commenter explained
that as proposed, subparagraphs (A) and (B)of 60 CFR 60.5365b(e)(3)(ii)
would trigger a potential modification even where the increase in
capacity of the tank battery is not accompanied by an increase in the
tank battery's emissions rate. The commenter stated that operators may
readily track and document the addition or replacement of storage
vessels within a tank battery. The commenter cautioned that if the EPA
does not define modification to require an increase in the emissions
rate of the tank battery, perverse outcomes may occur. By way of
example, the commenter explained that an operator may increase the size
of tank battery without increasing the emissions from the tank battery,
and if the emissions (which have not changed) exceed the applicability
threshold, the tank battery would become an affected facility. The
commenter explained that this possibility is real given that the EPA
now proposes to apply the 6 tpy VOC and 20 tpy methane applicability
thresholds to the entire tank battery, where it previously under NSPS
OOOO and NSPS OOOOa used the same VOC threshold but on an individual
storage vessel basis, which effectively reduces the NSPS applicability
threshold proportionally by the number of individual storage vessels in
a tank battery.
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\607\ EPA-HQ-OAR-2021-0317-2326, -2428, and -2399.
\608\ EPA-HQ-OAR-2021-0317-2326.
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Regarding subparagraphs (C) and (D) of 40 CFR 60.5365b(e)(3)(ii),
the same commenter \609\ explained that per 40 CFR 60.14(e)(2), an
increase in throughput for a storage vessel, accomplished without a
capital expenditure on that storage vessel, is not considered a
modification and the EPA has not fully explained why it is proposing to
deviate from the historical legal understanding of modification which
requires both an increase in throughput and a capital expenditure on
the storage vessel or tank battery. Other commenters \610\ expressed
similar concerns regarding capital expenditure. Two commenters \611\
noted that increases in liquid throughput at well sites, central
production facilities, and compressor stations are difficult to track,
as operators typically track liquid throughput using tank gauging
rather than flow meters. Further, one commenter \612\ explained, the
modification criteria for tank batteries at well sites and centralized
production sites serve as a disincentive to the centralization of
facilities, as the addition of production from a new well to an
existing centralized production facility would trigger a modification
under 40 CFR 60.5395b(e)(3)(ii)(C). The commenter urged the EPA to
consider that if the EPA does not remove the criteria at 40 CFR
60.5395b(e)(3)(ii)(C), the increase in liquid throughput also must be
accompanied by a capital expenditure on the tank battery itself. The
commenter explained that some actions, such as drilling a new well or
fracturing or refracturing an existing well, could increase liquid
throughput and require capital expenditure but not necessarily on the
tank battery itself.
---------------------------------------------------------------------------
\609\ EPA-HQ-OAR-2021-0317-2326.
\610\ EPA-HQ-OAR-2021-0317-2428 and -2399.
\611\ EPA-HQ-OAR-2021-0317-2326 and -2428.
\612\ EPA-HQ-OAR-2021-0317-2326.
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The same commenter \613\ recommended other clarifications to
[[Page 16980]]
subparagraph 40 CFR 60.5395b(e)(3)(ii)(C). First, the commenter
believed that the EPA should remove the reference to ``process unit''
in subparagraph (C), because ``process unit'' is defined in the rule
within the context of facilities that process natural gas, not well
sites and centralized production facilities, and that the reference to
process unit in the context of well sites and centralized production
facilities is confusing and misplaced. Second, the commenter stated
that the EPA should limit the scope of subparagraph (C) to ``actions
taken with respect to equipment that directly, or through a series of
equipment, provides crude oil, condensate, intermediate hydrocarbons,
or produced water throughput to the tank battery, including the
addition of, or change to, a production well (including hydraulic
fracturing or refracturing of the well).'' By way of example, the
commenter explained that hydraulic fracturing activities occurring in
the vicinity of a well that delivers produced liquids to a storage tank
battery may temporarily increase production of the well, which would,
in turn, increase throughput of the tank battery, but as drafted, it is
unclear whether this increase in production is an ``action'' that
modified the tank battery if it resulted in exceedance of the potential
for emissions threshold. The commenter believed the increase in
production should not be considered an action, as operators cannot plan
for or anticipate increases in production from activities occurring
offsite that are outside the scope of operations associated with the
tank battery. Further, in this example, the commenter explained that
the cause of a temporary increase in production may be unknown to the
operator and considering ``actions'' having no direct relationship to
equipment in the definition of modification would be a far and extreme
departure from longstanding NSPS modification principles. If the EPA
retains these modification triggers, the commenter requested that well
sites and centralized production facilities also be allowed to compare
liquid throughputs to limits in a legally and practicably enforceable
permit as is allowed for compressor stations and natural gas processing
plants. The commenter believed this recommendation would also make
modification criteria consistent for all sites and clearly define what
an increase in liquid throughput is.
---------------------------------------------------------------------------
\613\ EPA-HQ-OAR-2021-0317-2326.
---------------------------------------------------------------------------
Similarly, one commenter \614\ stated that the December 2022
Supplemental Proposal is not only inconsistent with the statutory
definition of ``modification'' but also inconsistent with the EPA's
prior interpretation that a ``modification'' requires some physical
change to a tank. See Letter from Valdus Adamkus, EPA Region 5, to
Bradley Miller, Hamilton County Environmental Services (March 25, 1996)
\615\ (increase in vapor pressure resulting in increased tank emissions
was not a ``modification'' under 40 CFR part 60, subpart Kb because
there were no physical changes to the tank). The commenter was
concerned that, unless the proposed definition of ``modification'' is
revised to require a physical change or change in the method of
operations, midstream owners and operators could find their equipment
``modified'' solely based on the decisions of upstream third parties
and without taking any action themselves.
---------------------------------------------------------------------------
\614\ EPA-HQ-OAR-2021-0317-2399.
\615\ See https://cfpub.epa.gov/adi/index.cfm?fuseaction=home.dsp_show_file_contents&CFID=1949573&CFTOKEN=fb4fc82ba0b35cd4-2102140A-E016-B8E6-76946EF822FC87A4&id=9600032.
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Another commenter \616\ provided some specific recommendations, if
the EPA decides to include increases in liquid throughput as a
criterion for modification:
---------------------------------------------------------------------------
\616\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------
The increase in liquid throughput must also be accompanied
by a capital expenditure on the tank battery itself. Actions, such as
drilling a new well or fracturing or refracturing an existing well,
could increase liquid throughput and require capital expenditure but
not necessarily on the tank battery itself. These actions would not be
considered modifications to the tank battery unless there is capital
expenditure on the tank battery itself. This recommendation would make
NSPS OOOOb consistent with the general provisions in 40 CFR 60 subpart
A.
Reference to process unit in 40 CFR 60.5365(e)(ii)(C)
should be removed since process unit is defined such that they should
not exist at well sites and centralized production facilities. Process
unit is a term specific to natural gas processing plants and does not
apply to well sites and centralized production facilities.
Well sites and centralized production facilities should
also be allowed to compare liquid throughputs to limits in a legally
and practicably enforceable permit like compressor stations and natural
gas processing plants. The EPA should be consistent and allow well
sites and centralized production facilities to compare liquid
throughputs to limits in a legally and practicably enforceable permit
since such a permit can be relied upon for the PTE determination for
all sites.
In the absence of a legally and practicably enforceable
limit, all sites should be allowed to compare liquid throughputs to
those used to design the existing cover and closed vent system in
operation when a potential modification action occurs. These
recommendations would also make modification criteria consistent for
all sites and clearly define what an increase in liquid throughput is.
The same commenter \617\ offered suggested edits to 40 CFR
60.5365b(e)(3)(ii) consistent with their recommendations.
---------------------------------------------------------------------------
\617\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------
Response: The EPA is finalizing the provisions regarding
modification as proposed, except for minor edits to the regulatory text
at 40 CFR 60.5365b(e)(3)(ii) to replace ``result in'' with ``occurs''
such that the provision is as follows: `` `Modification' of a tank
battery occurs when any of the actions in paragraphs (e)(3)(ii)(A)
through (D) of this section occur and the potential for VOC or methane
emissions meets or exceeds either of the thresholds specified in
paragraphs (e)(1)(i) or (ii) of this section.'' The EPA is making this
change because the EPA already has determined that the actions
described in 40 CFR 60.5365b(e)(3)(ii)(A) through (D) result in an
emissions increase, and the term ``result in'' may be incorrectly
interpreted to suggest otherwise.
CAA section 111(a)(4) defines ``modification'' as ``any physical
change or operational change in a stationary source which increases the
amount of any air pollutant emitted by such source . . . .'' While the
general provisions at 40 CFR 60.14 provide a definition of
modification, 40 CFR 60.14(f) specifically authorizes the EPA to
provide subpart-specific definition for ``modification'' that would
supersede any conflicting provision in 40 CFR 60.14. Pursuant to its
authority under 40 CFR 60.14(f), the EPA proposed to define
``modification'' of a tank battery under NSPS OOOOb (40 CFR
60.5365b(e)(3)(ii)) to mean when the potential emissions of the tank
battery exceed the 6 tpy VOC or 20 tpy methane threshold following any
of the following physical or operational changes:
(A) a storage vessel is added to an existing tank battery;
(B) one or more storage vessels are replaced such that the
cumulative storage capacity of the existing tank battery increases;
(C) for tank batteries at well sites or centralized production
facilities, an
[[Page 16981]]
existing tank battery receives additional crude oil, condensate,
intermediate hydrocarbons, or produced water throughput from actions,
including but not limited to, the addition of operations or a
production well, or changes to operations or a production well
(including hydraulic fracturing or refracturing of the well); or
(D) for tank batteries at compressor stations or onshore natural
gas processing plants, an existing tank battery receives additional
fluids which cumulatively exceed the throughput used in the most recent
(i.e., prior to an action in paragraphs (e)(3)(ii)(A), (B) or (D) of
this section) determination of the potential for VOC or methane
emissions.
The EPA did not propose to require a showing of an emission
increase, having determined that each of the four scenarios describes a
physical or operational change that results in an emission increase.
With respect to scenarios (A) and (B) above, the EPA explained in the
November 2021 Proposal that even if the type and quantity of fluid
processed remain the same, the increased storage capacity will lead to
higher breathing losses and thereby increase emissions from the tank
battery. See 86 FR 63198. With respect to scenario (C), as the EPA
explained in the November 2021 Proposal (86 FR 63199) and reiterated in
the December 2022 Supplemental Proposal (87 FR 74802), ``actions
occurring at a well site, such as refracturing a well or adding a new
well that sends these liquids to the tank battery at the well site or
centralized production facility, would result in an increase in VOC and
methane emissions based on an increase in volumetric throughput to the
tank battery.'' With respect to scenario (D), which addresses storage
vessels at compressor stations and gas processing plants, the EPA
acknowledges that ``storage vessels at these locations are designed to
receive liquids from multiple well sites that may startup production
over a longer period of time''; the EPA therefore ``agrees that when a
tank battery at a compressor station or onshore natural gas processing
plant receives additional throughput which has already been accounted
for in the design capacity of that tank battery and included as a
legally and practically enforceable limit in a permit for the tank
battery, that additional throughput does not result in an emission
increase from the tank battery because those emissions have already
been accounted for in the permit.'' (87 FR 74802). In other words,
there is emission increase under scenario (D) when the emissions from
the additional throughput is not accounted for in the design capacity
of the tank battery.
While the EPA has determined that an emissions increase results
from each of the four scenarios described in 40 CFR 60.5365b(e)(3)(ii),
none of them automatically result in the potential for VOC or methane
emissions to be at or above the VOC or methane emissions thresholds in
NSPS OOOOb; each of the scenarios would trigger the need to complete
the ``potential for VOC or methane emissions'' determination under 40
CFR 60.5365b(e)(1)(ii).
The EPA disagrees with the comment that modification based on an
increase in the tank battery's capacity (i.e., scenarios (A) and (B))
must be accompanied by an increase in the tank battery's emission rate
and that modification based on increased throughput (i.e., scenarios
(C) and (D)) must be accompanied by a capital expenditure. As mentioned
above, CAA section 111(a)(4) defines ``modification'' as ``any physical
change or operational change in a stationary source which increases the
amount of any air pollutant emitted by such source . . . .'' The
statutory definition does not require that there be an increase in an
``emission rate,'' and it makes no reference to ``capital
expenditure''; therefore, neither is requisite to determining
modification. Further, 40 CFR 60.14(f) authorizes the EPA to set forth
``[s]pecial provisions . . . under an applicable subpart of this part
[that] shall supersede any conflicting provisions of this section.''
With respect to scenarios (A) and (B), as explained above, the EPA
determined that an increase in tank battery capacity (scenarios (A) and
(B)) will always increase the emissions from that tank battery. The
commenters do not mention, much less disagree with or question, the
EPA's rationale. Having already determined that scenarios (A) and (B)
increase emissions, there is no need to require emission rate
calculation for purposes of determining whether there is an emission
increase under these scenarios. The EPA therefore declines the
suggestion to require that scenarios (A) and (B) be accompanied by an
increase in the tank battery's emission rate.
With respect to scenarios (C) and (D), the commenters did not
explain why these scenarios must be accompanied by a capital
expenditure other than pointing to 40 CFR part 60, General Provisions,
40 CFR 60.14(e)(2), which exempts from ``modification'' a facility that
increases its production rate (and thus emissions) but without a
capital expenditure on that facility. The EPA notes that this exemption
was promulgated in 1975, at the early stage of the EPA's CAA section
111 rulemaking. The EPA had just promulgated NSPS for the first five
listed source categories (steam generators, portland cement plants,
incinerators, nitric acid plants, and sulfuric acid plants) a few years
earlier in 1971.\618\ All of these facilities were traditional
industrial plants; there is no indication that in those earlier years
of CAA section 111 rulemakings, the EPA had the occasion to evaluate
more complex and unique source categories such as the crude oil and
natural gas source category, where a physical or operational change at
one affected facility (e.g., fracking of a well) causes physical/
operational change and emission increase at another affected facility
(a tank battery). What is clear is that 40 CFR 60.14(f), which the EPA
promulgated concurrently with 40 CFR 60.14(e), authorizes the EPA to
establish in individual rule subparts provisions that supersede any
conflicting provisions in 40 CFR 60.14(e). As explained earlier, under
scenarios (C) and (D), there is always a physical/operational change
and emission increase at a tank battery when receiving additional
throughput; this is the case whether or not there is capital
expenditure on the tank battery. However, 40 CFR 60.14(e) would exempt
tank batteries under scenarios (C) and (D) from regulation if there is
no capital expenditure, even if they have potential emissions above the
thresholds established in this rule. The EPA does not believe, and the
commenters do not explain why, such exemption is justified. Therefore,
the EPA declines to include a requirement that there be a capital
expenditure under scenarios (C) and (D).
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\618\ 36 FR 24876 (December 23, 1971).
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With respect to the comment claiming that the EPA previously
interpreted ``modification'' to require physical change to a tank, the
1996 EPA letter that the commenter cited as support made no such
pronouncement. Further, the letter addressed applicability of a storage
tank regulated under the New Source Performance Standard, subpart Kb,
and the exemption at issue was 40 CFR 60.14(e)(4) (use of an
alternative fuel or raw material that the existing facility was
designed to accommodate). It is not clear, and the commenter did not
elaborate, how that determination applies here, not to mention that the
EPA has since taken a different
[[Page 16982]]
position.\619\ The EPA therefore made no change in response to this
comment.
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\619\ See ``New Source Performance Standards Review for Volatile
Organic Liquid Storage Vessels (Including Petroleum Liquid Storage
Vessels); Proposed Rule,'' 88 FR 63535 (October 3, 2023) (proposing
to reinterpret the applicability of 40 CFR 60.14(e)(4) to not apply
to changes in the organic liquid stored in a storage vessel).
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We agree with a commenter's suggestion of removing the term
``process unit'' from proposed 40 CFR 60.5365b(e)(3)(ii)(C), which in
the December 2022 Supplemental Proposal defined ``modification'' of
tank batteries at well sites or centralized production facilities as
when ``an existing tank battery receives additional crude oil,
condensate, intermediate hydrocarbons, or produced water throughput
from actions, including but not limited to, the addition of a process
unit or production well, or changes to a process unit or production
well (including hydraulic fracturing or refracturing of the well). We
agree with the commenter that the term ``process unit,'' as defined in
the proposed NSPS OOOOb and EG OOOOc, relates specifically to natural
gas processing plants. In the final rule, the EPA has substituted the
term ``process unit'' with ``operations,'' a more generic term to cover
activity that could result in additional product throughput to a tank
battery at a well site or centralized production facility.
Regarding the comment that in the absence of a legally and
practicably enforceable limit, all sites should be allowed to compare
liquid throughputs to those used to design the existing cover and
closed vent system in operation when a potential modification action
occurs, the EPA disagrees because the throughput used in the design
analysis for the cover and closed vent system itself is not a legally
and practicably enforceable limit on throughput. The design analysis
also may include emissions from other than a storage vessel affected
facility, making it difficult to extract the contribution from the tank
battery. Finally, if the prior determination (i.e., before one of the
potential modification actions) was that the tank battery was not a
storage vessel affected facility, then the requirements to control the
tank battery and design and operate a cover and closed vent system
would not apply and no record of the cover and closed vent system
design would exist.
The EPA must defer to a case-by-case determination on the comment
asking that the EPA determine whether an action ``. . . from activities
occurring off-site that are outside the scope of operations associated
with the tank battery'' is not an action that results in a modification
because of the seemingly site-specific circumstances of the example.
The commenter seems to be citing an example of hydraulic fracturing at
a nearby well that induces a change in throughput to tanks at another
unrelated well site or centralized production facility. Regarding
temporary increases in throughput, the modification actions do not have
a temporal element. For the reasons discussed in the November 2021
Proposal, the EPA believes the actions will result in emissions
increase to the atmosphere. See 86 FR 63198. Limitations on throughput
may be accounted for in a legally and practicably enforceable limit
when determining the potential for VOC and methane emissions, which
determination is conducted after one of the actions occurs.
Regarding the comment that an owner or operator has difficulty
tracking liquid throughput because operators typically track liquid
throughput using tank gauging rather than flow meters, the EPA
clarifies that the final rule does not require any specific equipment
for tracking throughput and, therefore, throughput can be tracked using
gauging.
Regarding the comment that the owner or operator of midstream tank
batteries at compressor stations or natural gas processing plants has
no control over the receipt of fluids from upstream production
facilities owned by third parties, as explained above, as long as the
additional throughput is accounted for in the design capacity of the
tank battery, the additional throughput does not result in an emissions
increase from the tank battery because those emissions have already
been accounted for in the permit. See 87 FR 74802. The EPA proposed
language to that effect at 40 CFR 60.5365b(e)(3)(ii)(D) and
60.5365b(e)(2)(iii)(A) and (B). The EPA therefore is finalizing, as
proposed, the requirements regarding modification actions at natural
gas processing plants and compressor stations. In summary, a tank
battery at a natural gas processing plant and compressor station is
considered to be modified if one of the actions (adding a storage
vessel to an existing tank battery, replacing one or more storage
vessels such that the cumulative capacity of the tank battery
increases, or the existing tank battery receives additional fluids
which cumulatively exceed the throughput used in most recent
determination of the potential for VOC or methane emissions) occurs and
the potential for VOC or methane emissions meets or exceeds the
thresholds.
Regarding the comment that the modification criteria create a
disincentive to the centralization of facilities, the EPA is not
persuaded that operators locate and design their tank batteries to
avoid modification determinations because at some point in the future a
well may be added to route product to the tank battery, and the EPA
believes the decisions are based on the economics of well production.
The EPA notes that our BSER analysis has determined that it is cost-
effective to control emissions of VOC and methane at 6 tpy and 20 tpy,
respectively, regardless of the number or the location of the tank
batteries.
The EPA here reiterates that modification requires two conditions--
that (1) one of the actions in 40 CFR 60.5365b(e)(3)(ii) (A) through
(D) occurs, and (2) the potential for emissions from the tank battery
meets or exceeds 6 tpy VOC or 20 tpy methane (applicability
determination). With regard to the comment that an increase in the size
of a tank battery alone would trigger applicability, that is not the
case. The applicability determination must be performed within 30 days
under 40 CFR 60.5365b(e)(2)(ii) after adding the storage vessel or
replacing a storage vessel with another storage vessel of greater
capacity, and where the applicability determination indicates that
emissions are less than 6 tpy VOC or 20 tpy methane, the storage vessel
would remain an unaffected facility under NSPS OOOOb.
Comment: Several commenters \620\ were concerned about the
modification provisions related to replacement of a storage tank. One
commenter \621\ stated that an operator of an unregulated tank or tank
in a battery that reaches the end of its safe operational life and must
be replaced should not be required to have to prove that the tank or
tank battery should still be unregulated. The commenter explained that
many oil and gas wells typical of legacy production are limited in
their productive life only by the life of the tubulars in them (as
exhibited by the many 100-year-old-plus wells still producing in the
Appalachian Basin of east Kentucky). The commenter believed that
operators should be permitted to replace equipment in kind (e.g., akin
to a ``standard set'' for the refining industry) and should not be
burdened with potentially expensive compliance activities for replacing
equipment that has reached the end of its useful life. The commenter
expressed that they believed that if the EPA
[[Page 16983]]
finalizes the modification provisions as proposed, many operators will
not replace equipment and that those modification provisions would
result in more emissions from equipment not being replaced to avoid the
EPA's compliance requirements. Another commenter \622\ recommended that
replacement of a tank that only increases battery capacity should not
trigger a modification because, the commenter states, an increase in
tank capacity does not equal an increase in emissions and, therefore,
should not be considered a modification under any rule.
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\620\ EPA-HQ-OAR-2021-0317-2172, -2298, and -2248.
\621\ EPA-HQ-OAR-2021-0317-2172.
\622\ EPA-HQ-OAR-2021-0317-2298.
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One of the commenters \623\ expressed concern about the
modification provisions related to relocation of a storage vessel. The
commenter stated that certain activities the EPA is proposing which
potentially trigger a modification include activities that are not a
``physical change in, or change in the method of operation of, a
stationary source'' as required by CAA section 111(a)(3). By way of
example, the commenter pointed out that the definition of modification
in the proposed rule could include the relocation or replacement of a
storage vessel. The commenter also stated that they do not believe that
the EPA has demonstrated the necessity of this change or how its
implementation will benefit the environment.
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\623\ EPA-HQ-OAR-2021-0317-2248.
---------------------------------------------------------------------------
Response: The EPA believes that scenarios regarding the relocation
of an existing tank battery or replacement ``in like kind'' (i.e., the
cumulative throughput capacity is not increased) are not governed by
the modification provisions, but are akin to relocation and
reconstruction provisions, respectively. See discussion below which
clarifies which provisions (i.e., construction, reconstruction,
modification, or return to service) would need to be evaluated under
different tank replacement or relocation scenarios. On the other hand,
replacement of a tank that adds capacity to the tank battery
constitutes a modification. The EPA assumes that a facility adding
storage capacity anticipates an increase in production, which will lead
to higher emissions from the tank battery (86 FR 63199). Further, as
mentioned earlier, even if the type and quantity of fluid processed
remain the same, the increased storage capacity will lead to higher
breathing losses and thereby increase emissions from the tank battery.
See 86 FR 63198. The commenter does not dispute that, much less
providing a reason why, either of these rationales is incorrect.
Therefore, the definition of ``modification'' in the final rule,
specifically 60.5365b(e)(3)(ii)(A) and (B), is unchanged.
Regarding the comment on relocation, the EPA wishes to clarify
which provisions (i.e., construction, reconstruction, modification, or
return to service) would need to be evaluated under different tank
replacement or relocation scenarios. When one or more tanks in an
existing tank battery are replaced, but the cumulative storage capacity
does not increase nor are tanks added to the total number, the
replacement is not a ``modification'' as defined in 40 CFR
60.5365b(e)(3)(ii)(A) and (B); however, if more than half of tanks in
an existing tank battery are replaced, such replacement is
``reconstruction'' under 40 CFR 60.5365b(e)(3)(i) if, after such
replacement, the tank battery has the potential for 6 tpy or more of
VOC emissions or 20 tpy or more of methane emissions (see comments and
responses related to reconstruction in section XI.J.3 of the preamble).
If a storage vessel affected (or designated) facility or portion of a
storage vessel affected (or designated) facility that had been taken
out of service is later returned to service (i.e., reconnected to the
original source of liquids), it remains a storage vessel affected
facility subject to the same requirements that applied before its being
removed from service (see 40 CFR 60.5365b(e)(6) (or 60.5386c(e)(5)). If
an existing tank battery is relocated, with no actions described in the
modification provisions at 40 CFR 60.5365b(e)(3)(ii) taking place, and
without replacement of any tanks or other components in the tank
battery, then there is no modification or reconstruction of the
relocated tank battery. Further, if this existing tank battery was
determined not to be a designated facility under EG OOOOc (i.e., the
potential methane emissions are less than 20 tpy), relocation of the
existing tank battery does not change that status. Additional examples
of the outcomes of certain actions regarding modification may be found
in the December 2022 Supplemental Proposal. See 87 FR 74802.
3. Reconstruction
Comment: One commenter \624\ believes that the proposed definition
of reconstruction is internally inconsistent. The commenter cites to
the EPA's rationale in the proposal that for a tank battery consisting
of more than one storage vessel, reconstruction is based on replacing
at least half of the storage vessels based on the assumption that ``the
cost of replacing storage vessel components such as thief hatches and
pressure relief devices, in comparison to the cost of constructing an
entirely new storage vessel affected facility, will not exceed 50
percent of the cost of constructing a comparable new storage vessel
affected facility.'' However, the commenter points out, for a tank
battery consisting of a single storage vessel, the existing provisions
of 40 CFR 60.15 apply on the chance that the cost of replacement
storage vessel components could be 50 percent or more of the cost to
construct a comparable new storage vessel. The commenter explains that
the cost of depreciable components on a storage vessel other than the
tank itself either could be or could not be 50 percent or more of the
cost of a new comparable tank. The commenter is concerned that this
inconsistency means that operators would have to track the cost of
storage vessel component replacements for single storage vessel tank
batteries, but not for multi-vessel tank batteries. For both single-
and multi-vessel tank batteries, the commenter believes that operators
should have the option to track either storage vessel replacements or
all depreciable components and provided suggested regulatory changes
reflecting their recommendations.
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\624\ EPA-HQ-OAR-2021-0317-2428.
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Response: The EPA agrees that there appeared to be an inconsistency
in the discussion in the December 2022 Supplemental Proposal with
respect to why the EPA proposed to define ``reconstruction''
differently for a tank battery with more than one storage vessel and a
tank battery with a single storage vessel. For the former, the EPA
proposed to simplify and streamline the reconstruction determination by
defining reconstruction at a tank battery with more than a single
storage vessel as replacement of 50 percent of the storage vessels in
the tank battery. This was based on the EPA's expectation that when an
affected facility is replacing one or more storage vessels in a tank
battery, the capital costs for the individual storage vessel
replacement would be comparable or similar. The EPA received support
for this proposal. One commenter agrees that ``[b]ecause individual
tanks are likely to have comparable replacement costs, it is reasonable
to assume that there would be a one-to-one correlation between the
percentage of tanks being replaced at a site and the percentage of the
fixed capital cost that would be required to
[[Page 16984]]
construct a comparable entirely new facility.'' \625\
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\625\ Cite to EDF 02/13/23 comment at 126.
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The preamble to the December 2022 Supplemental Proposal also states
that ``for a tank battery which consists of more than a single storage
vessel, we believe that the cost of replacing storage vessel components
such as thief hatches and pressure relief devices, in comparison to the
cost of constructing an entirely new storage vessel affected facility,
will not exceed 50 percent of the cost of constructing a comparable new
storage vessel affected facility'' (87 FR 74801-02) (emphasis added).
This statement about replacing components appears to cover replacements
not addressed by the proposal above, i.e., it is addressing
replacements other than one-to-one storage vessel replacement in a tank
battery with more than one storage vessel. However, the preamble does
not provide a rationale for this statement; more importantly, the
statement contradicts the EPA's proposal to apply 40 CFR 60.15 \626\ to
reconstruction of a tank battery with a single storage vessel based on
the contrary belief that ``it may be possible that the cost of
replacing the thief hatch, pressure relief device or other depreciable
components could exceed 50 percent of the cost of an entirely new
storage vessel.'' (87 FR 74801) (emphasis added). The EPA solicited
comment on this issue; one commenter responded that the cost of
replacing the thief hatch, pressure relief device, or other depreciable
components would not exceed 50 percent of the cost of an entirely new
comparable tank battery, but the commenter did not provide any
supporting information for its comment. Although this statement could
be true where only some fraction of depreciable components (and perhaps
for some fraction of the total storage vessels) in the tank battery
were replaced, it remains possible that the cost of replacing the thief
hatch, pressure relief device, or other depreciable components could
exceed 50 percent of the cost of a comparable entirely new facility.
Further, we are concerned that if we were to apply the proposed
reconstruction definition for a tank battery with more than one storage
vessel (i.e., replacing more than 50 percent of the storage vessels in
a tank battery constitutes reconstruction) and to replacements that are
not one-to-one storage vessel replacement, it could potentially have an
unintended effect of disincentivizing owners and operators from
replacing old storage vessels.
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\626\ 40 CFR 60.15, which defines ``reconstruction'' as when the
cost of replacing components of an existing facility exceeds 50
percent of the cost of constructing a comparable tank battery
affected facility, would require keeping accounting of the
replacement costs for the ``reconstruction'' determination.
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In light of the above, while the EPA continues to believe that it
is appropriate to simplify and streamline the ``reconstruction''
determination where there is one-to-one storage vessel replacement in a
tank battery, the EPA cannot definitively conclude that other
replacements to a tank battery with more than one storage vessel would
never exceed 50 percent of the cost of an entirely new storage vessel;
in that respect, there is no difference between a tank battery with a
single storage vessel and a tank battery with more than one storage
vessel. Therefore, in the final rule, the EPA is defining
``reconstruction'' of a tank battery as follows:
``Reconstruction'' of a tank battery occurs when the potential for
VOC or methane emissions from the tank battery meets or exceeds [either
the 6 tpy VOC or 20 tpy methane threshold] and either:
(A) at least half of the storage vessels are replaced in the
existing tank battery that consists of more than one storage vessel; or
(B) the provisions of Sec. 60.15 are met for the existing tank
battery.
Comment: Two commenters \627\ provided input on the timeframe for
determining whether a reconstruction of a tank battery had occurred.
The commenter agrees that a 2-year time frame is reasonable and will
provide operators with a clear way to determine if reconstruction has
been triggered. Another commenter \628\ believes that a 2-year rolling
period provides a reasonable method of determining whether an owner of
an oil and natural gas site with storage tanks is actually pursuing an
extensive tank replacement program, within the EPA's original intent in
promulgating 40 CFR 60.15.
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\627\ EPA-HQ-OAR-2021-0317-2403 and -2305.
\628\ EPA-HQ-OAR-2021-0317-2433.
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Response: The EPA requested comment in the December 2022
Supplemental Proposal regarding the specific timeframe within which
replaced storage vessels in an existing tank battery will be aggregated
towards determining whether the 50 percent replacement threshold has
been exceeded. As summarized above, all of the commenters consider 2
years to be a reasonable period, and one commenter specifically
recommends a 2-year rolling period. The EPA is therefore finalizing a
2-year rolling period.
K. Covers and Closed Vent Systems
In section X.K of this document the final NSPS OOOOb and EG OOOOc
requirements for covers and closed vent systems are summarized.
Significant comments were received on the December 2022 Supplemental
Proposal regarding the NIE standard. This topic, a summary of the
proposed rule, the comments, the EPA responses, and changes made in the
final rule (if applicable), are discussed here. These comments and the
EPA's responses to these comments generally apply to the standards
proposed in both NSPS OOOOb and EG OOOOc. The instances where the
comment and/or response only applies to NSPS OOOOb or EG OOOOc are
noted. Comments and changes relevant to appendix K are discussed in
section XIV of this preamble. The EPA's full response to comments on
the November 2021 Proposal and December 2022 Supplemental Proposal,
including any comments not discussed in this preamble, can be found in
the EPA's RTC document for the final rule.\629\
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\629\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
---------------------------------------------------------------------------
In the December 2022 Supplemental Proposal, the EPA proposed a 95
percent emission reduction performance standard for a number of
affected/designated facilities, including centrifugal compressor,
pneumatic pump, process controller, and tank battery affected/
designated facilities. This numeric standard reflects the emission
reduction from capturing and routing the affected/designated facility's
emissions through a CVS to a control device with a 95 percent control
efficiency, which the EPA has identified as either the BSER or a
control option for these affected/designated facilities. To ensure
compliance with the 95 percent emission reduction standard when using a
control device,\630\ the EPA proposed that the control device must
reduce the emissions routed to the control device by 95 percent or
greater.\631\ This would in turn require that covers and CVS be
designed and operated to capture and route all emissions to the control
device. To that end, the EPA proposed a NIE standard
[[Page 16985]]
for the covers and CVS associated with affected/designated facilities
complying with the 95 percent emission reduction standard by routing
emissions through a CVS to a control device.\632\ Therefore, compliance
with the 95 percent emission reduction standard when using a control
device would require compliance with both the control device standard
and the NIE standard for the associated cover and CVS. To ensure
compliance with the NIE standard (which in turn would ensure compliance
with the 95 percent emission reduction standard), the EPA proposed that
inspections of covers and closed vent systems (except when associated
with gas plants) would be conducted using AVO and either OGI or EPA
Method 21, at the same frequency as inspections conducted for fugitive
emissions at well sites and compressor stations. For closed vent
systems at gas plants, AVO inspections would be conducted annually and
OGI inspections would be conducted bimonthly in accordance with
appendix K (or alternatively, quarterly using EPA Method 21).
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\630\ The EPA cannot require the installation of any specific
control device to meet performance standards that are in the form of
numeric limitation, such as the 95 percent emission reduction
standard. See CAA section 111(b)(5).
\631\ See proposed 40 CFR 60.5412b(a)(1)(i) and 40 CFR
60.5412c(a)(1)(i).
\632\ See proposed 40 CFR 60.5411b(a)(3), 40 CFR 60.5416b(b), 40
CFR 60.5411c(a)(3), and 40 CFR 5416c(b).
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As explained in the December 2022 Supplemental Proposal (87 FR
74805), the EPA used the term NDE in the November 2021 Proposal to
describe this design and operational requirement for CVS and covers;
however, in light of comments that the term NDE is closely linked with
EPA Method 21 and is defined based on an instrument reading in ppmv
(the proposed OGI and AVO inspections would not result in an instrument
reading in ppmv), the EPA proposed renaming the standard to NIE, which
is more appropriate for the methods (i.e., OGI and AVO) required to
demonstrate compliance. The EPA, however, emphasized that the NIE
standard is an emission limitation, not a work practice standard, that
any identified emissions would be a deviation of this emissions
limitation, and that ``the corrective actions (in the form of the
repair provisions) are provided to ensure that owners and operators
bring the CVS back into compliance with the NDE [now NIE] emission
limit as quickly as possible.'' (Id.) Provided below is a summary of
significant comments on this topic and the EPA's response thereto.
Comment: Commenters \633\ had concerns both with the term NIE and
with the EPA's position that the NIE standard is a numeric limit. One
commenter \634\ contends that there is a major difference between the
terms NDE and NIE for operators, because NDE recognizes that there will
be unavoidable de minimis leaks (i.e., less than 500 ppmv) even in the
best managed operations. Another commenter \635\ questioned the EPA's
position that the NDE standard (the term used in the November 2021
Proposal) always has been an emissions limit and that the detection of
emissions above a certain threshold results in both a violation of the
standard and an obligation to undertake a repair within a specified
time period. The commenter explains that they are unaware of the EPA's
ever taking this position.
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\633\ EPA-HQ-OAR-2021-0317-2202, -2227, -2248, -2326, -2391, -
2403, and -2428.
\634\ EPA-HQ-OAR-2021-0317-2391.
\635\ EPA-HQ-OAR-2021-0317-2202.
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Regarding the numeric limit of NIE, commenters \636\ stated that
the reality of engineering a ``zero-emissions'' standard can never be
perfectly achieved. One commenter \637\ pointed out that mechanical
components and seals are prone to some de minimis level of leaking
despite compliance with all other requirements, and because very small
leaks are unavoidable and no LDAR program can prevent leaks 100 percent
of the time, operators will not be able to comply with a NIE standard.
Several commenters \638\ believed that a zero-emissions standard is not
realistic for equipment located outside, because the equipment is
subject to harsh conditions and undergoes continuous wear and tear,
including intrusion of foreign objects preventing reseating of seal
surfaces. Commenters believed emissions from such scenarios should not
be an indication of inadequate CVS design. One of these commenters
\639\ added that such leaks are not within the control of the operator,
unlike the possibility of improperly operating a cover or CVS (e.g.,
forgetting to close a thief hatch), and asked that the EPA clearly
differentiate leaks beyond the control of the operator from leaks
within the control of the operator.
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\636\ EPA-HQ-OAR-2021-0317-2202, -2248, and -2326.
\637\ EPA-HQ-OAR-2021-0317-2391.
\638\ EPA-HQ-OAR-2021-0317-2248, -2403, and -2428.
\639\ EPA-HQ-OAR-2021-0317-2428.
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These same commenters offered that because the components that make
up covers and CVS are exposed to the elements just as other components
included in the fugitives monitoring program, it makes sense to treat
them the same way, by allowing LDAR work practice standards. These
commenters also questioned why a leak in a CVS pipe is considered a
violation, but a leak in a gas pipeline 10 feet away is not; the
commenters believed that a leak should not be handled differently just
because it occurs on a cover or CVS. From a practical standpoint, the
commenters stated, leaks from these components have little to do with
inadequate design or operation. One commenter \640\ explained that
pressure and vacuum relief devices are present for safety reasons to
prevent the tank from over-pressurization as wells as under-pressure
(i.e., vacuum). The commenter noted that temperatures in North Dakota
can vary 60 [deg]F or more in a 24-hour period. This variation causes
the content of the tanks to expand and shrink, and without these
control devices, the commenter contended, the tanks would fail. The
commenter explained that the vacuum side for the pressure relief device
is especially susceptible to sucking in dust and sometimes even bugs
that prevent the device from sealing, but these are all taken care of
as part of the LDAR program. Finally, the commenter noted that design
issues, if any, will show up as repeat offenders in the LDAR program
and will be corrected as part of that program.
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\640\ EPA-HQ-OAR-2021-0317-2248.
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Another commenter \641\ stated that the EPA does not provide
anything in the rulemaking record that indicates any system capable of
achieving a zero-emissions standard has been ``adequately
demonstrated.'' The commenter contended that on its face, such a
standard is therefore inconsistent with CAA section 111(a)'s plain
terms and cannot be BSER. Similarly, another commenter \642\ stated
that the EPA long ago rejected the idea that numeric emissions
limitations can or should be applied to fugitive emissions components
and that the EPA has presented no reason in the proposal to depart from
its historical approach regarding fugitive emissions from CVS. To this
end, the commenter maintained that an NIE or NDE standard cannot
constitute a numeric emissions limitation, because BSER must be
achievable. The commenter further stated that CAA section 111(h)(2)
provides that a work practice standard should be prescribed in lieu of
a standard of performance (i.e., numeric emissions limitation) when ``a
pollutant or pollutants cannot be emitted through a conveyance designed
and constructed to emit or capture such pollutant.'' The commenter
contended that this is precisely the case with the EPA's proposed NIE
standards because the NIE standards do not apply to emissions
[[Page 16986]]
from the storage vessel or equipment on which the CVS is installed.
Rather, the proposed NIE standard applies to the CVS itself. In this
case, the commenter maintained, it is obvious that there is no
``conveyance'' through which the regulated pollutants would be emitted
or captured. To accomplish such an outcome, the CVS to which the NIE
standard applies would have to be enclosed within another CVS or
similar permanent total enclosure for the regulated emissions to be
captured for subsequent control or venting. According to the commenter,
requiring such a system would be inordinately costly, highly
impracticable, and likely impossible. The commenter pointed out that
this is precisely why LDAR standards have been expressed from the
inception of such programs almost exclusively as work practice
standards. The commenter concluded that the NIE standard cannot be
effectively construed as a zero-emissions standard, as the EPA
proposes, because no ``conveyance'' exists that allows for capture of
the regulated emissions and application of such a standard to an
emissions point. The commenter stated that the EPA must make it clear
that a CVS remains in compliance when a leak is detected, provided the
associated work practices requiring investigation and repair are
followed.
---------------------------------------------------------------------------
\641\ EPA-HQ-OAR-2021-0317-2565.
\642\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------
Response: As an initial matter, the EPA clarifies that CVS and
covers subject to the NIE standards are not fugitive components or any
other type of affected/designated facilities under NSPS OOOOb/EG OOOOc;
rather, they are part of the emission control for an associated
affected/designated facility (e.g., a wet seal centrifugal compressor,
a pneumatic pump, process controllers, or a tank battery) that is using
a control device to meet its performance standard. Accordingly, CAA
section 111(h), which authorizes the EPA to prescribe work practice and
other non-numeric standards for an affected/designated facility if it
is not feasible to prescribe an emission limitation performance
standard, does not apply to these covers and CVS.
Second, as explained in the preamble to the December 2022
Supplemental Proposal and reiterated above in this section, the NIE
standard that applies to covers and closed vent systems is a numeric
limitation to ensure that associated affected/designated facilities
comply with the 95 percent emission reduction standard when using a
control device. For example, the standard for a wet seal centrifugal
compressor affected facility is to reduce emissions by 95 percent; if a
control device is used, the owner or operator must equip the wet seal
fluid degassing system with a cover that routes emissions through a
closed vent system to a control device (see 40 CFR 60.5380b). Since the
rule allows owners and operators to use a control device with 95
percent control efficiency,\643\ compliance with the 95 percent
emission reduction standard would require assurance (through
demonstration) that all emissions are captured and routed via the CVS
to the control device. The NIE standard reflects this compliance
assurance and demonstration requirement and, for the reason explained
above, is an emission limitation of zero emissions, to be demonstrated
by OGI, EPA Method 21, or AVO inspection. Any identified emissions
would be a deviation of the NIE standard and must be reported.\644\ In
addition, the owner or operator must undertake the required
``corrective actions'' (in the form of the repair provisions) to bring
the CVS back into compliance with the NIE standard as quickly as
possible to ensure that the associated affected/designated facility is
in compliance with the 95 percent emission reduction standard.
---------------------------------------------------------------------------
\643\ The EPA considered but declined to require the use of
control devices with higher control efficiency in this rule. See
discussion in section IV.H.2 of the November 2021 Proposal, 87 FR
74794 (December 6, 2022).
\644\ A deviation is defined as a failure to meet any obligation
of the rule (including emission limits, operating limits, or work
practice standards). See 40 CFR 60.5430b and 40 CFR 60.5430c.
---------------------------------------------------------------------------
With respect to the comment that the ``zero-emissions'' NIE
standard is not realistic for equipment located outside, the EPA notes
that the requirement to operate the CVS or cover without emissions to
the atmosphere has previously been required in NSPS OOOO and OOOOa,
with compliance demonstrated by NDE. The EPA notes that the same
requirement can be found in other NSPS (see, e.g., NSPS for Volatile
Organic Liquid Storage Vessel, 40 CFR part 60, subpart Kb). CVS should
be properly designed to minimize the possibility of leaks; for example,
owners and operators should consider whether welded piping can be used
in place of connectors, whether low emission equipment (such as valves)
is appropriate for the CVS, which gaskets are most suitable for the
composition of materials in the CVS, and whether pressure setpoints are
appropriate for relief devices in the system. Owners and operators
should regularly inspect and perform maintenance on the CVS to prevent
equipment failure and subsequently prevent leaks from occurring.
Because the term NDE has historically been associated only with the
use of EPA Method 21, as we explained in the December 2022 Supplemental
Proposal, the EPA believes the term ``no identifiable emissions'' is
more suited for inspections conducted by OGI and AVO.\645\ Contrary to
the commenter's assertion, the EPA does not believe the NIE standard
using OGI is more stringent than the NDE standard using EPA Method 21.
When using EPA Method 21, a leak is considered to not be detected if
the monitoring instrument returns a reading below 500 ppmv (taking into
account background concentration). Based on the EPA's experience with
and understanding of OGI, while it is possible to detect leaks below
500 ppmv with an OGI camera in a laboratory, it is highly unlikely that
an OGI camera operator would be able to detect leaks below 500 ppmv in
the conditions experienced in the field. As such, it is unlikely that
owners and operators who conduct inspections of CVS and covers with OGI
will regularly find leaks that would not have been required to be
addressed had the owner or operator conducted the inspection with EPA
Method 21. Further, where an owner or operator is concerned about the
use of OGI for inspecting covers and CVS, the EPA is allowing EPA
Method 21 as an alternative. Consistent with NSPS OOOO and OOOOa,
emissions detected by AVO from covers and closed vent systems also are
identifiable emissions. Regarding the comment that the detection of
emissions above a certain threshold results in both a violation of the
standard and an obligation to undertake a repair within a specified
time period, the EPA believes that the repair obligations are necessary
to ensure that the CVS or cover is returned to a condition of NIE as
quickly as possible, which serves to limit deviations from the standard
for the affected/designated facility that uses the CVS. The EPA
recognizes that situations beyond the control of the owner or operator
may occur, but the emission standard applies at all times.
---------------------------------------------------------------------------
\645\ 87 FR 74805 (December 6, 2022).
---------------------------------------------------------------------------
L. Equipment Leaks at Natural Gas Processing Plants
In section X.L of this document, the final NSPS OOOOb and EG OOOOc
requirements for equipment leaks at natural gas processing plants are
summarized. The BSER analyses for leaks from both new and existing
process unit equipment at natural gas processing plants are unchanged
from what was presented in the November 2021 Proposal (see 86 FR 63231-
33, section XII.G: Proposed Standards for Equipment Leaks at Natural
Gas
[[Page 16987]]
Processing Plants). Specifically, the EPA identified a bimonthly OGI
LDAR program following appendix K that includes all equipment
components that have the potential to emit VOC or methane to be BSER
for both new and existing process unit equipment at natural gas
processing plants. However, significant comments were received on the
December 2022 Supplemental Proposal on the following topics: potential
to emit methane and VOC; and the use of low-E equipment for repair. For
each of these topics, a summary of the proposed rule, the comments, the
EPA responses, and changes made in the final rule (if applicable), are
discussed here. These comments and the EPA's responses to these
comments generally apply to both NSPS OOOOb and EG OOOOc. The instances
where the comment and/or response only applies to NSPS OOOOb or EG
OOOOc are noted. Comments and changes relevant to appendix K are
discussed in section XIV of this preamble. The EPA's full response to
comments on the November 2021 Proposal and December 2022 Supplemental
Proposal, including any comments not discussed in this preamble, can be
found in the EPA's RTC document for the final rule.\646\
---------------------------------------------------------------------------
\646\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
---------------------------------------------------------------------------
1. Potential To Emit Methane and VOC
In the November 2021 Proposal (86 FR 63181), the EPA proposed not
to carry over to NSPS OOOOb the VOC concentration threshold in NSPS
OOOOa that excludes certain equipment within a process unit from the
LDAR requirements at natural gas processing plants. In NSPS OOOOa,
while the affected facility included equipment that is in contact with
a process fluid containing methane or VOCs, the standards only applied
to equipment ``in VOC service,'' which ``means the piece of equipment
contains or contacts a process fluid that is at least 10 percent VOC by
weight.'' The EPA explained in the November 2021 Proposal that because
a VOC concentration threshold has no relationship to the LDAR for
methane, it is not an appropriate threshold for determining whether
LDAR for methane applies. Further, the EPA explained that because there
was no threshold for requiring LDAR for methane, any equipment not ``in
VOC service'' still would be required to conduct LDAR for methane, even
if not for VOC, which made the VOC concentration threshold irrelevant.
In December 2022, the EPA proposed to apply the LDAR standards to
process unit equipment that has the potential to emit methane or VOC,
consistent with the November 2021 Proposal. The EPA also added
provisions that each piece of equipment is presumed to emit methane or
VOC unless the owner or operator demonstrates that the piece of
equipment does not have the potential to emit methane or VOC. The EPA
provided regulatory provisions for the demonstration, namely, that the
owner or operator would have to show that the process fluid did not
contain either methane or VOC.
Comment: Commenters \647\ on the November 2021 Proposal requested
that the EPA retain the ``in VOC service'' requirement and 10 percent
VOC by weight threshold, as well as establish a 1 percent threshold for
equipment in methane service. The commenters reiterated concerns
expressed in response to the November 2021 Proposal that some streams,
such acid and amine gas, ethane product streams, produced water
streams, and wastewater streams should be excluded and that a 1 percent
by weight methane concentration threshold would serve to exclude such
streams. Otherwise, both commenters expressed concern that owners and
operators would waste substantial resources to conduct LDAR monitoring
on components that will always result in non-detects.
---------------------------------------------------------------------------
\647\ EPA-HQ-OAR-2021-0317-2399 and -2428.
---------------------------------------------------------------------------
One of the commenters \648\ questioned the EPA's analysis in the
November 2021 Proposal. The commenter states that the EPA appears to
only consider components in VOC service (defined as defined as 10
percent by VOC by weight or in wet gas service) or in non-VOC service
(defined as a component in methane service with at least 10 percent
methane that is not also in VOC service). The commenter states that the
EPA then estimates VOC and methane emissions, reductions, and cost
effectiveness using a limited set of composition ratios,\649\ then
appears to treat the ``potential to emit methane'' as equivalent to
``in non-VOC service'' in evaluating control options. Therefore, the
commenter states, the EPA does not appear to fully consider the cost
effectiveness of a ``potential to emit'' applicability threshold.
---------------------------------------------------------------------------
\648\ EPA-HQ-OAR-2021-0317-2428.
\649\ The commenter (-2428) refers to Table 10-8 of the TSD. See
EPA-HQ-OAR-2021-0317-0166.
---------------------------------------------------------------------------
Response: The EPA is not including a VOC or methane threshold in
the final rule. In response to these comments, the EPA explained in the
December 2022 Supplemental Proposal that ``no additional data or
analyses were provided to demonstrate that a threshold of one percent
by weight methane would be appropriate. Further, recent studies
indicate that produced water and wastewater streams can be significant
sources of VOC and/or methane emissions'' (87 FR 74808). In addition,
no basis is provided for how removing ``in VOC service'' would
substantially increase costs.
2. Low-E Technology for Repair
In the November 2021 Proposal, the EPA proposed repair requirements
for leaking equipment. The EPA proposed that the definition of
``repaired'' (for equipment) is that the equipment is adjusted,
replaced, or otherwise altered, in order to eliminate equipment leaks
and that the equipment is re-monitored to verify that emissions from
the equipment are below the leak definition. The EPA explained that
valve repairs can include replacement with low-emissions (low-E)
valves, valve packing, or drill-and-tap with a low-E injectable (``low-
E equipment'') but did not require replacement with low-E equipment.
The EPA explained that low-E equipment meets the specifications of API
622 or API 624 and typically includes a manufacturer written warranty
or a performance guarantee that it will not emit fugitive emissions at
a concentration greater than 100 ppmv during the first 5 years. 86 FR
63182.
In the December 2022 Supplemental Proposal, the EPA proposed a
definition of ``repaired'' (for equipment) consistent with that
discussed in the November 2021 Proposal, and added that pumps subject
to weekly visual inspections, which are designated as leaking and then
repaired, are not subject to re-monitoring. The EPA did not propose to
require the replacement of leaking valves with low-E equipment, noting
that the technology is not appropriate for all repairs, but reiterated
the position from the November 2021 Proposal that due to the
performance expectations, low-E equipment can be a viable option for
valve repair, as demonstrated by the re-monitoring requirements of the
rule. 87 FR 74808.
Comment: Commenters \650\ urged the EPA to require replacement of
leaking equipment with low-E valves. The commenter cited to a recent
rulemaking, where Colorado found these options to be similar in cost to
non-low-E valves and packing and directed operators to
[[Page 16988]]
consider them.\651\ The commenter also referenced claims from some
manufacturers that their low-E packing can reduce emissions of harmful
gases by up to 95 percent versus valves with traditional packing, with
minimal cost impacts.\652\
---------------------------------------------------------------------------
\650\ EPA-HQ-OAR-2021-0317-2433.
\651\ See Colorado Air Pollution Control Division, Rebuttal
Prehearing Statement, Proposed Revisions to Regulation Numbers 7 and
22 (Dec. 14-17, 2021).
\652\ Id.
---------------------------------------------------------------------------
Response: The commenter's understanding of the cost for low-E
equipment aligns with that of the EPA in that they are similar in cost
to non-low-E equipment. Therefore, replacing leaking valves with low-E
equipment would result in lower emissions with no additional cost
burden (compared to using non-low-E equipment). However, as explained
in the two proposals and reiterated above, the EPA believes that the
low-E technology is not appropriate for all valve repairs, and the EPA
did not receive comments disagreeing or suggesting otherwise.
Therefore, the final NSPS OOOOb and the presumptive standard in EG
OOOOc require replacing leaking valves with low-E valves or repacking
existing valves with low-E packing, except where it is not technically
feasible. If delay of repair is required to repack or replace the
valve, you may use delay of repair provisionally, but no later than the
next process unit shutdown. Technical infeasibility includes situations
where low-E equipment is not suitable for the existing valves' intended
use. Other factors that may be considered in determining technical
infeasibility include: retrofit requirements for installation (e.g.,
re-piping or space limitation), commercial unavailability for valve
type, or certain instrumentation assemblies. Owners or operators are
required to report annually on instances where it was infeasible to
replace leaking valves with low-E valves or repack existing valves with
low-E packing technology, including the reasoning for why it was
infeasible.
M. Sweetening Units
In section X.M of this document the final NSPS OOOOb requirements
for sweetening units are summarized. In November 2021 and December
2022, the EPA proposed to retain the standards found in NSPS OOOO and
NSPS OOOOa for reducing SO2 emissions from sweetening units.
No comments were received in opposition to the December 2022
Supplemental Proposal and the standards are being finalized as
proposed.
XII. Significant Comments and Changes Since Proposal for NSPS OOOOa and
NSPS OOOO
As described in sections IV and VIII of the November 2021 Proposal
(86 FR 63133-37, 63147-53), the 2020 Policy Rule rescinded all NSPS
regulating emissions of VOC and methane from sources in the natural gas
transmission and storage segment of the oil and natural gas industry
and NSPS regulating methane from sources in the industry's production
and processing segments. As a result, the 2020 Technical Rule only
amended the VOC standards for the production and processing segments in
the 2016 NSPS OOOOa, because those were the only standards that
remained at the time that the 2020 Technical Rule was finalized.
Under the CRA, a rule that is subject to a joint resolution of
disapproval ``shall be treated as though such rule had never taken
effect.'' 5 U.S.C. 801(f)(2). Thus, because it was disapproved under
the CRA, the 2020 Policy Rule is treated as never having taken effect.
As a result, the requirements in the 2012 NSPS OOOO and 2016 NSPS OOOOa
that the 2020 Policy Rule repealed (i.e., the VOC and methane standards
for the transmission and storage segment, as well as the methane
standards for the production and processing segments) must be treated
as being in effect immediately upon enactment of the joint resolution
on June 30, 2021. The CRA resolution did not address the 2020 Technical
Rule; therefore, the amendments made in the 2020 Technical Rule, which
apply only to the VOC standards for the production and processing
segments in the 2016 NSPS OOOOa, have remained in effect. As a result,
sources in the production and processing segments have been subject to
two different sets of standards: One for methane based on the 2016 NSPS
OOOOa, and one for VOC that include the amendments to the 2016 NSPS
OOOOa made in the 2020 Technical Rule. Low production well sites, for
example, are now subject to semiannual methane leak detection and
repair requirements under the 2016 NSPS even while they continue to be
exempt from leak detection and repair for VOC emissions under the 2020
Technical Rule. Such affected facilities have been able to either
choose to comply with both sets of standards, which in most cases do
not conflict, or to comply with the more stringent standards, which are
those in the 2016 NSPS for methane. In this case, compliance with the
more stringent 2016 NSPS for methane also results in compliance with
the 2020 Technical Rule. Sources in the transmission and storage
segment are subject to the methane and VOC standards as promulgated in
either the 2012 NSPS OOOO or the 2016 NSPS OOOOa, as applicable. In
this rulemaking, the EPA updated the NSPS OOOO and NSPS OOOOa
regulatory text in the CFR to reflect the CRA resolution's disapproval
of the final 2020 Policy Rule, specifically, the reinstatement of the
NSPS OOOO and NSPS OOOOa requirements that the 2020 Policy Rule
repealed but that came back into effect immediately upon enactment of
the CRA resolution. The proposed regulatory text changes for NSPS OOOO
and NSPS OOOOa to reflect the CRA resolution were included in the
rulemaking docket when the EPA issued the November 2021 Proposal and
are being finalized as proposed.
In addition to aligning the NSPS OOOO and NSPS OOOOa regulatory
text in the CFR to reflect the CRA resolution's disapproval of the
final 2020 Policy Rule, the November 2021 Proposal (at 86 FR 63157-69,
November 15, 2021) also included a series of proposed amendments to
2016 NSPS OOOOa for methane to align the 2016 methane standards with
the current VOC standards (which were modified by the 2020 Technical
Rule). Those amendments included requirements for well completions,
pneumatic pumps, closed vent systems, fugitive emissions, AMEL, and
onshore natural gas processing plants, along with other technical
clarifications and corrections. The November 2021 Proposal preamble
described the supporting rationales that were provided in the 2020
Technical Rule for modifying the requirements applicable to the VOC
standards and explained why the amendments would also appropriately
apply to the reinstated methane standards. Most commenters on the
November 2021 Proposal provided general support for the retention of
certain aspects of the 2020 Technical Rule, including the corresponding
regulatory amendments to NSPS OOOOa. No significant comments were
received in opposition to these proposed regulatory amendments, and
they are being finalized as proposed.
Also, in the November 2021 Proposal, the EPA proposed to repeal
some of the amendments that were part of the 2020 Technical Rule.
Specifically, the EPA proposed to repeal its amendments in the 2020
Technical Rule that (1) exempted low production well sites from
monitoring fugitive emissions and (2) changed quarterly monitoring to
semiannual monitoring of VOC emissions at gathering and boosting
[[Page 16989]]
compressor stations. The EPA is finalizing the repeal of these
amendments and subsections XII.A and B of this document discuss the
comments received on the rescission of these proposed amendments and
the EPA's response to those comments.
In addition to the November 2021 proposed amendments, commenters
also requested changes to NSPS OOOOa that were also recommended to be
made to NSPS OOOOb and EG OOOOc. These changes include allowing for
delay of repair for when equipment necessary for repair is unavailable
and clarifying the source category scope of the rule (e.g., excludes
facilities located inside and including the Local Distribution Company
(LDC) custody transfer station). The EPA is making changes based on
these comments in the final rule. Specifically, the EPA has revised 40
CFR 60.5397a(h)(3) to allow for a delay of repair due to the lack of
availability of parts in some circumstances and has revised the
introductory language at 40 CFR 60.5365a of the final rule to clarify
that the Crude Oil and Natural Gas Production source category excludes
facilities located inside and including the LDC custody transfer
station. Section XII.C discusses the comments received and the EPA's
response to comments related to delay of repair, and section XII.D
discusses the comments received and the EPA's response to comments on
the need to clarify the source category scope of the rule. The EPA's
full response to comments on the November 2021 Proposal and December
2022 Supplemental Proposal, including any comments not discussed in
this preamble, can be found in the EPA's RTC document for the final
rule.\653\
---------------------------------------------------------------------------
\653\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
---------------------------------------------------------------------------
A. Low Production Well Site Exemption Rescission
The EPA proposed (86 FR 63158-59) to remove the exemption of low
production well sites from fugitive VOC emissions monitoring, thereby
restoring the semiannual monitoring requirement established in the 2016
NSPS OOOOa.
Comment: Several commenters \654\ objected to the proposal to
repeal the amendments in the 2020 Technical Rule that exempted low
production well sites from monitoring fugitive VOC emissions under the
NSPS (86 FR 63118). These commenters urged the EPA to retain the
exemption, citing concerns about the cost impacts of removing the
exemption as well as objections to the EPA's emissions baseline
analysis.
---------------------------------------------------------------------------
\654\ EPA-HQ-OAR-2021-0317-0577, -0803, -0824, and -0464.
---------------------------------------------------------------------------
Commenters \655\ stated that the repeal of the exemption for low
production well sites from monitoring fugitive emissions would result
in adverse impacts to owners and operators, especially owners and
operators of small-scale, independent well site operations. One of the
commenters stated that the repeals of the exemption for low production
well sites from monitoring fugitive emissions would affect many
stripper wells in Wyoming (defined by the Wyoming Oil and Gas
Conservation Commission (WOGCC) as wells that produce an average of 15
barrels of crude oil (bbl) or less per day) and some very small-scale,
independent well site operations that strictly operate on a single
owner's private property. According to the WOGCC, Wyoming has
approximately 6,524 stripper wells. The commenter is concerned about
the potential adverse economic impacts of these proposed regulations
upon individual operators and the greater economy of the state of
Wyoming and states that the economic impacts outweigh the indeterminate
and potentially marginal environmental benefits of the proposal. The
commenter added that the cost of compliance with these requirements is
simply unworkable for many smaller operators in Wyoming and some
operators have already expressed concerns to WDEQ that they will go out
of business due to the EPA's proposed requirements. The other commenter
stated that the removal of the low production well exemption would have
significant detrimental impacts on their operations, costs, overhead,
reserve recovery, plugging costs, and employment. The commenter noted
that every increase in cost directly jeopardizes their ability to
produce marginal wells.
---------------------------------------------------------------------------
\655\ EPA-HQ-OAR-2021-0317-0464 and -0824.
---------------------------------------------------------------------------
One commenter \656\ suggested that removing the exemption for low-
producing wells from fugitive emissions monitoring in NSPS OOOOa could
result in tens of thousands of additional affected facilities and/or
projects establishing PTE below affected source emissions levels. The
commenter added that changing this requirement may also result in some
facilities becoming an affected facility retroactively.
---------------------------------------------------------------------------
\656\ EPA-HQ-OAR-2021-0317-0763.
---------------------------------------------------------------------------
Another commenter \657\ recommended that the EPA consider the
small, low-emitting nature of Pennsylvania and New York conventional
oil and gas production before imposing any additional requirements in
the NSPS OOOOa (and NSPS OOOOb and EG OOOOc) revisions.
---------------------------------------------------------------------------
\657\ EPA-HQ-OAR-2021-0317-1341.
---------------------------------------------------------------------------
A couple of commenters \658\ also requested that the EPA more
thoroughly evaluate emissions and costs of control of marginal/low
production well sites. One of the commenters requested that the EPA
first determine if marginal well emissions warrant regulation. The
commenter noted that the DOE was conducting a study to better
characterize emissions from these types of wells. The commenter stated
that E.O. 13990 requires the Federal Government, ``. . . be guided by
the best science and be protected by processes that ensure the
integrity of Federal decision-making.'' As such, the commenter
recommended that the EPA defer regulating marginal/low production wells
until the DOE report was available for review or collect additional
data to fully determine the emissions profile of these types of wells,
determine if requirements are needed, and if needed, develop an
appropriate regulatory program. Similarly, the other commenter
suggested that they are aware of at least one study underway to
evaluate methane emissions from marginal wells, and that there may be
others. The commenter contends that, if the study's findings
demonstrate that these methane emissions contributions from low
production well sites do not contribute in any significant manner, the
commenter expressed that it is imperative that the EPA consider these
findings and provide appropriate exemptions.
---------------------------------------------------------------------------
\658\ EPA-HQ-OAR-2021-0317-0810 and -0824.
---------------------------------------------------------------------------
One commenter \659\ stated that marginal wells are not a
significant source of methane and that emissions from a well are
proportionate to the volume of oil and/or gas produced. As a result,
the commenter stated that marginal wells produce significantly fewer
emissions because they are marginal producers of oil and gas. According
to the commenter, emissions from their wells are much lower than those
emitted from high volume wells produced by larger companies. The
commenter expressed that it is unfair and unwise to treat small
operators with marginal wells in the same manner as larger producers.
The commenter suggested that marginally producing wells be exempt from
the EPA rules because the emissions are insignificant, and the rules
would be uneconomic. The commenter further requested that
[[Page 16990]]
there be a regulatory ``off ramp'' for low-producing wells such as
theirs.
---------------------------------------------------------------------------
\659\ EPA-HQ-OAR-2021-0317-0464.
---------------------------------------------------------------------------
Response: As discussed in the December 2022 Supplemental Proposal,
the EPA solicited comment in the November 2021 Proposal on regulatory
alternatives and additional information that would warrant considering
a subset of sites differently based on a potentially different
emissions profile, production levels, equipment onsite, or other
factors. The EPA examined data provided through an ICR distributed in
2016, data provided on equipment/component counts in relation to the
October 15, 2018, proposed reconsideration of NSPS OOOOa from
independent producers (many of whom are small businesses), data
provided through comments on the November 2021 Proposal from
independent producers, and data contained in the U.S. DOE marginal well
study to determine if a subset of well sites with major production and
processing equipment should be considered differently.
Consistent with comments received on previous rulemakings, the EPA
received comments on the November 2021 Proposal expressing that
emissions from a well are proportionate to the volume of oil and/or gas
produced.\660\ Commenters also referenced the U.S. DOE marginal well
study. However, the U.S. DOE marginal well study (now available)
concludes that the frequency and magnitude of emissions from well sites
are more strongly correlated with equipment counts, not production
rates.\661\ Further, this study broke down emissions by site size and
production levels and found that the smallest emissions rates were from
the second production level bin (2 barrels of oil equivalent per day
(boe/day) to 6 boe/day) and not the lowest-producing sites (production
less than 2 boe/day). Another study issued in April 2022 by Omara, et
al., concludes that approximately half of the methane emissions emitted
from well sites in the U.S. comes from low production well sites
(defined in that study as 15 boe/day or less production
rates).662 663 However, the EPA notes that this study is not
limited to fugitive emissions, and the overall impacts on emissions
reductions achieved under NSPS OOOOa (and NSPS OOOOb and EG OOOOc) if
these rules are finalized as proposed, would target the emissions
reported in that study as a whole. Therefore, the EPA does not have
compelling information that suggests production levels should provide
the basis for consideration of different fugitive emissions
requirements for well sites.
---------------------------------------------------------------------------
\660\ See Document ID No. EPA-HQ-OAR-2021-0317-0464.
\661\ Section 5.2.1 of the study concludes, ``The correlation
between major equipment counts and site emission frequency
(expressed as the number of detected emissions per piece of major
equipment, i.e., not absolute count of emissions), was strong with
the categorical site `size' variable and moderate (positive) with
the numeric equipment count. Among evaluated numeric variables, site
equipment counts also exhibited the strongest associations with both
frequency and magnitude of sitewide emissions, exhibiting only a
moderate positive correlation with detection frequency and weak
associations with whole gas and methane emission rates. Weak
correlations were also consistently detected among both the
frequency and magnitude of emissions, total oil and gas production,
and gas production rates.'' See Bowers, Richard L. Quantification of
Methane Emissions from Marginal (Low Production Rate) Oil and
Natural Gas Wells. https://www.osti.gov/biblio/1865859. page 19.
\662\ Omara, M., Zavala-Araiza, D., Lyon, D.R., et al. Methane
emissions from US low production oil and natural gas well sites. Nat
Commun 13, 2085 (2022). https://doi.org/10.1038/s41467-022-29709-3.
\663\ The EPA notes that Omara, et al., analyzed data from
offsite measurements of methane emissions from well sites. These
measurements would include methane from any leak, venting, flaring,
or other source onsite and, therefore, conclusions from this study
cannot be directly applied to the specific fugitive sources covered
by this action.
---------------------------------------------------------------------------
As stated in the November 2021 Proposal, the EPA remains mindful
about how the fugitive emissions monitoring requirements will affect
small businesses. The EPA discusses the financial conditions of
marginal wells in chapter 6 of the final rule TSD. There are many
factors that might affect the profitability of marginal wells and the
decision to shut in and plug a well, making it difficult to determine
the full impact of regulation on the financial status of marginal well
owners. The EPA has also taken steps to include regulatory flexibility
and streamline recordkeeping requirements in the fugitive emissions
standards of NSPS OOOOa.
The EPA is therefore finalizing the proposed (86 FR 63158-59)
removal of the exemption of low production well sites from fugitive VOC
emissions monitoring, thereby restoring the semiannual monitoring
requirement established in the 2016 NSPS OOOOa.
B. Compressor Station Quarterly Monitoring
The EPA proposed to repeal its amendment to the VOC monitoring
frequency for gathering and boosting compressor stations in the 2020
Technical Rule because the EPA believed that amendment was made in
error. 86 FR 63159
Comment: Some commenters \664\ expressed opposition to the proposal
and requested that fugitive emissions monitoring at compressor stations
only be required on a semiannual basis. One commenter contended that a
requirement for more frequent monitoring would be unduly burdensome,
given that one pipeline system could have numerous compressor stations
that are often located in remote areas. In addition, the commenter
stated that the resources (both personnel and equipment) to comply with
survey requirements may be limited, a concern that the commenter says
that the EPA itself acknowledged in the preamble for the initial NSPS
OOOOa Proposal. Moreover, the commenter stated that the leak rate in
the gathering and boosting industry segment is particularly low. The
commenter urged the EPA to retain the current requirement of semiannual
monitoring for fugitive emissions at compressor stations, including
gathering and boosting compressor stations. Similarly, another
commenter suggested that it is overly burdensome to require quarterly
compressor monitoring in respect to surveys and recordkeeping. The
commenter noted that the value of increased monitoring to reduce small
amounts of methane and VOC does not offset the associated expense and
manpower required to fulfill the proposed regulations. The commenter
suggested that a baseline for compressor stations could be undertaken
as a similar proposal for less than 3 tpy well sites to determine
future requirements of a particular site.
---------------------------------------------------------------------------
\664\ EPA-HQ-OAR-2021-0317-0755 and -0923.
---------------------------------------------------------------------------
Another commenter \665\ also suggested that changing the monitoring
frequency for the transmission and storage segments from semiannual to
quarterly creates confusion with the other actions taken in 2021
regarding NSPS OOOOa as these facilities have transferred back and
forth between affected facility status due to policy changes within the
existing NSPS OOOOa.
---------------------------------------------------------------------------
\665\ EPA-HQ-OAR-2021-0317-0763.
---------------------------------------------------------------------------
Response: As stated in the December 2022 Supplemental Proposal, the
analyses the EPA conducted for NSPS OOOOb and EG OOOOc confirm that
quarterly monitoring remains both achievable and cost-effective for
compressor stations, and several state agencies have rules that require
quarterly monitoring at compressor stations. The cost analysis
conducted for the November 2021 Proposal was a comprehensive evaluation
of emissions, reductions, and costs associated with various leak
detection and repair programs, which firmly established that the cost
effectiveness of quarterly monitoring for compressor stations is
[[Page 16991]]
reasonable. The November 2021 Proposal established that BSER for
reducing methane and VOC emissions from all compressor stations,
including gathering and boosting stations, transmission stations, and
storage stations was quarterly monitoring. In the December 2022
Supplemental Proposal, the EPA retained the proposed quarterly OGI (or
EPA Method 21) monitoring requirement for fugitive emissions components
affected facilities located at compressor stations. Although some
commenters oppose quarterly monitoring, they express no disagreement
with EPA's BSER analysis; rather, they find quarterly monitoring
unnecessarily burdensome or may cause confusion after allowing semi-
annual monitoring in the 2020 amendment, none of which are reasons for
the EPA not to restore the monitoring frequency that reflects the BSER.
Therefore, based on the reasoning provided in the November 2021
Proposal that the EPA lacked justification and erred in revising the
VOC monitoring frequency for gathering and boosting compressor stations
from quarterly to semiannual and that the cost effectiveness of
quarterly monitoring for compressor stations is reasonable, the EPA is
finalizing the restoration of the quarterly monitoring requirement for
gathering and boosting compressor stations, as established in the 2016
NSPS OOOOa.
C. Delay-of-Repair Provisions
Comment: Some commenters requested changes to NSPS OOOOa that were
also recommended to be made to NSPS OOOOb and EG OOOOc. One of those
requested changes was to allow for a delay of repair when parts are
unavailable to do the required repairs. One commenter \666\ supported
reconciling NSPS OOOOa delay-of-repair regulatory text consistent with
the 2020 Technical Rule. However, the commenter also recommended that
the delay-of-repair text be amended to address the delay necessary when
parts are unavailable, an issue that they believe is especially
important for existing sources. The comments summarized in section
XI.A.2.b were generally intended for NSPS OOOOa as well as NSPS OOOOb
and EG OOOOc.
---------------------------------------------------------------------------
\666\ EPA-HQ-OAR-2021-0317-0782.
---------------------------------------------------------------------------
Response: Based on these comments, the EPA is amending 40 CFR
60.5397a(h)(3) to allow the delay of repairs due to the lack of
availability of parts with provisions identical to those of NSPS OOOOb
and EG OOOOc. NSPS OOOOa has been revised to allow for delay of repair
due to unavailability of parts if replacement parts are necessary and
cannot be acquired within the repair timeline if either replacement
part supplies had been sufficiently stocked before the supplies were
depleted or a replacement part requires custom fabrication. Replacement
parts must be ordered within 10 calendar days after the first attempt
at repair. The repair must be completed within 30 calendar days after
receipt of the replacement parts or during the next scheduled shutdown
for maintenance after the parts are received (if the repair requires a
shutdown). As the EPA was considering provisions allowing for delay of
repair due to parts unavailability for sources regulated under NSPS
OOOOb and EG OOOOc, the EPA found that the supplemental information
submitted and reasoning for allowing delay of repair due to parts
unavailability under NSPS OOOOb and EG OOOOc is equally applicable to
sources regulated under NSPS OOOOa and, for that reason, is also
including the provision in 40 CFR 60.5397a(h)(3).
D. Applicability/Scope of the Rule
Comment: As noted above, some commenters requested changes to NSPS
OOOOa that were also recommended to be made to NSPS OOOOb and EG OOOOc.
One of those requested changes was to add greater clarity regarding the
applicability/scope of the rule.
One commenter \667\ stated that because their members are small
without access to significant resources to fully analyze complex
rulemakings, it is important that the scope of the rule be made as
clear as possible. The commenter requested that the EPA include the
following underlined text in NSPS OOOOa at 40 CFR 60.5365a and in
appropriate, corresponding sections of NSPS OOOOb and EG OOOOc
(underlined text reflects their recommended additions):
---------------------------------------------------------------------------
\667\ EPA-HQ-OAR-2021-0317-0928.
---------------------------------------------------------------------------
Sec. 60.5365a Am I subject to this subpart?
You are subject to the applicable provisions of this subpart if
you are the owner or operator of one or more of the onshore affected
facilities listed in paragraphs (a) through (j) of this section,
that is located within the Crude Oil and Natural Gas Production
source category, as defined in Sec. 60.5430, for which you commence
construction, modification, or reconstruction.
Similarly, another commenter \668\ stated that a small gas utility
or cooperative that does not have an environmental lawyer on staff may
not understand that the rule applies only to facilities that are
located within the Crude Oil and Natural Gas Production source category
as defined in 40 CFR 60.5430a, and that they need to refer to the
definitions section toward the end of the rule to discover that the
source category does not include operations inside and including the
LDC custody transfer station, and that the subpart only applies to
facilities in the defined source category. The commenter stated that
clarifying language was added to 40 CFR 60.5365a in the 2020 Policy
Rule.\669\ At a minimum, the commenter suggested that similar language
be restored in NSPS OOOOa and included in the new scope provisions of
NSPS OOOOb and EG OOOOc to clarify that facilities inside and including
the LDC custody transfer station are not subject to the subpart. The
commenter urged the EPA to include the following text in 40 CFR
60.5365a and in the analogous scope sections of NSPS OOOOb and EG
OOOOc:
---------------------------------------------------------------------------
\668\ EPA-HQ-OAR-2021-0317-0815.
\669\ 85 FR 57029-30, September 14, 2020.
You are subject to the applicable provisions of this subpart if
you are the owner or operator of one or more of the onshore affected
facilities listed in paragraphs (a) through (j) of this section,
that is located within the Crude Oil and Natural Gas Production
source category, as defined in Sec. 60.5430a. Facilities located
inside and including the LDC custody transfer station are not
---------------------------------------------------------------------------
subject to this subpart.
Response: The EPA considered the comments provided and agrees that,
while the definitions section clearly defines the boundaries of the
source category, additional clarification in the applicability section
of the subpart, with respect to LDC custody transfer, would further
assist sources in identifying whether they are subject to any of the
requirements in NSPS OOOOa. Therefore, the final rule includes the
following introductory language at 40 CFR 60.5365a:
You are subject to the applicable provisions of this subpart if
you are the owner or operator of one or more of the onshore affected
facilities listed in paragraphs (a) through (j) of this section,
that is located within the Crude Oil and Natural Gas Production
source category, as defined in Sec. 60.5430a, for which you
commence construction, modification, or reconstruction after
September 18, 2015, and on or before December 6, 2022. Facilities
located inside and including the Local Distribution Company (LDC)
custody transfer station are not subject to this subpart.
[[Page 16992]]
XIII. Significant Comments and Changes to Emission Guidelines for
State, Tribal, and Federal Plan Development for Existing Sources
A. Overview
In the December 2022 Supplemental Proposal, the EPA proposed
adjustments from the November 2021 Proposal, and additional
requirements to provide states with information needed for purposes of
state plan development. In the following sections of this preamble, in
the same six-part organizational ordering as the December 2022
Supplemental Proposal, we summarize significant comments and changes
since the December 2022 Supplemental Proposal for purposes of the final
EG. We also discuss the interaction of these final EG with recently
finalized revisions to the CAA section 111(d) implementing regulations,
40 CFR part 60 subpart Ba (subpart Ba).\670\ The EPA proposed these EG
in accordance with the version of subpart Ba that existed at the time
of proposal. However, since the recent revisions to subpart Ba are now
final and are therefore applicable to these EG, the final version of
these EG comports with the revised version of subpart Ba. Further,
states developing plans in accordance with EG OOOOc must follow the
recently revised version of subpart Ba, except where these EG expressly
supersede the requirements of subpart Ba. The EPA discusses the
importance of these changes in more detail later in this preamble.
---------------------------------------------------------------------------
\670\ 88 FR 80480 (November 17, 2023).
---------------------------------------------------------------------------
First, we discuss components of the final EG. Second, we discuss
the requirements for establishing standards of performance in state
plans. Third, we discuss the components of an approvable state plan
submission. Fourth, we discuss the final timing for state plan
submissions, and final timeline for designated facilities to come into
final compliance with the state plan. Fifth, we discuss the EPA's
action on state plans and the promulgation of Federal Plans. Sixth, we
discuss Tribes and the planning process for Tribal plans under CAA
section 111(d).
B. Components of EG
As explained in the November 2021 Proposal, CAA sections 111(d)(1)
and 111(a)(1) collectively establish and define certain roles and
responsibilities for the EPA and the states. The EPA addresses its
responsibilities by drafting and publishing EG in accordance with 40
CFR 60.22a, which ``[contain] information pertinent to control of the
designated pollutant from designated facilities.'' Mirroring language
included in CAA section 111(d)(1), the EPA's implementing regulations
define a designated pollutant as ``any air pollutant, the emissions of
which are subject to a standard of performance for new stationary
sources, but for which air quality criteria have not been issued and
that is not included on a list published under section 108(a) or
section 112(b)(1)(A) of the Act.'' 40 CFR 60.21a(a). The EPA's
implementing regulations also define a designated facility as ``any
existing facility (see Sec. 60.2) which emits a designated pollutant,
and which would be subject to a standard of performance for that
pollutant if the existing facility were an affected facility (see Sec.
60.2).'' Id. at Sec. 60.21a(b). The designated pollutant for purposes
of the final EG OOOOc included in this rulemaking is GHGs, but the
presumptive standards in the EG are expressed in terms of limitations
on methane. A description of each of the designated facilities included
in the final EG OOOOc can be found in sections X and XI of this
preamble.
More specifically, 40 CFR 60.22a(b) lists six components to be
included in EG to provide information for development of the state
plans triggered by the promulgation of the EG. Within the November 2021
Proposal, the EPA explained how the proposed EG OOOOc satisfied these
regulatory requirements. 86 FR 63110, 63248-49 (November 15, 2021).
Within the December 2022 Supplemental Proposal, the EPA elaborated on
several of these components. 87 FR 74702, 74816 and 74834 (December 6,
2022). The recent revisions to subpart Ba did not alter 60.22a(b) in
any meaningful way, so the analysis provided in the proposals remains
relevant and satisfactory. In addition, the EPA has included
information in this final rulemaking action that updates and
supplements that analysis. First, the EG must include information
regarding the ``endangerment of public health or welfare caused, or
contributed to, by the designated pollutant.'' 40 CFR 60.22a(b)(1).
Information on the harmful public health and welfare impacts of GHG
(methane) emissions from the oil and natural gas industry were included
in the November 2021 Proposal \671\ and are updated above in section
III of this document. Second, the EG must include a ``description of
systems of emission reduction which, in the judgment of the
Administrator, have been adequately demonstrated.'' 40 CFR
60.22a(b)(2). The EPA has included such a description in the November
2021 Proposal,\672\ in the November 2021 TSD,\673\ in the December 2022
Supplemental Proposal,\674\ in the December 2022 TSD,\675\ in sections
X and XI of this preamble, and in the final TSD located at Docket ID
No. EPA-HQ-OAR-2021-0317. Third, the EG must include information
regarding ``the degree of emission limitation'' achievable through
application of each system, along with information ``on the costs,
nonair quality health and environmental effects, and energy
requirements of applying each system to designated facilities.'' Id. at
60.22a(b)(3). The EPA has included such a description in the November
2021 Proposal,\676\ in the November 2021 TSD,\677\ in the December 2022
Supplemental Proposal,\678\ in the December 2022 TSD,\679\ in sections
X and XI of this preamble, and in the final TSD located at Docket ID
No. EPA-HQ-OAR-2021-0317. Fourth, the EG must include information
regarding the amount of time that the EPA believes would be normally
necessary for designated facilities to design, install, and startup the
control systems identified in component number three. See Id. at
60.22a(b)(4). The EPA proposed how to address this component in both
the November 2021 Proposal and the December 2022 Supplemental Proposal
and finalizes its explanation of how to address this component in
section XIII.E of this document. Fifth, and likely most helpful to
states when developing their plans, the EG must include information
regarding the ``degree of emission limitation achievable through the
application of the best system of emission reduction'' that has been
adequately demonstrated, taking into account the same factors as
described in component three (cost, nonair quality health and
environmental impact and energy requirements), ``and the time within
which compliance with standards of performance can be achieved.'' Id.
at 60.22a(b)(5). The EPA has included such information in the November
2021 Proposal; \680\ in the November 2021 TSD; \681\ in the December
2022 Supplemental Proposal; \682\ in the December 2022
[[Page 16993]]
TSD; \683\ in sections X, XI, and XIII.E of this preamble; and in the
final TSD located at Docket ID No. EPA-HQ-OAR-2021-0317. In identifying
the degree of achievable emission limitation, the EPA may
subcategorize, that is to ``specify different degrees of emission
limitation or compliance times or both for different sizes, types, and
classes of designated facilities when costs of control, physical
limitations, geographical location, or similar factors make
subcategorization appropriate.'' Id. The EPA has chosen to exercise
that discretion to subcategorize within the final EG for certain
designated facilities.\684\ Sixth, and last, the EG is to include any
other information not contemplated by the five other components that
the EPA ``determines may contribute to the formulation of State
plans.'' Id. at 60.22a(b)(6). Section XIII of this preamble includes
such information and guidance specifically designed to assist states in
developing and submitting their plans under CAA 111(d) for the final EG
OOOOc.
---------------------------------------------------------------------------
\671\ 86 FR 63124 (November 15, 2021).
\672\ 86 FR 63169-63240 (November 15, 2021).
\673\ EPA-HQ-OAR-2021-0317-0166.
\674\ 87 FR 74722-810 (December 6, 2022).
\675\ EPA-HQ-OAR-2021-0317-1578.
\676\ 86 FR 63169-240 (November 15, 2021).
\677\ EPA-HQ-OAR-2021-0317-0166.
\678\ 87 FR 74722-810 (December 6, 2022).
\679\ EPA-HQ-OAR-2021-0317-1578.
\680\ 86 FR 63169-240 (November 15, 2021).
\681\ EPA-HQ-OAR-2021-0317-0166.
\682\ 87 FR 74722-810 (December 6, 2022).
\683\ EPA-HQ-OAR-2021-0317-1578.
\684\ See sections X and XI of this preamble for detailed
discussion of the designated facilities for which the EPA is
including subcategories for.
---------------------------------------------------------------------------
C. Establishing Standards of Performance in State Plans
After the EPA provides information regarding the BSER in this final
EG, as described in preamble section XII of the November 2021 Proposal
and preamble section IV of the December 2022 Supplemental Proposal,
each state that has a designated facility located within the state must
develop, adopt, and submit to the EPA its state plan under CAA section
111(d). The state plan must include standards of performance for all
designated facilities. Under the TAR adopted by the EPA, Tribes may
seek authority to implement a plan under CAA section 111(d) in a manner
similar to a state. See 40 CFR part 49, subpart A. Tribes may, but are
not required to, seek approval for treatment in a manner similar to a
state for purposes of developing a TIP implementing the EG. The final
EG OOOOc addresses two key aspects of implementation, among other
issues: establishing standards of performance for designated facilities
and providing measures that implement and enforce such standards. In
this final EG, based on changes as a result of public comments, the EPA
finalizes updates to certain presumptive standards included in the
December 2022 Supplemental Proposal, and finalizes regulations related
to state flexibilities, certain implementation and enforcement
measures, and emissions inventories. The EPA is not finalizing in EG
OOOOc the proposed requirements related to meaningful engagement with
pertinent stakeholders, and electronic submittal of state plans, nor it
is finalizing certain proposed requirements related to the application
of a standard of performance to a particular designated facility that
is less stringent than otherwise required by the EG when taking into
consideration the facility's RULOF because such regulations are no
longer needed in this EG (OOOOc). Via a separate rulemaking process,
the EPA has finalized revisions to subpart Ba \685\ addressing the
framework for less stringent standards of performance pursuant to
RULOF, meaningful engagement with pertinent stakeholders, and
electronic submittal of state plans which are applicable to states
developing plans under these EG. Since these issues are addressed in
the final revisions to subpart Ba, and subpart Ba applies to states
developing plans under this EG (OOOOc), it would be redundant for the
EPA to also finalize the same provisions related to these issues within
EG OOOOc. As such, the EPA is not finalizing provisions specific to
these issues as proposed in the context of this EG (OOOOc) and is
instead deferring to subpart Ba on these issues. States should
carefully review the recent revisions to subpart Ba since subpart Ba
applies to state plans developed in accordance with this EG, except to
the extent that this EG supersedes subpart Ba (such as, for emissions
inventories and the deadline for state plan submittals, discussed in
later sections).
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\685\ 88 FR 80480 (November 17, 2023).
---------------------------------------------------------------------------
1. Establish Standards of Performance for Designated Facilities
As stated in the November 2021 Proposal, and reiterated in the
December 2022 Supplemental Proposal, the EPA's proposed EG OOOOc
included information on the degree of emissions limitation achievable
through application of the BSER in the form of presumptive standards
for designated facilities.\686\ The EPA described that there is a
fundamental requirement under CAA section 111(d) that a state's
standards of performance in its state plan submittal are no less
stringent than the presumptive standard determined by the EPA, which
derives from the definition of ``standard of performance'' in CAA
section 111(a)(1).\687\ The EPA is updating tables 25 and 26 to reflect
the final presumptive standards in the final EG OOOOc.
---------------------------------------------------------------------------
\686\ 86 FR 63169-63240 (November 15, 2021) and 87 FR 74722-810
(December 6, 2022).
\687\ CAA section 111(d)(1) also provides that states may apply
less stringent standards of performance to particular sources based
on consideration of such sources' remaining useful life and other
factors.
Table 25--Summary of Final EG Subpart OOOOc Presumptive Numerical
Standards
------------------------------------------------------------------------
Final presumptive numerical
Designated facility standards in the emissions
guidelines for GHGs
------------------------------------------------------------------------
Storage Vessels: Tank Battery with PTE 95 percent reduction of
of 20 tpy or more of methane. methane.
Process Controllers: Natural gas-driven Methane emissions rate of zero.
Pumps: Natural gas-driven.............. Methane emissions rate of zero.
------------------------------------------------------------------------
Table 26--Summary of Final EG Subpart OOOOc Presumptive Non-Numerical
Standards
------------------------------------------------------------------------
Final presumptive non-numerical standards
Designated facility in the emissions guidelines for GHGs
\688\
------------------------------------------------------------------------
Fugitive Emissions: Single Quarterly AVO monitoring surveys. First
Wellhead Only Well Sites and attempt at repair within 15 days after
Small Well Sites. detecting fugitive emissions. Final
repair within 15 days after first
attempt. Fugitive monitoring continues
for all well sites until the site has
been closed, including plugging the
wells at the site and submitting a well
closure report.
[[Page 16994]]
Fugitive Emissions: Multi- Quarterly AVO monitoring surveys. First
wellhead only Well Sites (2 attempt at repair within 15 days after
or more wellheads). detecting fugitive emissions. Final
repair within 15 days after first
attempt. Semiannual OGI monitoring
(Optional semiannual EPA Method 21
monitoring with 500 ppm defined as a
leak). First attempt at repair within 30
days after detecting fugitive emissions.
Final repair within 30 days after first
attempt. Fugitive monitoring continues
for all well sites until the site has
been closed, including plugging the
wells at the site and submitting a well
closure report.
Fugitive Emissions: Well Bimonthly AVO monitoring surveys. First
Sites and Centralized attempt at repair within 15 days after
Production Facilities. detecting fugitive emissions. Final
repair within 15 days after first
attempt. Quarterly OGI monitoring.
(Optional quarterly EPA Method 21
monitoring with 500 ppm defined as a
leak). First attempt at repair within 30
days after detecting fugitive emissions.
Final repair within 30 days after first
attempt. Fugitive monitoring continues
for all well sites until the site has
been closed, including plugging the
wells at the site and submitting a well
closure report.
Fugitive Emissions: Monthly AVO monitoring surveys. First
Compressor Stations. attempt at repair within 15 days after
detecting fugitive emissions. Final
repair within 15 days after first
attempt. AND Quarterly OGI monitoring.
(Optional quarterly EPA Method 21
monitoring with 500 ppm defined as a
leak). First attempt at repair within 30
days after detecting fugitive emissions.
Final repair within 30 days after first
attempt.
Fugitive Emissions: Well Annual OGI monitoring. (Optional annual
Sites and Compressor EPA Method 21 monitoring with 500 ppm
Stations on Alaska North defined as a leak). First attempt at
Slope. repair within 30 days after detecting
fugitive emissions. Final repair within
30 days after first attempt.
Process Controllers: Alaska Natural gas bleed rate no greater than 6
(at sites where onsite power scfh.
is not available--continuous
bleed natural gas-driven).
Process Controllers: Alaska OGI monitoring and repair of emissions
(at sites where onsite power from controller malfunctions.
is not available--
intermittent natural gas-
driven).
Pumps: Natural gas-driven (at Route pump emissions to a process if VRU
sites where onsite power is is onsite, or to control device if
not available and there are onsite.
fewer than 3 diaphragm
pumps).
Gas Well Liquids Unloading... Employ best management practices to
minimize or eliminate venting of
emissions to the maximum extent
possible.
Equipment Leaks at Natural LDAR with OGI following procedures in
Gas. Processing Plants. appendix K.
Oil Wells with greater than Route associated gas to a sales line.
40 tpy of Associated Methane Alternatively, the gas can be used as an
Gas. onsite fuel source or used for another
useful purpose that a purchased fuel or
raw material would serve or be injected
into the well or another well. If
demonstrated, and annually documented,
that a sales line and alternatives are
not technically feasible, the gas can be
routed to a flare or other control
device that achieves at least 95 percent
reduction in methane emissions.
Oil Wells with 40 tpy or less Route associated gas to a sales line.
of Associated Methane Gas. Alternatively, the gas can be used as an
onsite fuel source or used for another
useful purpose that a purchased fuel or
raw material would serve, or be injected
into the well or another well.
Alternatively, the gas can be routed to
a flare or other control device that
achieves at least 95 percent reduction
in methane emissions.
Wet Seal Centrifugal Monitoring and repair to maintain
Compressors (except for volumetric flow rate at or below 3 scfm
those located at well per compressor seal.
sites): Includes self-
contained wet seal
centrifugal compressors and
centrifugal compressors
equipped with mechanical
seals.
Wet Seal Centrifugal Monitoring and repair to maintain
Compressors (except for volumetric flow rate at or below 9 scfm
those located at well per seal.
sites): Alaska North Slope
centrifugal compressors
equipped with a seal oil
recovery system.
Dry Seal Centrifugal Monitoring and repair to maintain
Compressors (except for volumetric flow rate at or below 10 scfm
those located at well sites). per compressor seal.
Reciprocating Compressors Monitoring and repair to maintain
(except for those located at volumetric flow rate at or below 2 scfm
well sites). per compressor cylinder.
------------------------------------------------------------------------
\1\ Fugitive Emissions: Well Sites, Centralized Production Facilities,
and Compressor Stations: (Optional) Alternative periodic screening
with advanced measurement technology instead of OGI monitoring.
\2\ Fugitive Emissions: Well Sites, Centralized Production Facilities,
and Compressor Stations: (Optional) Alternative continuous monitoring
system instead of OGI monitoring.
The EPA received comments regarding the proposed presumptive
standards. A summary of some comments received and the EPA's response
to these comments, including any changes made to the final rule, as
applicable, are provided below. The EPA's full response to comments on
the November 2021 Proposal and December 2022 Supplemental Proposal,
including any comments not discussed in this preamble, can be found in
the EPA's RTC document for the final rule.\689\
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\688\ For fugitive emissions at well sites, centralized
production facilities, and compressor stations, the final EG
includes an advanced measurement technology compliance option to use
alternative periodic screening and alternative continuous monitoring
instead of OGI and AVO monitoring.
\689\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
---------------------------------------------------------------------------
[[Page 16995]]
Comment: The EPA received numerous comments that seem to object to
the general notion that a presumptive standard included in the EG can
be the same as a standard of performance under the NSPS. Commenters
contend that the EPA did not perform an appropriate BSER analysis for
existing sources and cannot simply apply the new source BSER to
existing sources without further explanation. Some commenters state
that EG OOOOc requirements should not be same as NSPS OOOOb
requirements, and that the cost of regulations for existing sources is
significantly higher than on new facilities, especially where there is
significant capital cost.
Response: In accordance with section 111(d) of the Clean Air Act
(CAA), states are tasked with developing plans which establish
standards of performance for existing sources. Further, in accordance
with CAA 111(d) and the EPA's implementing regulations, the EPA is to
publish EG for certain sources. Those guidelines are to include certain
information including ``[t]he degree of emission limitation achievable
through the application of the best system of emission reduction
(considering the cost of such achieving reduction and any nonair
quality health and environmental impact and energy requirements) that
has been adequately demonstrated for designated facilities.'' 40 CFR
60.22a(b)(5). The EG must also include: ``[i]nformation on the degree
of emission limitation which is achievable with each system, together
with information on the costs, nonair quality health environmental
effects, and energy requirements of applying each system to designated
facilities.'' Id. at 60.22a(b)(3).
The EPA is finalizing EG that translate the degree of emission
limitation achievable through application of the BSER (i.e., level of
stringency) into presumptive standards of performance that states may
use in the development of state plans for specific emission points. The
EPA's final EG do not impose binding requirements directly on sources,
but instead provide requirements for states in developing their plans
and criteria for assisting the EPA when judging the adequacy of such
plans. The presumptive standards that commenters appear to take issue
with are a product of the EPA's compliance with the CAA and its own
regulations, and are intended to assist states with the development of
their plans.
Within the EPA's November 2021 Proposal, the Agency explained why
the EG's proposed presumptive standards were often very similar to, if
not exactly the same as, the EPA's proposed standards of performance
under the proposed NSPS OOOOb. Part of that explanation is copied here
for context:
As discussed in each of the EG-specific subsections below, the
EPA's evaluation of BSER in the context of existing sources utilized
much of the same information as our BSER analysis for the NSPS. This
is because within the oil and natural gas industry many of the
control measures that are available to reduce emissions of methane
from existing sources are the same as those control measures
available to reduce VOC and methane emissions from new, modified,
and reconstructed sources. By extension, many of the methane
emission reductions achieved by the available control options, as
well as the associated costs, nonair environmental impacts, energy
impacts, and limitations to their application, are very similar if
not the same for new and existing sources. Any relevant differences
between new and existing sources in the context of available control
measures or any other factors are discussed in the EG-specific
subsections below.
86 FR 63186.
The November 2021 Proposal goes on to elaborate on these general
concepts. Id. The subsections that follow then explain the similarities
and any differences between new and existing sources for each of the
designated facilities covered by the EG. The December 2022 Supplemental
Proposal took the same approach by identifying similarities and
differences between new and existing sources, when relevant, within the
sections discussing the different affected and designated facilities.
Commenters provide no rationale or explanation to support the
general assertion that the presumptive standards in this EG cannot ever
be the same as the standards of performance in the corresponding NSPS.
Nor does any relevant CAA authority prohibit this outcome. The EPA did
not simply copy the NSPS into the EG. As explained in the November 2021
Proposal, the analysis that the EPA undertakes for purposes of the EG
OOOOc is the same as the analysis that the agency undertakes for the
NSPS; they are both premised on the same categories of criteria or
``inputs'' (available control options, costs associated with available
control options, emission reductions associated with available control
options, nonair quality health and environmental impacts associated
with available control options, and energy requirements associated with
available control options). Further, the EPA's methodology for
assessing the ``inputs'' is the same under the NSPS and the EG. In the
case of many designated facilities for this EG, the value of the
``inputs'' happens to be the same, or very similar (i.e., there are no
meaningful factual differences), such that the outcomes of the analysis
happen to be the same or very similar. But that is not always the case.
Where meaningful factual differences exist between new and existing
sources, the EPA appropriately took those differences into account when
developing the presumptive standards in the final EG. Take for example
the criteria of costs. For many designated facilities in this EG, the
costs of controlling emissions do not include large capital
expenditures or retrofit costs because there is no additional equipment
to buy and install.\690\ However, this is not the case for every
designated facility. For example, the presumptive standards for wells
with associated gas in the final EG OOOOc, as discussed in section
XI.F.2 of this preamble, are different than the final standard of
performance in NSPS OOOOb in part because of cost differences between
new and existing sources. By way of another example, in the November
2021 Proposal, the EPA explained relevant cost differences between new
and existing tank batteries and concluded that ``it is more expensive
to install controls at an existing tank battery than to install
controls as part of a new tank battery.'' \691\
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\690\ For example, see December 2022 Supplemental Proposal, 87
FR 74792, regarding dry seal compressors (``[t]he application of the
numerical emission limit option at an existing source is the same as
at a new source because no additional equipment must be installed in
order to comply with the standards''). See also 87 FR 74809 (``[t]he
application of an LDAR program at an existing source is the same as
at a new source because there is no need to retrofit equipment at
the site to achieve compliance with the work practice standard'').
\691\ 86 FR 63110, at 63200. More specifically, EPA ``applied a
30 percent retrofit factor to the capital and installation costs to
account for added costs of manifolding existing storage vessels and
installing the control system on an existing tank battery.'' Id.
After considering the costs for existing sources, EPA found ``the
cost effectiveness for achieving 95 percent emission reduction of
methane from [an existing] tank battery with potential methane
emissions of 20 tpy is reasonable for methane.'' Id. at 63201.
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To the extent that commenters raised particular issues (factual
differences) that they thought warranted a different presumptive
standard because of some difference between new and existing sources,
those comments are addressed separately in the context of the
appropriate designated facility. Specifically with regard to costs, the
EPA recognizes the general possibility that the costs associated with
utilizing various available control options could
[[Page 16996]]
vary between new and existing sources. It is also possible that the
costs are exactly the same; it depends on various facts that are
specific to the individual analysis for each type of designated
facility. To the extent that the EPA or commenters identified
meaningful cost differences between new and existing sources, those
differences are addressed in the context of the discussion about the
particular affected and designated facilities.
2. State Flexibilities
a. Leveraging State Programs
As first acknowledged in the November 2021 Proposal, the EPA
recognizes that some states already have existing programs they may
want to leverage for purposes of satisfying their CAA section 111(d)
state plan obligations (86 FR 63252). As stated in the December 2022
Supplemental Proposal,\692\ the EPA believes that for states to
successfully leverage their state programs to satisfy their CAA section
111(d) state plan obligations, specific criteria need to be identified
for states and the EPA to follow in determining whether a state plan
meets the level of stringency required under the final EG, and how such
equivalency demonstrations can be made in a rigorous and consistent way
such that the integrity of the EG is not undermined. In the December
2022 Supplemental Proposal, the EPA specifically proposed a source-by-
source evaluation methodology which consists of five basic criteria to
determine whether a source-by-source (or designated facility-by-
designated facility) evaluation can be considered for equivalency
should any state choose to leverage a state program for purposes of
satisfying their CAA section 111(d) state plan obligations. The
proposed criteria were: (1) Designated facility, (2) designated
pollutant, (3) standard type/format of standard (e.g., numeric, work
practice), (4) emission reductions (with consideration of applicability
thresholds and exemptions), and (5) compliance assurance requirements
(e.g., monitoring, recordkeeping, and reporting). The EPA further
proposed a source-by-source equivalency step-by-step approach followed
by an example for hypothetical state rules illustrating how states
could implement the proposed approach when conducting a state rule
equivalency determination with the proposed presumptive standards. The
step-by-step approach the EPA proposed in the December 2022
Supplemental Proposal is outlined below. The EPA is, in large part,
finalizing this approach as proposed. Any differences between the
December 2022 Supplemental Proposal and the final EG with respect to
this approach are explained below.
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\692\ 87 FR 74812.
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i. Step One: Are the state rule designated facility definition,
pollutant, and format the same?
The first question that a state needs to answer is whether its
program relied upon for purposes of the CAA 111(d) state plan defines
the regulated emissions sources substantially similar to how the EPA
defines a designated facility. The state should also address whether
the state's program requirements in the state plan for the designated
facility regulate the same pollutant (GHGs with standards expressed as
limitations on methane), and whether the format of the standard the
same (e.g., work practice or performance-based numerical standard). If
the answer is ``no'' to any of these three questions (e.g., state
program regulates VOC and not methane), then the state plan cannot
include an equivalency determination with the EPA's proposed
presumptive standards for the designated facility unless the state
program is altered to address the inconsistency. If the answer is yes
to all of these questions, a state could proceed to Step Two.
ii. Step Two: Emissions reductions.
If a state wishes to rely on their program for purposes of their
state plan, and they are not invoking RULOF to justify a less stringent
standard, then a state plan needs to include a demonstration that the
state requirements for designated facilities achieve the same or
greater emissions reduction as the designated facility presumptive
standards in the final EG. A state would have several options to make
this demonstration.
The first option would be to make a demonstration that the
designated facility's state standard achieves the same degree of
emission reduction as the designated facility BSER identified in the
final EG using the EPA model plant/representative facility. The second
option would be to make a demonstration that the designated facility's
state standard, when applied to an actual facility in the state,
achieves the same or greater emissions reduction as the designated
facility model plant/representative facility emission reduction in the
BSER analysis. The third option would be to conduct a state-wide
emissions comparison, in which the state would apply the designated
facility presumptive standard to data reflecting the population of
sources in the state (e.g., using activity data (number of sources) and
actual emissions data) and calculate the state-wide emission reduction
that would be achieved by apply the presumptive standard, and then
demonstrate that the state program requirements for a designated
facility would achieve the same or greater emissions reduction. If, for
any designed facility type, emissions reductions from the
implementation of the state rule are less than would be achieved from
the implementation of the final presumptive standards in the EG, and
the state does not properly invoke RULOF to justify the less stringent
standard(s), then the state cannot make an equivalency determination
with the EPA's presumptive standards for that designated facility type.
Conversely, if emissions reductions from the implementation of the
state rule are the same or greater than would be achieved from the
implementation of the presumptive standards, a state could proceed to
Step Three.
iii. Step Three: Make demonstration that compliance measures
included for a designated facility under a state program are adequate.
Once a state has determined that the emissions reductions from the
implementation of the state requirements for a designated facility are
the same or greater than would be achieved by the implementation of the
presumptive standards for a designated facility under Step Two, a state
plan would need to include a demonstration that compliance measures
(e.g., monitoring, recordkeeping and reporting requirements) are
sufficient to ensure continued compliance with the standards and
projected emissions reductions. The EPA's presumptive standards
included in the final EG are accompanied by compliance measures.
The EPA's intention for providing these criteria is to offer states
flexibility while establishing guideposts for states and the EPA to
follow to ensure that the state plan would meet the degree of emission
limitation required under the EG. These criteria are necessary to
ensure that states are establishing standards of performance that meet
the statutory requirements of section 111, the EPA's implementing
regulations under section 111(d) (subpart Ba), and this final EG. They
also enable the EPA to make reasoned decisions that are consistent
across states with respect to whether state plans are ``satisfactory''
and therefore approvable under section 111(d). The EPA solicited
comment on all aspects of the proposed state program equivalency
demonstration methodology and evaluation criteria. The EPA received
significant comments
[[Page 16997]]
regarding the type of equivalency evaluation. A summary of the comments
received and the EPA's response to these comments, including any
changes made to the final rule, as applicable are provided below. The
EPA's full response to comments on the November 2021 Proposal and
December 2022 Supplemental Proposal, including any comments not
discussed in this preamble, can be found in the EPA's RTC document for
the final rule.\693\
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\693\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
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Types of Equivalency Evaluations: Total Program Evaluation
Within the 2022 Supplemental Proposal, on pages 74813 to 74814, the
EPA considered an option to allow ``total program evaluation.'' The EPA
opted to not propose such an approach for the concerns expressed in
that supplemental proposal. Even though commenters asked the EPA to
allow total program evaluations, we are finalizing as proposed to not
allow such an approach for the reasons explained below.
Comment: Numerous stakeholders support a total program evaluation
rather than the proposed source-by-source methodology. In general,
commenters recommend that the EPA maximize flexibility by allowing
states to continue implementing their existing state programs.\694\ One
commenter implies that for a total program evaluation to work, the EPA
would need to allow for emissions averaging across emissions sources to
demonstrate equivalency.\695\ Another commenter generally states that
they believe a total program evaluation can be employed, with
appropriate guardrails, to both ensure significant emissions reductions
opportunities will move forward while not disrupting effective state
programs that are already in place.\696\ For example, the commenter
wrote that states should be required to adopt new requirements for a
particular source category only in the following circumstances: (1)
where the state program does not include any reduction requirements for
a particular source category; or (2) the state does have reduction
requirements for a particular source category but those requirements
achieve significantly less emissions reductions than the requirements
set forth in the EG relative to the overall emission reductions from
the oil and gas sector achieved by the state program. Absent these
circumstances, the commenter asserts that the state should retain the
flexibility necessary to continue with its current program, provided,
of course, that the state can demonstrate that the overall program can
achieve comparable emissions reductions to the EG. The comment further
advocates that the final rule provide flexibility for states to
demonstrate overall program equivalency as it pertains to existing
state monitoring, recordkeeping, and reporting requirements. More
specifically, the commenter requests that the final rule provide that
if a state demonstrates overall program equivalency, changes or
additions to existing monitoring, recordkeeping, and reporting
provisions only be required where the existing provisions are
substantially inadequate to ensure compliance with the associated
emissions reductions requirements. The commenter expresses concern that
in order to leverage a state program, the state may actually need to
modify its existing regulatory provisions, which the commenter believes
would undermine the state's implementation processes and practices and
lead to less effective state regulation.
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\694\ See Document ID Nos. EPA-HQ-OAR-2021-0317-2249, -2286, -
2296, -2326, -2390, -2410.
\695\ See Document ID No. EPA-HQ-OAR-2021-0317-2390.
\696\ See Document ID No. EPA-HQ-OAR-2021-0317-2286.
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Similarly, another commenter requests that the EPA allow states to
leverage existing state programs through submittal of total program
evaluations to demonstrate equivalency with EG OOOOc.\697\ The
commenter contends that precluding states from making a programmatic
equivalency determination--by requiring the EPA's source-by-source
approach--serves as a disincentive to state rulemaking. More
specifically, the commenter argues that the source-by-source evaluation
would be an application of a one-size-fits all approach to state
regulation in contradiction of the cooperative federalism principles
inherent throughout the CAA and specifically enumerated in CAA section
111(d). Further, the commenter believes that the EPA's source-by-source
equivalency approach will stifle progressive state rulemaking, as those
states would be less likely to expend the significant resources to
promulgate new rules only to have the EPA swoop in and set aside well-
thought-through state programs.
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\697\ See Document ID No. EPA-HQ-OAR-2021-0317-2326.
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Another commenter asserts that the EPA's proposal to preclude
states from relying on emissions averaging across emissions sources to
demonstrate equivalency will prevent states from effectively leveraging
existing state programs, require states with existing, comprehensive
regulatory programs to undertake additional rulemakings in order to
prove identicality, rather than equivalency.\698\ They interpret the
December 2022 Supplemental Proposal to have proposed a ban on averaging
by relying on health-based considerations. The commenter asserts that
the EPA justifies its decision to categorically preclude total program
evaluations on the grounds that source-by-source equivalency
demonstrations will result in greater emissions reductions because
states with more stringent regulations for some sources will be
required to revise any less stringent regulations to meet the EPA
standard. They assert that the EPA's position cannot be squared with
the interpretation of CAA section 111(d). The commenter cites to the
D.C. Circuit's decision in American Lung Association that instructs
that for the EPA to bar states from submitting plans that rely on
averaging, the EPA must have a source- and pollutant-specific rationale
that is justified and supportable.
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\698\ See Document ID No. EPA-HQ-OAR-2021-0317-2390.
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The same commenter further argues that they believe that CAA
section 111(d) does not preclude state plans from including non-
designated facilities for the purpose of demonstrating equivalency. The
commenter recommends that the EPA allow state plans to include rules
that apply to non-designated facilities for the limited purpose of
demonstrating the state plan will achieve equivalent emissions
reductions as EG OOOOc. The commenter believes that allowing state
plans to include regulations that apply to non-designated facilities,
for the limited purpose of demonstrating equivalency, is consistent
with the ``cooperative-federalism approach'' adopted by Congress in CAA
section 111(d) ``that leaves the [s]tates discretion in determining how
their [s]tate and industry can best meet quantitative emissions
guidelines established by the EPA.''
American Lung Ass'n, 985 F.3d at 942. They commenter continues to
state that even if the EPA's interpretation is reasonable, the fact
that the EPA proposed that a state plan cannot rely on emissions
reductions from non-designated facilities does not justify the EPA's
wholesale bar on submitting total
[[Page 16998]]
program evaluations. The commenter adds that the EPA does not provide
any support in the statute or case law for its interpretation that
states cannot rely on regulations that regulate the emission of VOCs or
other pollutants, if the state can demonstrate that those regulations
achieve equal reductions in methane as a co-benefit. The commenter
asserts that the EPA does not rationally justify its concerns about
allowing states to rely on different standards, both non-numerical and
numerical, in the state plan equivalency demonstrations. The EPA's
concern that allowing states to use a non-numerical standard different
from the EPA's to demonstrate equivalency ``would likely be technically
difficult because many of the presumptive standards in the EG OOOOc are
work practice standards that do not quantify emissions'' fails to
support its decision to deprive states of the flexibility Congress
granted them under the statute. The commenter believes that the EPA
assumes--without support--that this equivalency evaluation would need
to be qualitative rather than quantitative because ``not all states
have comprehensive source and source-specific emissions inventory data
[on which] to base a stringency comparison on emissions reductions
alone.''
The commenter criticizes the EPA's December 2022 Supplemental
Proposal by arguing that they believe the EPA did not rationally
justify its concerns about allowing states to rely on different
standards, both non-numerical and numerical, in the state plan
equivalency demonstrations.\699\ They refer back to the joint comment
on the November 2021 Proposal from a number of states requesting that
the EPA permit the use of different numerical standards.
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\699\ See Document ID No. EPA-HQ-OAR-2021-0317-2390.
---------------------------------------------------------------------------
One commenter recommends that the EPA consider previous regulatory
investments and existing state implementation plan approvals.\700\ One
commenter asserts that the EPA must provide states an option to
demonstrate the equivalency of their existing programs against the
EPA's proposed EG because requiring overburdened state agencies to
implement and enforce two redundant regulations jeopardizes the
regulatory agency's effectiveness and has not been justified in the EPA
proposal.\701\ The commenter furthermore is concerned that the proposed
framework for leveraging state programs does not actually provide
states with regulatory programs an option to demonstrate equivalency
because many state's regulated pollutant is VOC rather than GHG
(methane) even though VOC will achieve methane co-reductions. The
commenter believes the source-by-source criteria and methodology to be
unworkable, inflexible, and short-sighted and will result in redundant
regulations, unnecessary, and an extremely poor use of state regulatory
agencies' limited staffing resources. The commenter believes that it is
incumbent upon the EPA to consider the above points and to allow
equivalency demonstrations for states and have a streamlined process
for the adoption of states' existing rules.
---------------------------------------------------------------------------
\700\ See Document ID No. EPA-HQ-OAR-2021-0317-2249.
\701\ See Document ID No. EPA-HQ-OAR-2021-0317-2296.
---------------------------------------------------------------------------
Response: While reviewing and assessing these comments, the EPA
observed that commenters do not provide specific alternative criteria
or a specific alternative methodology for a total program evaluation
that addresses the complexities and challenges unique to the oil and
natural gas source category that the EPA identified in the December
2022 Supplemental Proposal.\702\ Furthermore, the EPA observes that
some commenters assert claims of equivalency with no supporting
documentation to substantiate how they have made that determination
articulated in their comments or identifying what criteria they used to
compare their program to the December 2022 Supplemental Proposal. For
example, the EPA posited that an accurate qualitative comparison on a
total-program scale would be extremely complicated given that there are
numerous types of designated facilities with presumptive standards, of
which some have numerical limits and others are in the format of non-
numerical standards. Commenters did not provide the EPA with actionable
ideas to address the concern that attempting to assess total program
equivalency for this EG would be so complex that the results of such an
analysis would likely be difficult to ascertain. The EPA remains
concerned with allowing the type of total program equivalency that
commenters appear to be asking for because the Agency has been unable
to identify a methodology for conducting the comparison that would be
likely to produce accurate and reliable results.
---------------------------------------------------------------------------
\702\ See 87 FR 74812-16.
---------------------------------------------------------------------------
Further, while evaluating these comments the EPA observed that
total program equivalency would necessarily entail some degree of
averaging across different types of designated facilities and
recognizes that states would need to establish an emissions reduction
tracking system to account for this averaging. If the EPA understands
the commenters correctly, commenters would like the ability to, for
example, regulate one type of designated facilities (e.g., fugitive
emissions) in a manner that results in more emissions reductions than
would occur under the presumptive standard in the EG and ``bank'' those
``extra'' reductions to offset for a different type of designated
facility (e.g., process controllers) where the state standard would be
less stringent than the presumptive standards in the EG. This type of
trading or averaging seems necessary to the idea of total program
equivalency in the context of this EG. In this particular context, the
EPA disfavors this approach and is not allowing this type of averaging
in state plans under this EG. It is inherently difficult to accurately
measure emissions from some of the designated facilities covered by
this EG. More specifically, those designated facilities where the EPA
is finalizing non-numerical presumptive standards are difficult to
measure. In accordance with 40 CFR 60.24a(b), the EPA is to identify in
the EG cases where it is not feasible to prescribe or enforce a
standard formed as an allowable rate, quantity, or concentration. The
EPA has done so in this EG. If the designated facility cannot be
subject to a standard formed as a rate, quantity, or concentration of
emissions, then it is logical that accurately measuring the emissions
from such a designated facility would be difficult. If a state plan
purported to ``overregulate'' a certain designated facility type that
was subject to a non-numerical limit, beyond the presumptive standard
in the EG, it would be extremely difficult to determine how much
``credit'' would be banked for purposes of cross-designated facility
averaging. This approach is not workable in a way that would ensure the
integrity of the EG.
To be clear, the EPA is not prohibiting all types of averaging in
this final EG. On the contrary, states may average within the confines
of each type of designated facility (e.g., storage vessel designated
facilities to storage vessel designated facilities, pump designated
facilities to pump designated facilities, fugitives designated
facilities to fugitives designated facilities). This type of averaging
does not run afoul of the concerns expressed above regarding total
program equivalence. In the context of non-numerical standards, the EPA
would expect the averaging associated with the equivalency
[[Page 16999]]
determination to be qualitative.\703\ This type of averaging to
demonstrate equivalence is what the EPA means when discussing ``source-
by-source'' equivalency in the context of leveraging a state plan.
States may very well take a different approach to certain types or
groups of designated facilities. That is acceptable so long as the
state plan follows the criteria laid out earlier in this section on
leveraging a state plan. Specifically, step two (Emissions reductions)
of the framework the EPA has laid out is the point at which this type
of averaging is relevant.
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\703\ For an example of a qualitative equivalency determination
in the context of the oil and natural gas source category, see
memorandum, ``Equivalency of State Fugitive Emissions Programs for
Well Sites and Compressor Stations to Final Standards at 40 CFR part
60, subpart OOOOa,'' located at Docket ID No. EPA-HQ-OAR-2017-0483
(January 17, 2020).
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We also clarify that averaging within the confines of each type of
designated facility can be a form of a total program equivalence. The
EPA recognized this possibility in the December 2022 Supplemental
Proposal.\704\ In theory, if a state were to perform a source-by-source
evaluation for each type of designated facilities in its state and
determine equivalency for each type of designated facility, this would
be a form of total program equivalency. Note however that this is
distinct from the type of total program evaluation commenters advocate
for and which the EPA is disallowing.
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\704\ See 87 FR 74814.
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The EPA also remains concerned about other complicating scenarios
previously identified in the December 2022 Supplemental Proposal.
Specifically, the EPA identified one scenario in which there are
instances where a state covers part or a subset of the EG designated
facility's applicability definitions. For example, Colorado requires
the use of non-emitting \705\ process controllers with specific
exceptions. One exception is that operators do not have to retrofit
their controllers to become non-emitting if on a company-wide basis,
the average production from producing wells in 2019 is less than 15
barrel of oil equivalent/day/well. However, as discussed in section
XI.D of this preamble, the presumptive standard for process controllers
included in the final EG is a methane emissions rate of zero with no
site-wide production or other applicability threshold. Thus, the
definition of the designated facility for controllers in the final EG
covers a broader group of controllers than does Colorado's regulations.
This would be problematic in a state plan because under CAA 111(d) and
40 CFR part 60, subpart Ba, the state plan must include standards of
performance for all designated facilities. Commenters did not provide
the EPA with suggestions or ideas to address this concern. If the EPA
were to permit total program equivalence in situations like this where
the scope of the sources subject to regulation in the state programs do
not align with the scope of coverage by the EG, then there could be
situations where a state would be allowed to forgo regulating some
designated facilities which the text of CAA section 111(d) says should
be subject to standards of performance in a state plan. After review of
the comments received, the EPA remains concerned that a total program
evaluation would not guarantee that the same level of emissions
reductions as identified in the EG would be achieved.
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\705\ The phrases ``zero emissions'' and ``non-emitting'' are
used to describe process controllers, but the EPA does not use these
phrases to mean the same thing. In Colorado, 5 CCR Regulation 7,
Part D, Section III, defines a ``non-emitting'' controller as ``a
device that monitors a process parameter such as liquid level,
pressure or temperature and sends a signal to a control valve in
order to control the process parameter and does not emit natural gas
to the atmosphere. Examples of non-emitting controllers include but
are not limited to: no-bleed pneumatic controllers, electric
controllers, mechanical controllers and routed pneumatic
controllers.'' A routed pneumatic controller is defined as ``a
pneumatic controller that releases natural gas to a process, sales
line or to a combustion device instead of directly to the
atmosphere.'' The EPA's final EG includes a presumptive standard for
process controllers of zero emissions. The difference between non-
emitting, as defined by Colorado, and zero emissions, as used in
this action, is that process controllers for which emissions are
captured and routed to a combustion device do not have zero
emissions. Therefore, routing emissions to a combustion device is
not an option for compliance with the presumptive standard.
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In a related scenario, the EPA recognizes states may have broader
thresholds for regulatory coverage that may differ from the EPA's EG
definitions of designated facilities. For example, a state may cover a
broader set of sources compared to the EG's designated facility
applicability threshold. The EPA acknowledges that states may choose to
regulate non-designated facilities under state law for other purposes
than to satisfy their CAA section 111(d) state plan submission
requirement. However, the EPA does not find it appropriate to allow a
state to account for non-designated facilities for purposes of
demonstrating program equivalency to the degree of emission limitation
required by the EG, even if a state regulates such sources as a matter
of state law. Put another way, for purposes of this EG, a state cannot
bank credit for portions of a state plan that rely on state laws that
regulate sources that are not designated facilities. CAA section 111(d)
requires states to establish standards of performance for designated
facilities that achieve the degree of emission limitations identified
by the Administrator. Accordingly, the emission reductions relied upon
for purposes of leveraging a state program to demonstrate source-by-
source equivalency should come from designated facilities. To be clear,
the final EG in no way impacts states' ability to regulate sources
under state law. States are still free to choose how to regulate
sources. This section of this preamble is speaking to what are
creditable emission reductions for purposes of averaging in a state
plan submitted to the EPA under CAA 111(d) and 40 CFR part 60, subpart
Ba, for purposes of this final EG.
In addition, the EPA reiterates its interpretation that CAA section
111(d) does not allow the EPA to approve state plan requirements for
different pollutants other than those designated pollutants in the EG.
Subpart Ba defined ``designated pollutant'' at 40 CFR 60.21a(a). The
EPA is aware that while numerous states have programs in place that
regulate emissions from the designated facilities that the EPA is
finalizing presumptive standards for, many of those programs do not
regulate GHGs in the form of limitations on methane. Some state
programs regulate VOC. State plans must regulate the designated
pollutant, which for this EG is GHGs in the form of limitations on
methane. Further, as the EPA explained in the 2021 Proposal, states
must submit plans ``to establish standards of performance for existing
sources for any air pollutant: (1) The emission of which is subject to
a Federal NSPS; and (2) which is neither a pollutant regulated under
CAA section 108(a) (i.e., criteria pollutants such as ground-level
ozone and particulate matter, and their precursors, like VOC) [footnote
omitted] or a HAP regulated under CAA section 112.'' 86 FR 63110 at
63134. While VOC are not specifically listed as CAA section 108(a)
pollutants, the EPA is regulating VOC in the NSPS that corresponds to
this EG as precursors to photochemical oxidants (e.g., ozone) and
particulate matter (PM), both of which are listed CAA section 108(a)
pollutants. Therefore, VOC fall within the CAA 108(a) exclusion here,
and the EPA cannot approve a state plan that establishes standards of
performance for VOC.
The EPA clarifies we are not finalizing a framework that demands
the state plan be identical to the EG. Under this EG, and consistent
with the
[[Page 17000]]
cooperative federalism framework of CAA section 111(d), states have the
prerogative to develop state plans and have flexibility to adopt
standards that diverge from the presumptive standards finalized here
(including by considering RULOF in the development of their state
plans). However, the EPA specifies that the designated facilities and
the regulated pollutants must be the same as specified in the EG.
Further, unless the state is invoking RULOF to justify a less stringent
standard, the state must demonstrate its plan achieves the degree of
emission limitation in the EG in order to be approvable. After
consideration of comments and for the reasons detailed in this section
and the critical need to provide clear regulatory certainty to the
hundreds of thousands of designated facilities in this uniquely large
source category, the EPA does not find that a total program evaluation
along the lines that commenters describe would guarantee that the same
emissions reductions as required by the EG would be achieved.
Therefore, the EPA is not finalizing a framework to allow total program
equivalency as commenters describe.\706\
---------------------------------------------------------------------------
\706\ While the RIA includes information on state-level
estimates of emissions reductions that could result from the final
EG, it's not sufficient to judge the equivalence of a state plan.
The RIA is intended to be illustrative in nature and is not precise
enough to rely upon in an analysis of total program equivalency.
---------------------------------------------------------------------------
Types of Equivalency Evaluations: Source-by-Source Evaluation
Comment: One commenter recommends that the EPA provide more clarity
and specificity in its articulation of Steps 2 and 3 of the source-by-
source equivalency determination, particularly offering clarity about
the approval of alternative technologies.\707\ The commenter recommends
that the EPA establish guidance and work with states who choose to
leverage their programs for purposes of their state plan submittal; the
commenter believes this collaboration would pose little burden on the
EPA. In addition, they suggest that ongoing resources be devoted to
offering cooperative and consultative technical support to these
states. The commenter recommends that the EPA be consistent across
different regions in these determinations. However, the commenter
asserts that the EPA must be clear in any guidance and offer a
streamlined process for equivalency to give state and local agencies a
high degree of certainty in leveraging their programs.
---------------------------------------------------------------------------
\707\ See Document ID No. EPA-HQ-OAR-2021-0317-2249.
---------------------------------------------------------------------------
Response: The EPA remains committed to working with states as they
develop and submit state plans to the Agency for review. The EPA
strives to maintain consistency in its collaboration with states to
ensure that implementation of the EG will be uniform. Please see
discussion in section XIII.D. and XIII.F. of this preamble related to
components of state plan submissions and the EPA action on state plans.
The EPA provides the following example for hypothetical state rules
illustrating how states could implement the source-by-source
(designated facility-by-designated facility) evaluation when conducting
a state rule equivalency determination with the presumptive standards.
Centrifugal Compressor Examples--Comparison of Presumptive Standards
With 4 Hypothetical Examples
Table 27 provides examples of the application of the steps outlined
above for five hypothetical state rules for reciprocating compressors
at gathering and boosting stations in the production segment. The
parameters for the presumptive standard for reciprocating compressors
are as follows.
(1) The designated facility is a single reciprocating compressor.
(2) The designated pollutant is methane, using volumetric flow rate
as a surrogate for methane.
(3) The standard type/format of standard is a numerical standard (2
scfm volumetric flow rate).
(4) The estimated methane emissions reductions for the model
compressor in the BSER analysis for the presumptive standard was 92
percent reduction.
(5) The compliance assurance requirements include the requirement
to measure the flow rate once every 8,760 operating hours and maintain
records.
Table 27--Reciprocating Compressor Designated Facility Presumptive Standards Equivalency Evaluation Examples
----------------------------------------------------------------------------------------------------------------
Equivalency determination steps
--------------------------------------------------------------------------
Designated facility requirements Step One--
Applicability and Step Two-- Emission Step Three-- Compliance
format of standard reduction assurance measures
----------------------------------------------------------------------------------------------------------------
Example A
----------------------------------------------------------------------------------------------------------------
Designated Facility: Single FAIL--format of
Reciprocating Compressor at standard not
Gathering and Boosting. equivalent.
Designated Pollutant: Methane........
Format of Standard: Work Practice
(Change out rod packing every 3
years)..
Estimated Emissions Reduction
(Basis): 56 percent (model
compressor basis)..
Compliance Assurance Requirements:
Records of changeout..
----------------------------------------------------------------------------------------------------------------
[[Page 17001]]
Example B
----------------------------------------------------------------------------------------------------------------
Designated Facility: Single PASS.................. PASS.................. PASS.
Reciprocating Compressor at
Gathering and Boosting.
Designated Pollutant: Total
hydrocarbon as Surrogate for
Methane..
Format of Standard: Numerical
(Collect and route to control to
achieve 95 percent reduction)..
Estimated Emissions Reduction
(Basis): 95 percent (model
compressor basis)..
Compliance Assurance Requirements:
Performance test of control device,
continuous parameter monitoring,
recordkeeping and reporting..
----------------------------------------------------------------------------------------------------------------
Example C
----------------------------------------------------------------------------------------------------------------
Designated Facility: Single FAIL--format of
Reciprocating Compressor at standard not
Gathering and Boosting. equivalent.
Designated Pollutant: Total Gas Flow
rate as surrogate for methane..
Format of Standard: Directed
Inspection and Maintenance (Measure
flow rate annually and replace or
repair if volumetric flow is greater
than 3 scfm)..
Estimated Emissions Reduction
(Basis): 92 percent (model
compressor basis)..
Compliance Assurance Requirements:
Records of measurements, records of
corrective actions if greater than 3
scfm, records of new measurement to
demonstrate less than 3 scfm after
corrective action..
----------------------------------------------------------------------------------------------------------------
Example D
----------------------------------------------------------------------------------------------------------------
Designated Facility: Single PASS.................. PASS--Demonstrated PASS.
Reciprocating Compressor at that the ``real
Gathering and Boosting. life'' state-wide
Designated Pollutant: Total gas flow emission reduction
rate as surrogate for methane.. for state rule was
Format of Standard: Numerical: 5 greater than the
scfm.. ``real-life''
Estimated Emissions Reduction reduction for the
(Basis): using analysis of state- presumptive standard.
wide emissions from actual
reciprocating compressors, estimated
that EG presumptive standard would
achieve 85 percent reduction over
the state, state rule would achieve
87 percent reduction..
Compliance Assurance Requirements:
Measure volumetric flow rate once
every 6 months, record results..
----------------------------------------------------------------------------------------------------------------
Example E
----------------------------------------------------------------------------------------------------------------
Designated Facility: Single PASS.................. FAIL--did not
Reciprocating Compressor at demonstrate that the
Gathering and Boosting. BSER presumptive
Designated Pollutant: Total gas flow standard model
rate as surrogate for methane.. facility reduction
Format of Standard: Numerical: 4 was met.
scfm..
Estimated Emissions Reduction
(Basis): 88 percent (analysis of
state-wide emissions from actual
reciprocating compressors)..
Compliance Assurance Requirements:
Measure volumetric flow rate once
every 6 months, record results..
----------------------------------------------------------------------------------------------------------------
The EPA further clarifies how we intend these steps of the source-
by-source equivalency determination to work with regards to the use of
alternative technologies for monitoring of fugitive emissions. For
illustrative purposes to assist with this response, we have identified
three possible scenarios. First, if a state incorporates the
presumptive standards and the associated advanced methane detection
technology provisions from the EG model rule into their approved state
plan submittal, then it would be reasonable to expect that when the EPA
approves an alternative technology in the future, the designated
facilities in the state could use the alternative technology. In a
second scenario, if a state incorporates the presumptive standards but
wants its state plan to include different alternative technology
criteria, the state must demonstrate equivalence between the state's
criteria and the criteria in the final EG. The EPA acknowledges however
that certain authorities are retained by the EPA and a state would not
have the authority to approve the alternative technology itself.
Specifically, in Sec. 60.5373c the EPA lists authorities that will not
be delegated to state, local, or Tribal agencies including but not
limited to the approval of major alternatives to test methods and the
approval of major alternatives to monitoring. In a third scenario, if
the state's plan includes a standard that is not the presumptive
standard from the EG and also different
[[Page 17002]]
alternative technology criteria than those included in the EG, the
state would need to ensure that: (1) Their standard is equivalent to
the presumptive standard (or invoke RULOF), and (2) the alternative
technology criteria are equivalent to those included in the EG.
However, just as with the second scenario, the authority to approve the
alternative technology would be retained by the EPA.
b. Averaging
As discussed in XIII.C.2.a of the December 2022 Supplemental
Proposal, the EPA stated that CAA section 111(d) authorizes the EPA to
allow states, in particular rules, to achieve the requisite emissions
limitation through the aggregate reductions from their sources, and the
EPA accordingly proposed to authorize states to leverage their state
programs in specific ways to satisfy their CAA section 111(d) state
plan obligations pursuant to the EG OOOOc. More specifically, the EPA
proposed that states may average within the confines of each type of
designated facility (e.g., pump designated facilities to pump
designated facilities). As discussed previously, the EPA is allowing
this type of averaging under the final EG. The EPA clarifies that this
type of averaging may be used regardless of whether a state chooses to
leverage an existing state program that predated EG OOOOc for purposes
of their state plan submission. In other words, states may average
within the confines of each type of designated facility even if a state
does not choose to leverage an existing program, or if the state has no
existing program and is developing new regulations in response to the
EG for their state plan. In those situations, the EPA believes states
can still use the discussion in section XIII.C.2.a of this document as
guidance for ensuring their state plan is equivalent to the EG. Also,
as discussed previously, the EPA is not allowing the type of averaging
that commenters appear to be asking for when they discuss total program
equivalency. The EPA's concerns with total program equivalency specific
to this EG are explained above. The EPA received significant comments
regarding the use of averaging in the state plan submittal. The EPA
believes that the discussion on averaging above in this section
responds to the most significant of those comments. The EPA's full
response to comments on the November 2021 Proposal and December 2022
Supplemental Proposal, including any comments not discussed in this
preamble, can be found in the EPA's RTC document for the final
rule.\708\
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\708\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
---------------------------------------------------------------------------
c. General Permitting Programs
The EPA continues to recognize that some states may choose to
regulate designated facilities under the EG through a general permit
program. For example, general permits often include standardized terms
and conditions related to emissions control, compliance certification,
notification, recordkeeping, reporting, and source testing
requirements. The EPA is not finalizing a regulatory provision on this
topic within EG OOOOc, but confirms that the implementing regulations
under subpart Ba allows for standards of performance and other state
plan requirements to be established as part of state permits and
administrative orders, which are then incorporated into the state plan.
See 40 CFR 60.27a(g)(2)(ii).
However, the EPA notes that the permit or administrative order
alone may not be sufficient to meet the requirements of an EG or the
implementing regulations, including the completeness criteria under 40
CFR 60.27a(g). For instance, a plan submission must include supporting
material demonstrating the state's legal authority to implement and
enforce each component of its plan, including the standards of
performance. Id. at 40 CFR 60.27a(g)(2)(iii). In addition, EG OOOOc
requires demonstrations that may not be satisfied by terms of a permit
or administrative order. To the extent that these and other
requirements are not met by the terms of the incorporated permits and
administrative orders, states will need to include materials in a state
plan submission demonstrating how the plan otherwise meets those
requirements.
3. Remaining Useful Life and Other Factors (RULOF)
In the December 2022 Supplemental Proposal, the EPA proposed and
solicited comment on requirements related to states' use of RULOF when
applying standards of performance in their state plan submittals.\709\
However, the EPA is not finalizing any substantive provisions related
to RULOF in EG OOOOc. The only provision included in the final version
of EG OOOOc that relates to RULOF is 40 CFR 60.5365c, which directs
states to the RULOF requirements specified in 40 CFR 60.24a (subpart
Ba).
---------------------------------------------------------------------------
\709\ See 87 FR 74816 (December 6, 2022).
---------------------------------------------------------------------------
Since the supplemental proposal, the EPA has promulgated revisions
to subpart Ba.\710\ These revisions represent the final, generally
applicable requirements for RULOF, including consideration of the
topics that the EPA addressed in the December 2022 Supplemental
Proposal, and are applicable to these EG. State plans submitted in
accordance with these EG that include provisions for RULOF must comply
with the subpart Ba general RULOF provisions in 40 CFR 60.24a.\711\ As
such, the EPA did not find it necessary to also finalize similar
provisions in these EG as they would have been redundant with those
recently finalized via a separate rulemaking process in subpart Ba.
---------------------------------------------------------------------------
\710\ 88 FR 80480 (November 17, 2023).
\711\ See 40 CFR 60.20a(a), which establishes applicability of
subpart Ba requirements to EG OOOOc. Further, EG OOOOc does not
supersede any requirement within subpart Ba related to RULOF.
---------------------------------------------------------------------------
For informational purposes, the EPA will summarize the RULOF
provisions that have been finalized in the subpart Ba rulemaking, which
is separate and distinct from this action. 40 CFR 60.24a(e) explains
that states may apply a standard of performance to a particular
designated facility that is less stringent than otherwise required by
an applicable EG taking into consideration that facility's RULOF,
provided that the state demonstrates with respect to each such facility
(or class of such facilities) that the facility cannot reasonably
achieve the degree of emission limitation determined by the EPA based
on: (1) unreasonable cost of control resulting from plant age,
location, or basic process design; (2) physical impossibility or
technical infeasibility of installing necessary control equipment; or
(3) other factors specific to the facility. The state must demonstrate
that there are fundamental differences between the information specific
to a facility or class of such facilities and the information the EPA
considered in determining the degree of emissions limitation achievable
through application of the BSER that make achieving such degree of
emissions limitation unreasonable for that facility. Similarly, the
state may apply a compliance schedule to a particular designated
facility, or class of such facilities, that is longer than provided in
an applicable emissions guideline taking into consideration that
facility's RULOF, provided the state demonstrate there are fundamental
differences between the information specific to the
[[Page 17003]]
facility and the information the EPA considered in determining the
compliance schedule.
If a state makes the demonstration in 40 CFR 60.24a(e), the plan
may apply a standard of performance that is less stringent than
required by an applicable EG. Such standard of performance must meet
the requirements in 40 CFR 60.24a(f): (1) The standard must be no less
stringent (or have a compliance schedule no longer) than is necessary
to address the fundamental differences identified under 40 CFR
60.24a(e). To the extent necessary to determine a standard of
performance, the state must evaluate the systems of emission reduction
identified in the applicable EG using the factors and evaluation
metrics the EPA considered in assessing those systems, including
technical feasibility, the amount of emission reductions, the cost of
achieving such reductions, any nonair quality health and environmental
impacts, and energy requirements. The states may also consider, as
justified, other factors specific to the facility that were the basis
of the demonstration under 40 CFR 60.24a(e) as well as other systems of
emission reduction in addition to those the EPA considered in the
applicable EG. (2) The standard of performance under 40 CFR 60.24a(f)
must be in the form as required by the applicable EG. 40 CFR 60.24a(g)
requires that where a state applies a less stringent standard of
performance on the basis of an operating condition(s) within the
designated facility's control, such as remaining useful life or
restricted capacity, the plan must include such operating condition(s)
as an enforceable requirement and provide for the implementation and
enforcement of the operating condition(s), such as requirements for
monitoring, reporting, and recordkeeping. 40 CFR 60.24a(h) requires
that a less stringent standard of performance meet all other applicable
requirements in subpart Ba and the applicable EG.
Even though the EPA is not finalizing any RULOF requirements in EG
OOOOc that are unique to the oil and natural gas industry, the EPA has
provided information and analysis on this subject that states should
consider when developing their state plans for this EG. First, as a
point of clarification, application of the RULOF provisions in the
context of EG OOOOc is distinct from source-by-source equivalency
evaluations (that can account for a type of averaging) discussed
earlier in section XIII.C.2 of this document. RULOF applies where a
state intends to depart from the presumptive standards in EG OOOOc to
apply a less stringent standard for a designated facility or class of
facilities. That is, the RULOF provisions are relevant to a state's
process of applying a standard of performance to an existing source in
the first instance. In contrast, averaging is a mechanism that states
may use to demonstrate compliance with the standards of performance
that they have previously determined and are contained within their
state plans. States are not required to use the RULOF provisions in
order to implement averaging mechanisms to comply with a standard of
performance that reflects the presumptive standard in EG OOOOc.
Next, the EPA continues to find that states ought to consider
certain circumstances that are specific to remaining useful life and
the concept of unreasonable costs for EG OOOOc. The EPA explained these
considerations within the December 2022 Supplemental Proposal. 87 FR
74822-23. Remaining useful life is the one ``factor'' that CAA section
111(d) explicitly requires that the EPA permit states to consider in
applying a standard of performance. Subpart Ba allows for a state to
account for remaining useful life to apply a standard that is less
stringent than the corresponding EG. Moreover, the recent revisions to
subpart Ba, as explained above, clarified the circumstances in which
states may invoke RULOF based on an existing source's remaining useful
life, as well as the process for doing so.
For purposes of this discussion, which is specific to EG OOOOc, the
relevant provision of subpart Ba is 40 CFR 60.24a(e), which allows
states to apply a less stringent standard if the state demonstrates
that a facility, or class of facilities, cannot reasonably achieve the
degree of emision limitation determined by the EPA based on, inter
alia, unreasonable cost of control resulting from plant age. As
explained in the December 2022 Supplemental Proposal, the EPA believes
that the ability to demonstrate cost unreasonableness based on a
source's remaining useful life would likely depend on whether the
facility will be required to make a capital investment to comply with
the presumptive degree of emission limitation.
When the EPA determined the degree of emission limitation
achievable through application of the BSER in this EG, as required by
CAA section 111(a)(1), it considered costs of controls and, in many
instances, the EPA specifically considered annualized costs associated
with payment of the total capital investment of the technology
associated with the BSER. In the estimation of this annualized cost,
the EPA assumes an interest rate and a capital recovery period,
sometimes referred to as the payback period. The EPA provided the
following example in the December 2022 Supplemental Proposal of how
cost effectiveness is evaluated in these circumstances. This
illustrative example is still helpful to understand the EPA's position
and is therefore repeated here. In the estimation of the annual costs
for the installation of an instrument air system to power process
controllers with compressed air at a medium-sized transmission and
storage site, the EPA estimated that the total capital investment
(equipment and installation) of the system would be $76,481. For the
BSER analysis, the EPA assumed an interest rate of 7 percent and a
capital recovery period of 15 years. This means that the annual cost of
recovering the initial capital investment including interest, was
$8,397 per year for 15 years. The total annual cost includes this
capital recovery cost plus the additional operation and maintenance
cost of the equipment (additional beyond what would be required for a
natural gas-driven controller system). For this example, the additional
operation and maintenance cost was estimated to be $2,816 per year,
resulting in a total annual cost of $11,213 and a cost effectiveness of
$1,250 per ton of methane removed, which is a value within the range
considered reasonable by the EPA.
Therefore, for this illustrative example, the cost effectiveness is
reasonable considering a capital recovery period, or payback period, of
15 years. If the remaining useful life of a particular facility were to
be less than 15 years, the result could be a cost effectiveness value
for that facility that is outside of the range considered reasonable by
the EPA, i.e., is fundamentally different from the cost of control the
EPA considered in EG OOOOc. For example, consider a remaining useful
life of 6 years. The resulting capital recovery cost would be $26,742
per year and total annual cost would be $29,196. This would yield a
cost effectiveness of $1,834 per ton of methane removed, which would
still be in the range considered reasonable by the EPA. Therefore, the
state would not be able to claim under 40 CFR 60.24a(e) that the costs
were unreasonable for a remaining useful life of 6 years. However, if
the remaining useful life were only 2 years, the capital recovery cost
would be $70,502 per year and the total annual cost would be $72,956.
The cost effectiveness of this would be
[[Page 17004]]
almost $4,600 per ton of methane removed, which is outside of the range
considered reasonable by the EPA in this action. In this situation,
this could potentially be used as part of a RULOF demonstration under
subpart Ba to justify applying a less stringent standard.
Note that this specific example is only for illustrative purposes.
For process controller designated facilities, EG OOOOc identifies the
degree of emission limitation achievable as zero methane emissions (100
percent reduction). To invoke RULOF to apply a less stringent standard
of performance, the state must show ``that the facility cannot
reasonably achieve the degree of emission limitation determined by the
EPA.'' 40 CFR 60.24a(e). While the example examines one potential
control option to achieve the identified degree of emission limitation,
there are other equivalent control options (e.g., electric controllers)
that are considerably less expensive than the installation of an
instrument air system. The EPA still finds this example helpful though
because all zero-emissions control options for process controllers
entail capital investment.
In the December 2022 Supplemental Proposal, the EPA distinguished
the application of remaining useful life based on cost unreasonableness
for sources that would not incur capital costs to comply with the
presumptive degree of emission limitation and proposed to preclude
states from relying on the remaining useful life factor for certain
specified facilities. While the EPA continues to believe that a cost
unreasonableness determination based on remaining useful life for
certain designated facility types (such as fugitive emissions, which do
not entail large capital expenditures) would very likely not be
justified under the RULOF provisions of subpart Ba, the EPA is not
finalizing a regulatory provision prohibiting states from attempting to
make such a demonstration in developing state plans for EG OOOOc.
Nonetheless, the EPA continues to believe that for purposes of this
EG the only cost factor that would likely be reasonable to consider in
a remaining useful life determination of cost unreasonableness is
whether there is a significant capital investment required to design,
purchase, and install equipment. This is based on how the EPA conducted
the relevant BSER analyses that resulted in the presumptive standards
included in this final EG. The BSER determinations in EG OOOOc that are
based on compliance measures that do not require such upfront capital
expenditures were not based on the assumption that that the compliance
costs would need to be amortized over a payback period in order to be
considered cost reasonable, and therefore are reasonable for designated
facilities that operate for any period of time into the future. If the
presumptive standard included in this final EG does not require upfront
capital expenditures, then the EPA believes it would be extremely
unlikely that a state could demonstrate, based on costs relative to
remaining useful life, ``that there are fundamental differences between
the information specific to a facility (or class of such facilities)
and the information EPA considered in determining the degree of
emission limitation achievable through application of the best system
of emission reduction or the compliance schedule that make achieving
such degree of emission limitation or meeting such compliance schedule
unreasonable for that facility.'' 40 CFR 60.24a(e)(2). Accordingly, a
cost unreasonableness showing based on remaining useful life under 40
CFR 60.24a(e) would likely only be appropriate for the following types
of designated facilities in this EG: oil wells with associated gas,
storage vessels, process controllers, and pumps. While states are not
precluded from attempting to demonstrate cost-unreasonable based on
remaining useful life for other designated facility types in this EG,
the EPA does not believe that such a demonstration for the other
designated facilities would likely satisfy the requirements of subpart
Ba.
Note that this discussion is specific to application of 40 CFR
60.24a(e) based on unreasonable cost of control resulting from plant
age (remaining useful life) within the context of this specific EG
(OOOOc) and does not speak to application of the other circumstances
provided in 40 CFR 60.24a(e).
Within the December 2022 Supplemental Proposal, the EPA solicited
comment on ``whether EG OOOOc should include a single `outermost
retirement date' that would define the maximum length of time that
would qualify for a designated facility to operate at a less stringent
standard based on remaining useful life.'' 87 FR 74823. The EPA's
reasoning for soliciting comments on this issue was that establishing
such an outermost retirement date could avoid potential inequities
associated with different states making demonstrations that result in
different remaining useful life periods for the same types of
designated facilities. After reviewing comments and considering this
issue in conjunction with the final provisions promulgated as part of
40 CFR part 60, subpart Ba, the EPA has determined that establishing
outermost retirement dates in this EG is not necessary to avoid the
potential inequities that the Agency expressed concern about in the
December 2022 Supplemental Proposal. Specifically, the EPA finds that
this potential inequity will be mitigated by the requirements within
subpart Ba mandating that any standard less stringent than otherwise
required by the EG be no less stringent than necessary to address the
fundamental differences between the facility and the information the
EPA considered when developing the EG. 40 CFR 60.24a(f)(1). This will
help to ensure that the state's basis for relying on a particular
retirement date to establish a less stringent standard is well-
justified. Moreover, the EPA recognizes the possibility, in the context
of this EG, that certain designated facilities may be situated such
that different remaining useful life periods for the same types of
designated facilities could be justified. Due to the large number of
existing sources, the wide variety of configurations, and the fact that
the EPA's presumptive standards already include subcategories for some
types of designated facilities, it is conceivable that fact-specific
circumstances taken into account when applying the RULOF process in
subpart Ba could result in different remaining useful life periods for
the same types of designated facilities.
Lastly, as previously discussed, subpart Ba requires that when an
operational condition is used as the basis for applying a less
stringent standard, the state plan must include that condition as a
federally enforceable requirement. 40 CFR 60.24a(g). Accordingly, if a
state applies a less stringent standard by accounting for remaining
useful life, per subpart Ba, the state must include in the state plan
the retirement date for the designated facility as an enforceable
commitment and include measures that provide for the implementation and
enforcement of such commitment. For example, the state could adopt a
regulation or enter into an agreed order specifying that the designated
facility will not operate beyond a certain date (the facility's planned
retirement date), and that regulation or agreed order would then be
incorporated into the state plan. The state could also choose to
incorporate the retirement date into a permit, such as a
preconstruction permit, and incorporate that permit into the state
plan.
As required by CAA section 111(d) and subpart Ba, a state plan must
[[Page 17005]]
include a standard of performance that applies to a designated facility
until its retirement (all designated facilities must be subject to a
standard of performance). If the state is invoking RULOF to apply a
less stringent standard, then the less stringent standard ``must be no
less stringent . . . than is necessary to address the fundamental
differences'' between the relevant facility and the information the EPA
considered when developing the EG. 40 CFR 60.24a(f)(1). The EPA
recognizes that, in some instances, a designated facility may intend to
retire imminently such that the remaining useful life of that facility
results in costs that are fundamentally different from the costs that
the EPA considered in EG OOOOc. In such situations it may not be
reasonable to require that any additional controls be installed, based
on the source's exceptionally short remaining useful life. This could
be especially true if such controls require upfront capital
expenditures. In the case of an imminently retiring source, the EPA
continues to believe that states should apply a standard of performance
no less stringent than one that reflects the designated facility's
current operations.
The EPA explained this position in the December 2022 Supplemental
Proposal at page 74823. If the fundamental difference between the
facility at issue and the information that the EPA considered in this
EG is that the facility intends to cease operations in the very near
future, then it seems apparent to the EPA that the requirements of
subpart Ba as applied to this EG would result in a standard that is no
less stringent than what the source is already doing to control
emissions. The EPA believes it would be extremely unlikely that a state
could justify a standard less stringent than maintaining the existing
level of emission control already in place at the facility.
4. Providing Measures That Implement and Enforce Such Standards
In conjunction with establishing standards of performance, state
plans must also include compliance schedules for those standards, and,
where required by the applicable EG, must also include increments of
progress. See 40 CFR 60.24a(a) and (d). Section XIII.E explains the
timing of state plan submissions, compliance schedules, and increments
of progress for EG OOOOc. The EPA's subpart Ba implementing regulations
require that state plans shall require final compliance as
expeditiously as practicable, but no later than the compliance times
specified in the applicable EG. See 40 CFR 60.24a(c). States that
identify a need for longer compliance times than those specified in the
final EG must invoke RULOF to justify those longer times. See 40 CFR
60.24a(e)-(h). Moreover, 40 CFR 60.24a(d) requires state plans to
include increments of progress when the compliance schedule under the
applicable EG extends more than 20 months after the state plan
submittal date. Since the compliance schedule for EG OOOOc is 36
months, the EPA has considered the need for and ultimately required
increments of progress to be included in state plans. States that
invoke RULOF to justify a compliance schedule longer than 36 months
should consider whether additional increments of progress, beyond those
required in EG OOOOc, are ``necessary to permit close and effective
supervision of progress toward final compliance.'' 40 CFR 60.24a(d).
Where a state invokes RULOF to apply a less stringent standard of
performance, the compliance schedule must be as expeditious as
practicable but no later than the time specified in EG OOOOc, 40 CFR
60.24a(c), unless the state also justifies a longer compliance schedule
pursuant to 40 CFR 60.24a(e) and (f).
In addition to establishing standards of performance and compliance
schedules, state plans must also include, adequately document, and
demonstrate the methods employed to implement and enforce the standards
of performance such that the EPA can review and identify measures that
assure transparent and verifiable implementation. As part of ensuring
that regulatory obligations appropriately meet statutory requirements
such as enforceability, the EPA has historically and consistently
required that obligations placed on sources be quantifiable, non-
duplicative, permanent, verifiable, and enforceable. See 40 CFR
60.27a(g)(3)(vi). In accordance with the EPA's implementing
regulations, standards of performance required for designated
facilities as part of a state plan to implement the EG must be non-
duplicative, permanent, verifiable, and enforceable. Further, in this
EG and in accordance with subpart Ba at 60.24a(b), the EPA has
identified certain types of designated facilities where the Agency has
determined that it is not feasible to prescribe or enforce a standard
based on an allowable rate, quantity, or concentration of emissions
(numeric limit). For these, the final EG includes non-numerical
presumptive standards, consistent with CAA section 111(h)(1), sometimes
referred to in shorthand as presumptive ``work practice standards'' but
which can also be design, equipment, or operational standards, or a
combination thereof.\712\ When states include non-numerical limits in
their plan, ``the plan shall, to the degree possible, set forth the
emission reductions achievable by implementation of such standards, and
may permit compliance by the use of equipment determined by the State
to be equivalent to that prescribed.'' 40 CFR 60.24a(b). A state plan
implementing the EG should include information adequate to support a
determination by the EPA that the plan meets these requirements.
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\712\ See tables 25 and 26 in this preamble for summary of final
EG subpart OOOOc presumptive standards.
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Additionally, states must include appropriate monitoring,
reporting, and recordkeeping requirements to ensure that state plans
adequately provide for the implementation and enforcement of standards
of performance. See 40 CFR 60.25a. The model rule included within the
final EG OOOOc includes many monitoring, reporting, and recordkeeping
provisions associated with the final presumptive standards. Within the
2022 Supplemental Proposal, the EPA clarified our position ``that
states maintain the same monitoring, reporting, and recordkeeping
requirements, or equivalent requirements as described in EG OOOOc for
presumptive standards that states adopt in their plans.'' 87 FR 74702
at 74826. The EPA is finalizing this approach because the Agency has
determined that the monitoring, reporting, and recordkeeping provisions
included in the final EG are necessary to implement and enforce the
associated presumptive standards. Put another way, if a state chooses
to include a final presumptive standard in their state plan, then they
need to also incorporate the associated final monitoring,
recordkeeping, and reporting requirements contained in the model rule,
or equivalent requirements, to ensure that the state plan adequately
provides for the implementation and enforcement of the standard of
performance. Where a state plan includes standards of performance that
differ from the presumptive standards, the plan may accordingly include
different monitoring, reporting, and recordkeeping requirements than
those in the final model rule, but such requirements must be
appropriate for the implementation and enforcement of the standards. In
those situations, states may still find the monitoring, reporting, and
recordkeeping provisions included in the model rule helpful and
informative for development of their
[[Page 17006]]
state plan. The EPA reviews all state plan submittals for approvability
through notice and comment rulemaking. As such, components of a state
plan that differ from any presumptively approvable aspects of the EG,
including monitoring, reporting, and recordkeeping provisions included
in a state plan, will be thoroughly reviewed by the EPA and will be
subject to review and comment by the public.
5. Emissions Inventories
Within the November 2021 Proposal, the EPA solicited comment on
whether to supersede the emission inventory requirements of 40 CFR
60.25a(a).\713\ Based on comments received, in the December 2022
Supplemental Proposal, the EPA proposed to supersede the requirements
of 40 CFR 60.25a(a) for purposes of this EG, so that state plans are
not required to include an inventory and emissions data as described
under that subpart Ba provision. The implementing regulations at 40 CFR
60.25a contain generally applicable requirements for emission
inventories, source surveillance, and reports. 86 FR 63253 (November
16, 2021). 40 CFR 60.25a(a) requires that state plans shall include an
inventory of all designated facilities, including emissions data for
the designated pollutants. This provision further requires that such
data shall be summarized in the plan, and emission rates of designated
pollutants from designated facilities shall be correlated with
applicable standards of performance. While the latest revisions to
subpart Ba did alter this provision some, those revisions were not
meaningful with respect to the reasoning that the EPA included in the
December 2022 Supplemental Proposal for superseding this inventory
requirement for the oil and natural gas EG.
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\713\ 86 FR 63253.
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The EPA received significant comments regarding the inclusion of an
emissions inventory in the state plan submittal. A summary of the
comments received and the EPA's response to these comments, including
any changes made to the final rule, as applicable are provided below.
The EPA's full response to comments on the November 2021 Proposal and
December 2022 Supplemental Proposal, including any comments not
discussed in this preamble, can be found in the EPA's RTC document for
the final rule.\714\
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\714\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
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Comment: Several commenters support the use of existing emissions
inventory data to fulfill state plan requirements even if that data
might not be fully aligned with the designated facilities in the
EG.\715\ One commenter \716\ suggested that the emissions inventory
data could be derived from the GHGRP whereas other commenters \717\ did
not support the use of GHGRP as a basis for their state inventory data
due to the large reporting threshold. Several other commenters
supported the EPA's proposal to supersede the requirements of 40 CFR
60.25a(a) so that state plans do not have to include an inventory and
emissions data as described.\718\ Lastly, one commenter reported that
their state regulations require that any source of regulated air
pollutants must submit an emission inventory and suggests the EPA
accept emissions data for these facilities in accordance with the
provisions of the Air Emissions Reporting Requirements (AERR), with
detailed requirements for designated facilities that are classified as
AERR Type A and B sources and the use of alternative methods (e.g., a
nonpoint tool) for designated facilities that would be classified as
nonpoint sources under the AERR.\719\ The commenter reports that AERR
already has emissions thresholds for what should be inventoried as a
point source, and what is being captured in the NEI as a nonpoint
source. The commenter believes that the rule should align with the AERR
thresholds and requirements and suggests that using the NEI would give
a much more comprehensive accounting of facilities and provide more
accurate emissions.
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\715\ See Document ID No. EPA-HQ-OAR-2021-0317-2218, -2286, -
2296, -2393, -2410.
\716\ See Document ID No. EPA-HQ-OAR-2021-0317-2218.
\717\ See Document ID No. EPA-HQ-OAR-2021-0317-2296, -2393.
\718\ See Document ID No. EPA-HQ-OAR-2021-0317-2286, -2296.
\719\ See Document ID No. EPA-HQ-OAR-2021-0317-2393.
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Response: The EPA maintains that, due to the very large number of
existing oil and natural gas sources (designated facilities) \720\ and
the frequent change of configuration and/or ownership, it is not
practical to require states to compile this information generally
required by subpart Ba in the same way that is typically expected for
other industries under other EG. Furthermore, the EPA believes that,
while 40 CFR 60.25a(a) could be superseded to require the use of
existing emissions inventory data such as GHGRP or NEI to fulfill state
plan requirements, the development of such an inventory would still be
resource intensive with little benefit. Specifically, the EPA does not
find it reasonable to burden states to derive information from GHGRP,
the AERR, or the NEI, which the EPA already has, only to resubmit it to
the Agency. Therefore, in order to avoid the potential burden that
could be imposed by applying 40 CFR 60.25a(a) as written to this EG, as
well as the potential burden and duplicative information collection
imposed by requiring states to use other existing inventories such as
GHGRP, the EPA finalizes, as proposed, to supersede the requirements of
40 CFR 60.25a(a) for purposes of this EG, so that state plans are not
required to include an inventory and emissions data as described under
this provision. The EPA further reiterates for purposes of this EG,
that the EPA does not find that the inventory and detailed emissions
data required under 40 CFR 60.25a(a) is necessary for states to develop
standards of performance.
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\720\ In the U.S. the EPA has identified over 15,000 oil and gas
owners and operators, around 1 million producing onshore oil and gas
wells, about 5,000 gathering and boosting facilities, over 650
natural gas processing facilities, and about 1,400 transmission
compression facilities.
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6. Meaningful Engagement
In the November 2021 Proposal and December 2022 Supplemental
Proposal, the EPA proposed and solicited comment on a requirement that
states perform early outreach and meaningful engagement with pertinent
stakeholders during the development process of their state plans
pursuant to EG OOOOc.\721\ The EPA is not finalizing the provision for
meaningful engagement in this rulemaking. Rather, since similar
revisions to subpart Ba are now final and are therefore applicable to
the EG OOOOc, state plans must be submitted according to the provisions
in 40 CFR 60.23a(i) which requires states to document in their plan
submittals how they provided meaningful engagement with the pertinent
stakeholders. Specifically, subpart Ba requires as part of completeness
criteria in 40 CFR 60.27a(g) that states must submit, with the plan or
revision, documentation of meaningful engagement including a list of
identified pertinent stakeholders and/or their representatives, a
summary of the engagement conducted, a summary of stakeholder input
received, and a description of how stakeholder input
[[Page 17007]]
was considered in the development of the plan or plan revisions.\722\
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\721\ See 86 FR 63254 (November 15, 2021) and 87 FR 74827
(December 6, 2022).
\722\ See 40 CFR 60.21a for the definitions of meaningful
engagement and pertinent stakeholders.
---------------------------------------------------------------------------
Since the EPA has finalized these meaningful engagement provisions
within the context of subpart Ba, and since subpart Ba applies to the
development of state plans for this EG, the EPA found it unnecessarily
redundant to finalize similar provisions related to meaningful
engagement in the context of this EG OOOOc. This EG therefore defers to
subpart Ba on this topic. However, there are several related issues
raised in comments that the EPA will briefly discuss here. First, as
discussed in section VII of this preamble, the EPA summarized
engagement with pertinent stakeholders for this rulemaking. To the
extent that commenters take issue with the EPA's engagement with
stakeholders on this rulemaking (the NSPS OOOOb and EG OOOOc), we
direct them to section VII of this preamble and the separate RTC
document associated with this final rulemaking.
Second, the EPA recognizes that several comments the Agency
received on the November 2021 Proposal and the December 2022
Supplemental Proposal referenced several existing state and Tribal
nation EJ programs and/or EJ analyses conducted in oil and natural gas
producing states and Tribal nations. The EPA compiled information
submitted by commenters and documented our review of other readily
available information (e.g., state websites) on programs and analyses
in a Memorandum to the public docket titled, Summary of State, Tribal
and Local Environmental Justice (EJ) Programs and Analyses.\723\ The
EPA believes this memorandum will serve as a helpful resource to
states, pertinent stakeholders, and other interested parties trying to
determine how to conduct their own meaningful engagement as part of the
state planning process. The memorandum specifically describes a summary
of existing EJ programs and other EJ activities conducted by state,
Tribal, and local governments compiled from an in-depth assessment of
government websites and publicly available documents. The EPA
identifies state and Tribal EJ programs and procedures, including
community identification criteria and mapping tools utilized.\724\ The
EPA observes in the memorandum that while several states implement
tools or procedures for conducting analyses, few of these states
include readily available results of analyses their agencies have
conducted (i.e., not accessible on their websites or through web
searches), and no analyses conducted by tribes were identified.
Analyses performed by local government associations for transportation
planning purposes were available for review and included in this
summary.
---------------------------------------------------------------------------
\723\ See EPA-HQ-OAR-2021-0317.
\724\ Comments also indicated several EJ studies had been
conducted in oil and gas producing states by third parties. The
focus of this review was on analyses conducted by state and local
governments, although a few third-party analyses were included where
information was readily available.
---------------------------------------------------------------------------
Lastly, the EPA further recognizes that several comments the Agency
received on the November 2021 Proposal and the December 2022
Supplemental Proposal requested that the EPA be more specific about
what the EPA would consider approvable for meaningful engagement and
provide guidance to states (e.g., scope and degree). The EPA notes that
as part of subpart Ba the EPA finalized procedural requirements for
meaningful engagement as completeness criteria and is not prescribing
how states proceed with such engagement. In particular, at 40 CFR
60.23a(i), subpart Ba requires that states must submit, with the plan
or revision, documentation of meaningful engagement including a list of
identified pertinent stakeholders and/or their representatives, a
summary of the engagement conducted, a summary of stakeholder input
received, and a description of how stakeholder input was considered in
the development of the plan or plan revisions. As an additional
resource to states, the EPA compiled information that may assist states
identify best practices for conducting meaningful engagement. This
information can be found in a Memorandum to the public docket for this
rulemaking titled, Summary of Strategies for Meaningful Engagement on
Environmental Justice (EJ) Topics.\725\ This memorandum reviews over
fifty EJ reports, policies, plans, and publications that have been
produced by various state and local jurisdictions in the U.S. and the
memorandum includes numerous referenced documents that pertinent
stakeholders and other interested parties may find helpful.
---------------------------------------------------------------------------
\725\ See EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------
D. Components of State Plan Submission
Under CAA section 111(d)(2), the EPA has an obligation to determine
whether each state plan is ``satisfactory.'' Therefore, in addition to
identifying the components that the EG must include, the EPA's
implementing regulations \726\ for CAA section 111(d) (subpart Ba)
identify additional components that a state plan must include. Many of
these requirements are found in 40 CFR 60.23a, 60.24a, 60.25a, and
60.26a. These provisions include requirements for components such as
the following: procedures a state must follow for adopting a plan
before submitting it to the EPA; the stringency of standards of
performance and compliance timelines; emissions inventories, reporting,
and recordkeeping; and a demonstration the state has legal authority to
adopt and implement the plan. These requirements are also generally
contained in a list of required state plan elements, referred to as the
state plan completeness criteria, found at 40 CFR 60.27a(g)(2)-(3). If
the EPA determines that a submitted plan does not meet these criteria,
then the state is treated as not submitting a plan and the EPA has a
duty to promulgate a Federal plan for that state. See CAA section
111(d)(2)(A) and 40 CFR 60.27a(g)(1). If the EPA determines a plan
submission is complete, such determination does not reflect a judgment
on the eventual approvability of the submitted portions of the plan,
which instead must be made through notice-and-comment rulemaking. The
completeness criteria do not apply to states without any designated
facilities because these states are instead directed to submit to the
Administrator a letter of negative declaration certifying that there
are no designated facilities, as defined by the EPA's emissions
guidelines, located within the state. See 40 CFR 60.23a(b). No plan is
required for states that do not have any designated facilities.
Designated facilities located in states that mistakenly submit a letter
of negative declaration could be subject to a Federal plan until a
state plan regulating those facilities becomes approved by the EPA.
---------------------------------------------------------------------------
\726\ 88 FR 80480 (November 17, 2023).
---------------------------------------------------------------------------
Subpart Ba of 40 CFR part 60 contains ten administrative and six
technical criteria for complete state plans under CAA section 111(d).
See 40 CFR 60.27a(g)(2)-(3). If a state plan does not include one of
these established criteria, then the state plan may be deemed
incomplete by the EPA. States that are familiar with the SIP submittal
process under CAA section 110 will be familiar with the completeness
criteria found in 40 CFR part 51, appendix V. While the completeness
criteria for state plan submittals found at 40 CFR 60.27a(g)(2)-(3) are
somewhat similar to the SIP submittal criteria in appendix V, the
criteria are not exactly the same. As such, even states that are
familiar with the SIP submittal process under CAA section 110 are
strongly encouraged to
[[Page 17008]]
review the completeness criteria in 40 CFR 60.27a(g)(2)-(3) as well as
the other state plan requirements found in 40 CFR 60.23a, 60.24a,
60.25a, and 60.26a early in their planning process.
In short, the administrative completeness criteria require that the
state's plan include a formal submittal letter and a copy of the actual
state regulations themselves, as well as evidence that the state has
legal authority to adopt and implement the plan, actually adopted the
plan, followed state procedural laws when adopting the plan, gave
public notice of the changes to state law, held public hearing(s) if
applicable, and responded to state-level comments. For a detailed
description regarding the public hearing requirement, see 40 CFR
60.23a. For a detailed description of what the state plan must include
in terms of evidence that the state has legal authority to adopt and
implement the plan, see 40 CFR 60.26a. States are strongly encouraged
to review the state plan requirements included in 40 CFR 60.23a and
60.26a in conjunction with the administrative completeness criteria in
40 CFR 60.27a. Also, as explained above, the completeness criteria in
subpart Ba now requires states to include in their plan submittals how
they provided meaningful engagement with the pertinent stakeholders.
The technical criteria require that the state's plan identify the
designated facilities, the standards of performance, the geographic
scope of the plan, monitoring, recordkeeping and reporting requirements
(both for designated facilities to ensure compliance and for the state
to ensure performance of the plan as a whole), and compliance
schedules. The technical criteria further require that the state
demonstrate that the plan is projected to achieve emission performance
under the EG and that each emission standard is quantifiable, non-
duplicative, permanent, verifiable, and enforceable. As previously
described, it may not be feasible to quantify certain non-numerical
standards of performance. For a detailed description of the state plan
requirements regarding standards of performance, see section XIV.C of
this document and 40 CFR 60.24a.
In addition to these technical criteria, 40 CFR 60.25a(a) requires
that state plans include certain emissions inventory data for the
designated facilities. As explained in section XIII.C.5 of this
preamble, the EPA is, in this final action, superseding that
requirement for this EG. Further, Sec. 60.25a provides a detailed
description of what the state plan is required to include in terms of
certain compliance monitoring and reporting. States are to review the
state plan requirements included in 40 CFR 60.24a and 60.25a in
conjunction with the technical completeness criteria in 40 CFR 60.27a
to ensure their state plan submissions are complete.
In the December 2022 Supplemental Proposal, the EPA proposed to
include a provision within EG OOOOc regarding electronic submission of
state plans. However, the EPA is not finalizing the provision for
electronic submission of state plans in this rulemaking. Rather, since
similar revisions to subpart Ba regarding electronic submission are now
final and are therefore applicable to the EG OOOOc, state plans and
negative declarations must be submitted according to the provisions in
40 CFR 60.23a(3) and (b) respectively. These subpart Ba provisions
require the electronic submission of state plans and negative
declarations using the State Planning Electronic Collaboration System
(SPeCS). As specified in subpart Ba, states are not to transmit CBI
through SPeCS.\727\ The EPA found it unnecessary to also finalize
provisions related to electronic submission within EG OOOOc because
such provisions would be unnecessarily redundant with those now
included in subpart Ba.
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\727\ 88 FR 80480 (November 17, 2023).
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E. Timing of State Plan Submission and Compliance Times
1. Background and Subpart Ba
Under CAA section 111(d), each state has an obligation to submit a
plan to the EPA that establishes standards of performance for each
designated facility. The EPA acknowledged in the November 2021 Proposal
that the D.C. Circuit vacated certain timing provisions within the
version of 40 CFR part 60, subpart Ba that had been promulgated in
2019. American Lung Ass'n, 985 F.3d at 991. See 86 FR 63255 (November
15, 2021). These vacated timing requirements included: the timeline for
state plan submissions, the timeline for the EPA to act on a state
plan, the timeline for the EPA to promulgate a Federal plan, and the
timeline that dictates when state plans must include increments of
progress. As a result of the court's vacatur, no regulations governed
the timing of these actions at the time the EPA proposed this EG in
2021 and also at the time that the EPA issued the Supplemental Proposal
for this EG in 2022.\728\ In a separate rulemaking in response to the
vacatur, the EPA has now finalized new timelines in subpart Ba for
purposes of the implementing regulations.\729\ These deadlines in
subpart Ba are intended to apply generally to actions implementing EG
promulgated after July 8, 2019, under CAA section 111(d), including to
the EPA's action on state plan submissions and promulgation of a
Federal plan under the final EG OOOOc which are further discussed in
XIII.F.
---------------------------------------------------------------------------
\728\ The court did not vacate the applicability provision for
subpart Ba under 40 CFR 60.20a(a).
\729\ 88 FR 80480 (November 17, 2023).
---------------------------------------------------------------------------
In the December 2022 Supplemental Proposal,\730\ for purposes of EG
OOOOc, the EPA proposed to require that each state adopt and submit to
the Administrator, within 18 months after publication of the final EG
OOOOc, a plan for the control of GHGs in the form of limitations on
methane to which EG OOOOc applies. The EPA also proposed a uniform
compliance timeline to be as expeditiously as practicable, but no later
than 36 months following the state plan submittal deadline. Lastly, the
EPA proposed two increments of progress. The first increment of
progress was the submission of a final control plan by owners and
operators within 2 years after the deadline for the state plan
submittals. The second increment of process proposed was a notification
of final compliance report for each designated facility on or before 60
days after the compliance date of the state plan. The EPA proposed that
for the notification of final compliance report, a company would be
allowed to submit one notification that covers all of the company's
designated facilities in a state in lieu of submitting a notification
for each designated facility.
---------------------------------------------------------------------------
\730\ See 87 FR 74831 (December 6, 2022).
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The EPA received comments regarding the timing of the state plan
submission deadline and the compliance times. A summary of the comments
received and the EPA's response to these comments, including any
changes made to the final EG, as applicable are provided below. The
EPA's full response to comments on the November 2021 Proposal and
December 2022 Supplemental Proposal, including any comments not
discussed in this preamble, can be found in the EPA's RTC document for
the final rule.\731\
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\731\ Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil
and Natural Gas Sector Climate Review. Response to Public Comments
on the November 2021 Proposed Rule and the December 2022
Supplemental Proposed Rule (86 FR 63110, November 15, 2021; 87 FR
74702, December 6, 2022).
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2. Timing of State Plan Submission
Within the December 2022 Supplemental Proposal, the EPA proposed to
require that each state
[[Page 17009]]
adopt and submit to the Administrator, within 18 months after
publication of the final EG OOOOc, a plan for the control of GHGs in
the form of limitations on methane to which EG OOOOc applies. The EPA
received many comments on this proposed timeline, and is finalizing a
slightly extended deadline of 24 months after publication of the final
EG OOOOc.
Comments: A large number of state commenters in addition to other
commenters expressed that the EPA's proposed 18-month state plan
submission deadline would not provide adequate time for state plan
development and state administrative processes for adopting a plan to
regulate designated facilities.\732\ The commenters cite several
concerns with the timeframe proposed. The commenters request that the
EPA consider the impracticability of the criteria established in 40 CFR
60.5365c of the proposed regulatory text for EG OOOOc and afford states
greater flexibility to effectively develop a state plan. Specifically,
a few commenters \733\ outlined factors that affect the time needed for
states to develop and submit a plan to the EPA including the volume of
sources, limited air regulatory experience of sources, time necessary
to create an accurate source inventory, the proper notification to
those sources and information requests from sources, the possible need
for permit development, time needed for meaningful engagement and
public participation, time needed to adopt any regulatory changes that
would be necessary before submitting a state plan, time needed to
develop and draft plans that include the required components, and time
needed for adoption of the plans through their required administrative
processes before submitting them to the EPA. Other commenters stated
similar points and suggested that the 18-month timeframe would be
inadequate for source-by-source equivalency determinations, and that
states with a greater number of production wells (particularly low-
producing wells) will need additional time.\734\ The same commenters
argue that even if states were to simply adopt the presumptive
standards as proposed, the 18-month timeline would not provide states
with sufficient time for meeting the requirements. They criticize the
Agency for proposing the 18-month timeframe when the EPA itself has
taken much longer to propose and finalize a FIP for the Uinta Basin
ozone NAAQS. One state commenter asks that the EPA grant states with a
substantial number of covered sources additional time as needed.\735\
The commenter expresses concern with regards to the significant
workload and impact on the state resources, making it difficult to
complete a state plan in 18-month timeframe. Several other commenters
discuss the lengthy state administrative process and the need for
adequate time to assess any RULOF considerations.\736\ Specifically,
they argue in order to consider remaining useful life of a source in a
state plan submission, states must be able to determine the compliance
timeline by considering factors such as the source's anticipated
retirement date, costs and benefits of an available technology, and
technology that has already been deployed which they believe would
necessitate additional time for these analysis.
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\732\ Document ID Nos. EPA-HQ-OAR-2021-0317-2157, -2220, -2222,
-2224, -2237, -2241, -2292, -2296, -2310, -2322, -2330, -2393, -
2403, -2410, -2418, -2446.
\733\ Document ID Nos. EPA-HQ-OAR-2021-0317-2330, -2403.
\734\ Document ID Nos. EPA-HQ-OAR-2021-0317-2446, -2241.
\735\ Document ID Nos. EPA-HQ-OAR-2021-0317-2296, -2220.
\736\ Document ID Nos. EPA-HQ-OAR-2021-0317-2220, -2237, -2393.
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Specifically with regards to meaningful engagement, commenters
discuss that the additional requirement of meaningful engagement that,
as proposed, would have required additional outreach beyond what states
typically conduct during a routine rulemaking and state CAA section
111(d) plan development taking consequential time and resources
required to fulfill those obligations to ensure state plan
completeness.\737\ The commenter highlights the coordination that may
be needed for meaningful engagement between a state, the EPA, and
Tribal nations to address shared and neighboring jurisdictions. One
commenter provides further details on the level of effort and time
needed based on their experience of developing other state rules.\738\
According to the commenter, their state rulemaking process requires an
internal draft development phase, numerous outreach meetings to
stakeholders, and two Air Quality Advisory Board meetings. At the Air
Quality Advisory Board meeting for one proposal, the state agency
received significant comment that prompted additional review and
revisions, and an Environmental Quality Council hearing. The commenter
indicated this process took more than 18 months for development,
stakeholder engagement, and statutory process while emphasizing that
their example only addressed a subset of sources in one region of the
state and that the work necessary to implement the EG will affect
designated facilities statewide and will entail greater effort and need
additional time. The commenter states that it would appear that the
only workable option to states would be to adopt the model rule in the
EG, which they argue denies states their legal right to consider a
source's RULOF as established by the CAA.
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\737\ Document ID Nos. EPA-HQ-OAR-2021-0317-2220, -2222, -2393,
-2241.
\738\ Document ID No. EPA-HQ-OAR-2021-0317-2220.
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Some commenters provide a general recommendation for a minimum 24-
month timeline for state plan development and submission but many
suggest a need provide for additional extensions for RULOF and for
engagement with pertinent stakeholders.\739\ They tally the needed time
to upwards of 3 years to complete state plan development.\740\
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\739\ Document ID Nos. EPA-HQ-OAR-2021-0317-2157, -2220, -2296,
-2330, -2410, -2418.
\740\ Document ID Nos. EPA-HQ-OAR-2021-0317-2222, -2225, -2237,
-2241, -2310, -2322, -2393, -2403.
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On the contrary, other stakeholders argue that 18 months is too
long.\741\ One commenter suggests that 6 to 12 months would be adequate
time for states to submit their state plans.\742\ Other commenters urge
the EPA to defer to the timeframe provided in the implementing
regulations (subpart Ba).\743\ The commenters contends that the EPA did
not provide adequate evidence in the December 2022 Supplemental
Proposal, or the proposed implementing regulations under subpart Ba, to
suggest that state-level administrative processes are different for
designated facilities in the crude oil and natural gas source category
than for any other source category, and so offers no reason why the
proposed 18 months, rather than 15 months proposed in subpart Ba, are
necessary to accommodate state plan development in this category. The
commenter challenges the EPA's reasoning that EG OOOOc necessitates a
longer timeframe due to the size and variety of emission sources in the
source category.\744\ The commenter notes that this justification
appears nowhere in the EG OOOOc preamble itself and does not support an
18-month rather than 15-month submission period in any event. The
commenter further asserts that given the urgent nature of climate
change, the EPA must ensure that its proposed EG
[[Page 17010]]
OOOOc are implemented as swiftly as possible. The commenter urges the
EPA to apply the proposed default 15-month timeline for state plan
submissions proposed in subpart Ba under EG OOOOc rather than the
extended 18-month period.
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\741\ Document ID Nos. EPA-HQ-OAR-2021-0317-2201, -2433.
\742\ Document ID No. EPA-HQ-OAR-2021-0317-2201.
\743\ Document ID Nos. EPA-HQ-OAR-2021-0317-2392, -2433.
\744\ 87 FR 79181.
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Response: The proposed 18-month submittal timeline the EPA proposed
for EG OOOOc was based on the EPA's proposed determination that this
was a reasonably expeditious deadline that would provide states
sufficient time to develop and submit an approvable state plan. After
evaluation of the comments received, the EPA agrees with commenters
that additional time is warranted for the state plan submittal for EG
OOOOc. The EPA disagrees with commenters claiming that substantially
less time would be adequate time for states to submit complete state
plans. The EPA clarifies that while state-level administrative
processes are not different for designated facilities in the crude oil
and natural gas source category than for any other source category,
there are numerous reasons why the EPA believes it is appropriate to
supersede the state plan submittal timeframe of the subpart Ba
implementing regulations in EG OOOOc. Furthermore, in the December 2022
Supplemental Proposal (87 FR 74831 to 74835), the EPA discussed its
considerations with respect to the characteristics and unique nature of
the crude oil and natural gas source category in comparison to other
EG. In response to comments on this discussion, the EPA provides
further explanation.
When developing a state plan submittal, the requirements of the
recently finalized subpart Ba apply. This subpart imposes baseline
requirements that the state must meet when developing its state plan in
response to this EG OOOOc. Meeting those requirements takes time. There
are also state-specific processes applicable to the development and
adoption of a state plan, including the administrative processes (e.g.,
permitting processes, regulatory development, legislative approval)
necessary to develop and adopt enforceable standards of performance.
State plan development generally involves several phases, including
providing notice that the state agency is considering adopting a rule;
taking public comment; and approving or adopting a final rule. The
process required to formally adopt a rule at the state level differs
from state to state.
Moreover, there are several recently added requirements in subpart
Ba (for example, meaningful engagement) that states may be undertaking
for the first time when developing their state plan submission in
response to the final oil and natural gas EG. Further, the EPA
generally agrees with commenters that meeting the requirements of
subpart Ba within the context of their state plan submittal for EG
OOOOc require time. For example, there are many diverse stakeholders
who have equities and interests in how this industry is regulated.
These stakeholders may submit many complex comments to the state during
the state's plan development process. The EPA received over 470,000
comments on the November 2021 Proposal and over 515,000 comments on the
December 2022 Supplemental Proposal. While it would be unusual for a
state plan to garner this same number of comments as a national
rulemaking, it is nonetheless reasonable to assume these larger than
typical number of comments are an indication of the increased level of
interest that state plans are likely to receive. Since the state is
required to include responses to comments received in their state plan
submittal, development of plans for this EG could take longer than
typical. Subpart Ba, 60.27a(g)(2)(viii).
In addition to the baseline requirements of subpart Ba, these EG
also impose unique circumstances to consider on states. For example,
the EPA explained in the December 2022 Supplemental Proposal that EG
OOOOc has the potential to require states to perform considerable
engineering and/or economic analyses for their plan. For purposes of
these EG, states will be required to establish standards of performance
for nine different types of designated facilities, of which three have
numerical limits and six are in the format of non-numerical standards.
The designated facilities are also geographically spread out covering
multiple industry segments. If a state wishes to utilize the
flexibilities explained in section XIII.C.2 of this preamble related to
leveraging an existing state program, determining equivalency, and/or
averaging, then the requisite analysis can be time consuming. Contrary
to some commenters' assertions, the EPA explained these concerns at 87
FR 74833 and 74834 of the December 2022 Supplemental Proposal. Those
commenters that suggest that states need less time to submit plans did
not appear to address these concerns that the EPA expressed or the
requirements of state laws governing the development and submission of
plans. We still find these to be compelling reasons to allow the states
even more time to develop and submit their plans for this EG.
Therefore, the EPA is superseding the timeline included in subpart
Ba and is finalizing 24 months for the timing of the state plan
submissions for purposes of EG OOOOc. The EPA believes that 24 months
from the time the EG is published will be adequate to complete state
administrative processes, conduct public hearings, engage with
pertinent stakeholders, and meet all other applicable requirements of
subpart Ba. This timeline represents a reasonable balance between
providing states sufficient time to develop and submit a plan that
satisfies the applicable requirements and ensuring that the emission
reductions contemplated in an EG are achieved as expeditiously as
practicable. While the EPA recognizes that states need time to follow
their state-specific processes and laws, we are also aware from the
Agency's experience with SIPs that some states have adopted, or may
adopt, procedures that are longer than necessary and that could delay
Federal emission-reduction obligations. Extending the state plan
submittal deadline beyond 24 months to account for any and all unique
state procedures would inappropriately delay reductions in emissions
that have been found under CAA section 111 to endanger health or the
environment. The timeline of 24 months strikes an appropriate balance
for this EG between the state's need for time and the EPA's
responsibility to ensure expeditious implementation in consideration of
the important benefits of the pollution reductions. This balance also
comports with the court's reasoning in American Lung Ass'n (985 F.3d
914 (D.C. Cir. 2021)).
Furthermore, the EPA finds that 24 months will accommodate the
challenges commenters identified and help ensure states have the time
to ensure their plans are complete and approvable to ensure that the EG
will be timely implemented given the urgent need of climate change. The
EPA recognizes that the recent revisions to subpart Ba include a state
plan submittal timeline of 18 months. To avoid any potential confusion,
the EPA is clarifying that the state plan submittal timeline of 24
months being finalized in this action for EG OOOOc supersedes the
default timeline in subpart Ba, but only for purposes of those state
plans submitted in accordance with this EG OOOOc.
3. Compliance Timelines
Within the November 2021 Proposal, the EPA proposed to require that
state plans require designated facilities to
[[Page 17011]]
come into full compliance with the applicable standards of performance
as expeditiously as practicable, but no later than 2 years following
the state plan submittal deadline. Based on comments received on the
November 2021 Proposal, the EPA extended this timeline to 36 months in
the December 2022 Supplemental Proposal (87 FR 74835-74837). The EPA is
finalizing the compliance timeline of 36 months from the deadline for
state plan submittals.
Comments: Numerous commenters express concern that the proposed 36-
month compliance timeline does not provide adequate implementation time
for owners and operators to accomplish successful emission reductions
for the tens of thousands of facilities.\745\ Commenters highlight
constraints on equipment supplies particularly for converting to zero-
emissions equipment for process controllers and pumps. The commenters
believe that the scope and breadth of the EG will exacerbate existing
delays in acquiring equipment on such a large scale. One commenter
articulates that more time is needed to account for the cumulative
burden of the multiple actions that the EPA is finalizing, and that
owners and operators need time to understand how all the rules are
intended to interact together.\746\
---------------------------------------------------------------------------
\745\ Document ID Nos. EPA-HQ-OAR-2021-0317-2288, -2237, -2296,
-2403, -2423.
\746\ Document ID No. EPA-HQ-OAR-2021-0317-2423.
---------------------------------------------------------------------------
Some commenters recommend that the EPA establish a final compliance
timeline that begins with the date of the EPA's approval of the state
plan rather than the state plan submission date.\747\ Other commenters
state that the final compliance date should be no less than the
proposed 36-month timeline.\748\ One commenter adds that states and
operators are ill-equipped and unprepared to comply with the EG.\749\
For example, the commenter states that certain presumptive standards,
like fugitive emissions monitoring requirements, have a regulatory
framework that is dependent on component counts which is different than
how some states or existing sources have tracked their facilities, so
time is needed to understand and establish a new framework for tracking
regulatory requirements. The commenter furthermore stresses that states
have considerable staffing shortages and that it will take additional
time for designated facilities and states to process necessary
reporting requirements or updating of permits.
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\747\ Document ID Nos. EPA-HQ-OAR-2021-0317-2403, -2446.
\748\ Document ID Nos. EPA-HQ-OAR-2021-0317-2288, -2237.
\749\ Document ID No. EPA-HQ-OAR-2021-0317-2304.
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Other commenters take the opposite position. One commenter states
that designated facilities should not receive additional compliance
time at the expense of the public interest in pollution reduction, and
urges the EPA to require accelerated compliance in states with higher
methane emissions from designated facilities.\750\ Several other
commenters suggest that for standards that do not require the
installation of new equipment, the compliance timeline should be
accelerated.\751\ They identify that designated facilities other than
oil wells with associated gas, storage vessels, process controllers,
and pumps, such as alternative leak detection programs, should be
placed on faster compliance timelines. According to commenters,
fugitive and leak detections programs and alternative leak detection
programs can be implemented relatively quickly and inexpensively as
compared to equipment retrofits. They believe that the EPA has failed
to justify why such a lengthy compliance period would be necessary for
these types of sources. The commenter adds that the desire to simplify
compliance and ease the burden on industry operators is not a valid
basis for this timeframe under the statute and not warranted by these
circumstances. Furthermore, they argue that leak detection standards
are not impacted by supply chain and logistical issues in the same way
as standards requiring equipment procurement and possible shutdowns of
designated facilities, such as standards for process controllers,
pumps, and storage vessels. The commenters suggest a shortened timeline
for compliance for these facilities of no more than 6 months to 1 year
after the EPA's approval of a state plan.
---------------------------------------------------------------------------
\750\ Document ID No. EPA-HQ-OAR-2021-0317-1659.
\751\ Document ID Nos. EPA-HQ-OAR-2021-0317-2028, -2284, -2392,
-2410, -2433.
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Commenters advocating for an earlier compliance timeline for some
sources identify the advantages of phasing-in leak detection programs
for EG OOOOc and recommend incentivizing earlier compliance. For
example, the commenter asks the EPA to consider incentivizing a
separate, earlier phase-in period for control strategies that do not
involve significant capital expenditures or retrofits which could be
used to balance emissions from areas of the rule that may require
additional time to implement. The commenters suggest the EPA consider
adopting a shorter timeline than proposed, such as 24 to 30 months
after plan submission deadlines, for sources that do not require
capital expenditures for compliance. Another commenter recommends that
the EPA reconsider whether to accelerate the timeline for compliance
for specific performance standards.\752\ The commenter notes that the
EPA should reconsider whether the benefits of the proposed three-year
uniform deadline may be overstated and whether the urgency of the
health and environmental harms that state plans will address merits a
shorter deadline for compliance to increase net benefits for society.
According to the commenter, the EPA has given some consideration to the
need for expeditious compliance, but given the December 2022
Supplemental Proposal's significant health and environmental benefits,
the EPA should reevaluate the feasibility of a more aggressive
compliance schedule that would allow these benefits to be realized
sooner. The commenter recommends that to select which standards of
performance merit an earlier compliance deadline, the EPA should apply
the nine factors that the EPA identified for this purpose in the
December 2022 Supplemental Proposal (e.g., supply-chain issues).\753\
However, in lieu of the existing second and ninth factors (``[t]he cost
of equipment'' and ``overall methane emissions reduction that will
result from control of existing sources under the [emissions
guideline]''), the commenter suggests that it would be preferable to
examine net benefits. Compared to methane emissions reductions alone,
looking to net benefits would allow for consideration of all relevant
costs and benefits--including benefits from methane's co-pollutants
emitted along with methane--when evaluating whether to prioritize
compliance with one standard of performance over another. The commenter
continues that, the nine factors indicate that the EPA should
substantially shorten the timeline for existing sources to comply with
the super-emitter response program. The EPA's concerns about the costs
of simultaneous implementation across the sector and planning burdens
do not apply to this program. For the same reasons that 14 days is too
long to wait before acting on a single super-emitter event, the
commenter states that 3 years is too long to wait for the entire
program. The commenter suggests that, in instances where the EPA has
[[Page 17012]]
differentiated between subcategories of affected facilities, the EPA
should further consider accelerating compliance for select
subcategories if doing so appears more net beneficial than subjecting
all designated facilities to the same deadline. The commenter provides
that staggering compliance across tiers within a single EG could reduce
the planning burden on entities in a given year and help prevent
bottlenecks for specialized equipment and services by spreading
compliance deadlines out over time. For instance, the commenter points
out the consideration of fugitive emissions at wells, a category that
the EPA already divides into four tiers with different monitoring
requirements based on the number of wells at the site and the presence
of major equipment. The commenter states that the EPA could apply the
same nine factors discussed above to designate one or more tiers of
wells subject to an accelerated compliance timeline. The commenter adds
that the EPA could conduct a similar assessment for its four potential
subcategories for pneumatic controllers (well sites, gathering and
boosting stations, transmission and storage compressor stations, and
natural gas processing plants). The commenter notes that this tiering
of compliance deadlines may increase net benefits relative to waiting 3
years for all four tiers because a subset of the December 2022
Supplemental Proposal's benefits would be achieved sooner and thus
accrue over the additional time. While annual costs would also accrue
over the additional time, the commenter believes that the benefits
would most likely exceed the costs to the same extent as they are
projected to do so for future years.
---------------------------------------------------------------------------
\752\ EPA-HQ-OAR-2021-0317-2343.
\753\ See Table 38 in the December 2022 Supplemental Proposal at
87 FR 74835.
---------------------------------------------------------------------------
Response: The EPA disagrees with the comments suggesting additional
time is necessary. When the compliance timeline of 36 months is
considered in conjunction with the state plan submittal deadline of 24
months, that means that sources could have up to 5 years between when
the EG are final and when they are required to fully comply with the
applicable standards of performance. The EPA believes that any concerns
with possible equipment or staffing shortages, which commenters
speculate could be an issue, would likely be addressed by industry and
regulators in that timeframe. The EPA did evaluate the types of factors
that commenters raised, as explained in the December 2022 Supplemental
Proposal (87 FR 74835, table 38). After re-considering these factors in
conjunction with the comments received on the December 2022
Supplemental Proposal, the EPA still finds that 36 months is
appropriate because commenters did not present the EPA with convincing
information to suggest that the assumptions made in the 2022
Supplemental Proposal were inaccurate.
The EPA agrees to a certain extent with some comments that suggest
the Agency could have taken a different approach wherein we could have
established different compliance timelines for different types of
designated facilities. The EPA discussed this consideration in the
December 2022 Supplemental Proposal at 87 FR 74836. After considering
comments, the EPA still believes that it is appropriate to finalize a
uniform outermost compliance deadline for purposes of these EG. In
addition to the reasoning for preferring uniformity and easing burden
explained in the December 2022 Supplemental Proposal, which the EPA
believes to still hold true (and which commenters do not appear to take
direct issue with), the EPA believes that many of the issues raised by
commenters could be more appropriately addressed by states during plan
development. The EPA highlights that this compliance deadline included
in the final EG represents the furthest date into the future that the
EPA finds appropriate for a state to allow as a final compliance
deadline for the state's standards of performance. Put another way, the
36-month timeline is the most time that the EPA believes a state will
need to allow for sources to come into compliance. However, states are
free to establish compliance timelines within their state plan
submittals for certain designated facilities that are shorter than 36
months, and indeed states should be examining shorter timelines as a
possibility to ensure that sources come into compliance with their
respective standards of performance as expeditiously as practicable.
Subpart Ba is clear that ``final compliance shall be required as
expeditiously as practicable, but no later than the compliance times
specified in an applicable subpart of this part.'' By finalizing the
outermost compliance deadline of 36 months, the EPA is not suggesting
that it is necessarily appropriate for all compliance timelines in all
state plans to be set at 36 months. On the contrary, states must
require designated facilities to come into final compliance with their
standards of performance ``as expeditiously as practicable.'' The time
needed for particular groups of existing sources to come into full
compliance with a state's standards depends on many factors including
the specifics of that yet-to-be-determined standard as well as the
preexisting regulatory framework, if any. The EPA cannot account for
all these possible variables when establishing these EG, but states
can, and should, account for specific circumstances in their state
plans because they will have the relevant facts available to them when
developing their state plan submittals.
F. The EPA's Action on State Plans and Promulgation of Federal Plans
The EPA finalized deadlines for its action on state plan
submissions and for promulgation of a Federal plan in a separate
rulemaking for the implementing regulations (subpart Ba).\754\ See 40
CFR 60.27a. Unless superseded by a particular EG, the subpart Ba
deadlines apply generally to all EG promulgated after July 8, 2019,
under CAA section 111(d), and also apply to the EPA's action on state
plan submissions and promulgation of a Federal plan under the final EG.
The EPA is not superseding the deadlines in the final oil and natural
gas EG OOOOc. As such, the deadlines included in the final revisions
for subpart Ba for the EPA action on a state plan submit and for
promulgation of a Federal plan apply in the context of this EG.
---------------------------------------------------------------------------
\754\ 88 FR 80480 (November 17, 2023).
---------------------------------------------------------------------------
As discussed in the November 2021 Proposal and December 2022
Supplemental Proposal, it was not necessary for the EPA to propose
deadlines for the EPA's action on state plans submitted in response to
a final EG OOOOc, or for the promulgation of a Federal plan where a
state fails to submit an approvable plan, as part of the November 2021
Proposal or December 2022 Supplemental Proposal, because these
deadlines are not relevant to states in the development of their plans.
Additionally, as described in section XIII.E of this document, the EPA
proposed and is finalizing in EG OOOOc the final compliance schedule
for designated facilities to run from the deadline for state plan
submissions.
The EPA subsequently provides this process information for
stakeholder awareness. While CAA section 111(d)(1) authorizes states to
develop state plans that establish standards of performance and
provides states with certain discretion in determining the appropriate
standards, CAA section 111(d)(2) provides the EPA a specific oversight
role with respect to such state plans. CAA section 111(d)(2) authorizes
the EPA to prescribe a Federal plan for a state ``in cases where the
state fails to submit a satisfactory plan.'' The states must therefore
submit their plans to the
[[Page 17013]]
EPA, and the EPA must evaluate each state plan to determine whether
each plan is ``satisfactory.'' The EPA's implementing regulations for
CAA section 111(d) accordingly provide procedural requirements for the
EPA to make such a determination. See 40 CFR 60.27a.
Upon receipt of a state plan, the EPA is first required to
determine whether the state plan submittal is complete in accordance
with the completeness criteria explained above. See 40 CFR 60.27a(g).
Per the finalized amendments to subpart Ba, the EPA has 12 months to
act on a state plan after the plan is deemed complete. Id. at
60.27a(b). If the EPA determines that the state plan submission is
incomplete, then the state will be treated as not having made the
submission, and the EPA would be required to promulgate a Federal plan
for the designated facilities in that state within 12 months. Likewise,
if a state does not make any submission by the applicable deadline for
state plan submissions, then the EPA is required to promulgate a
Federal plan within 12 months. If the EPA does not make an affirmative
determination regarding completeness of the state plan submission
within 60 days of receiving the submittal, then the submission is
deemed complete by operation of law.
If a state has submitted a complete plan, then the EPA is required
to evaluate that plan submission for approvability in accordance with
the CAA, the EPA's implementing regulations, and the applicable EG. The
EPA may approve or disapprove the state plan submission in whole or in
part. See 40 CFR 60.27a(b). If the EPA approves the state plan
submission, then that state plan becomes Federally enforceable. If the
EPA disapproves the required state plan submission, in whole or in
part, then the EPA is required to promulgate a Federal plan for the
designated facilities in that state via a notice-and-comment
rulemaking, and with an opportunity for public hearing. In the case of
a disapproval, the scope of the disapproval (in whole or in part)
defines the scope of the EPA's duty to issue a Federal plan. The EPA
will also promulgate a Federal plan if a state fails to submit a plan
by the state plan submission deadline and if a state submission is
determined to be incomplete. See 40 CFR 60.27a(c) and (f). The EPA
would not be required to promulgate the Federal plan if the state
corrects the deficiency giving rise to the EPA's duty and the EPA
approves the state's plan before promulgating the Federal plan.
Requirements regarding the content of a Federal plan are included in 40
CFR 60.27a(e).
G. Tribes and the Planning Process Under CAA Section 111(d)
Under the TAR adopted by the EPA, Tribes may seek authority to
implement a plan under CAA section 111(d) in a manner similar to a
state. See 40 CFR part 49, subpart A. Tribes may, but are not required
to, seek approval for treatment in a manner similar to a state for
purposes of developing a TIP implementing the EG. If a Tribe obtains
approval and submits a TIP, the EPA will generally use similar criteria
and follow similar procedures as those described above for state plans
when evaluating the TIP submission, and will approve the TIP if
appropriate. The EPA is committed to working with eligible Tribes to
help them seek authorization and develop plans if they choose. Tribes
that choose to develop plans will generally have the same flexibilities
available to states in this process. If a Tribe does not seek and
obtain the authority from the EPA to establish a TIP, the EPA has the
authority to establish a Federal plan under CAA section 111(d) for
areas of Indian country where designated facilities are located. A
Federal plan would apply to all designated facilities located in the
areas of Indian country covered by the Federal plan unless and until
the EPA approves an applicable TIP applicable to those facilities.
XIV. Use of Optical Gas Imaging in Leak Detection (Appendix K) and
Response to Significant Comments
A. Summary of Requirements
In this action, the EPA is finalizing a protocol for the use of OGI
as appendix K to 40 CFR part 60. The EPA notes that while this protocol
is being finalized in this action, the applicability of the protocol is
broader. The protocol is applicable to facilities when specified in a
referencing subpart to help determine the presence and location of
leaks; it is not currently applicable for use in direct emission rate
measurements from sources. The protocol does not on its own apply to
any sources; it applies only where a specific rule subpart incorporates
it by reference and specifies the sources to which it applies. In this
case, we are finalizing the use of the protocol only for implementing
the standards for process units at natural gas processing plants that
are being finalized in this action.
Once incorporated into a subpart, the protocol would only be
applicable for surveys of process equipment using OGI cameras where the
majority of compounds (>75 percent by weight) in the emissions streams
have a response factor of at least 0.25 when compared to the response
factor of propane. Additionally, the OGI camera used for surveying must
also be capable of detecting (or producing a detectable image of)
methane emissions of 19 g/hr and either butane emissions of 29 g/hr or
propane emissions of 22 g/hr at a viewing distance of 2.0 meters and a
delta-T of 5.0 [deg]C in an environment of calm wind conditions around
1.0 meter per second or less. Verification that the OGI camera meets
these criteria may be performed by the owner or operator, the camera
manufacturer, or a third party.
Field conditions, such as the viewing distance to the component to
be monitored, wind speed, ambient air temperature, and the background
temperature, have the potential to impact the ability of the OGI camera
operator to detect a leak. Because it is important that the OGI camera
has been tested under the full range of expected field conditions in
which the OGI camera will be used, an operating envelope must be
established for field use of the OGI camera. Imaging must not be
performed when the conditions are outside of the developed operating
envelope. Operating envelopes are specific to each model of OGI camera
and can be developed by the owner or operator, the camera manufacturer,
or a third party. To develop the operating envelope, methane gas is
released at a set mass rate and wind speed, viewing distance, and
delta-T (the temperature differential of the background and the
released gas) are all varied to determine the conditions under which a
leak can be imaged. For purposes of developing the operating envelope,
a leak is considered able to be imaged if three out of four observers
can see the leak. Once the operating envelope is developed using
methane, the testing is repeated with either butane or propane gas. The
operating envelope for the OGI camera is the more restrictive operating
envelope developed between the different test gases. The operating
envelope must be confirmed for all potential configurations that could
impact the detection limit of the OGI camera.
In cases where an operating envelope has not yet been established
for an OGI camera model or an OGI camera operator needs to expand an
operating envelope to account for site-specific conditions, the OGI
camera operator can conduct a daily field check for maximum viewing
distance prior to conducting the monitoring survey. The daily field
check must be conducted for each OGI camera operator who will conduct
the monitoring survey using the OGI camera (and each camera
configuration) they will use to complete
[[Page 17014]]
the monitoring survey. The daily field check must be performed using
the same gases and flow rates used for setting the operating envelope
and initial verification check. The maximum viewing distance for the
day for the OGI camera operator will be the farthest viewing distance
where the OGI camera operator is able to visualize a leak of both test
gases. A complete video record, as well as documentation of the delta-
T, wind speed, and viewing distance, must be retained for the daily
field check. If the delta-T in the field decreases below the delta-T
that was recorded for the daily field check or if the wind speed
increases above the wind speed recorded for the daily field check, the
maximum viewing distance determination must be repeated for the new
delta-T and wind speed conditions. A description of how the OGI camera
operator will monitor viewing distance, delta-T, and wind speed must be
included in the monitoring plan.
Each site must have a monitoring plan that describes the procedures
for conducting a monitoring survey. One monitoring plan can be used for
multiple sites, as long as the plan contains the relevant information
for each site. The monitoring plan must contain procedures for a daily
verification check, ensuring that the monitoring survey is performed
only when conditions in the field are within the operating envelope,
monitoring all the components regulated by the referencing subpart
within the unit or area, viewing the components with the camera, how
the operator will ensure an adequate delta-T is present in order to
view potential gaseous emissions, operator rest breaks, documenting
surveys, and quality assurance.
The EPA is finalizing requirements to view each component from at
least two different angles. The OGI camera operator must dwell on each
angle for a minimum time, where dwell time is defined as the time the
scene is steady and in focus and the operator is actively viewing the
scene. For a simple scene consisting of 10 or fewer components, the
camera operator must dwell for a minimum of 10 seconds per angle. For a
scene with greater than 10 components, the camera operator must dwell
for a minimum of 2 seconds per component in the field of view.
Each facility or company performing OGI surveys must have a
training plan which ensures and monitors the proficiency of the OGI
camera operators. If the facility does not perform its own OGI
monitoring, the facility must ensure that the training plan for the
company performing the OGI surveys adheres to this requirement.
Appendix K prescribes a multi-faceted approach to training. Training
includes classroom instruction (either online, remotely, or at a
physical location) both initially and biennially on the OGI camera and
external devices, monitoring techniques, best practices, process
knowledge, and other regulatory requirements related to leak detection
that are relevant to the facility's OGI monitoring efforts. Prior to
conducting monitoring surveys, camera operators must demonstrate
proficiency with the OGI camera. The initial field training includes a
minimum of 30 survey hours with OGI where trainees first observe the
techniques and methods of a senior OGI camera operator and then
eventually perform monitoring surveys independently with a senior OGI
camera operator present to provide oversight. The trainee must then
pass a final monitoring survey test of at least 2 hours. If there are
10 or more leaks identified by the senior OGI operator, the trainee
must achieve less than 10 percent missed persistent leaks relative to
the senior OGI camera operator to be considered authorized for
independent survey execution. If there are less than 10 leaks
identified by the senior OGI operator, the trainee must achieve zero
missed persistent leaks relative to the senior OGI camera operator to
be considered authorized for independent survey execution. If the
trainee doesn't pass the monitoring survey test, the senior OGI camera
operator must discuss the reasons for the failure with the trainee and
provide instruction/correction on improving the trainee's performance,
following which the trainee may repeat the final test.
Performance audits for all OGI camera operators must occur on a
quarterly basis and can be conducted either by comparative monitoring
or video review by a senior OGI camera operator. If the senior OGI
camera operator finds that the survey techniques during the video
review do not match those described in the monitoring plan, then the
camera operator being audited will need to be retrained. Additionally,
if there are 10 or more leaks identified by the senior OGI operator,
the camera operator being audited must achieve less than 10 percent
missed persistent leaks relative to the senior OGI camera operator. If
there are less than 10 leaks identified by the senior OGI operator, the
camera operator being audited must achieve zero missed persistent leaks
relative to the senior OGI camera operator. Retraining consists of a
discussion of the reasons for the failure with the OGI operator being
audited and techniques to improve performance; a minimum of 16 survey
training hours; and a final monitoring survey test. If an OGI operator
requires retraining in two consecutive quarterly audits, the OGI
operator must repeat the initial training requirements.
Previous experience with OGI camera operation can be substituted
for some of the initial training requirements. OGI camera operators
with previous classroom training (either at a physical location or
online) that covers the majority of the elements required by the
initial classroom training required in appendix K prior to the
publication date of this final rule do not need to complete the initial
classroom training, but if the date of certification is more than 2
years before the publication date of the final rule, the biennial
classroom training must be completed in lieu of the initial classroom
training. OGI camera operators who have 40 hours of experience over the
12 calendar months prior to the date of publication of the final rule
may substitute the retraining requirements, including the final
monitoring survey test, for the initial field training requirements.
Appendix K requires records to be retained in hard copy or
electronic form. Records include the site monitoring plan, operating
envelope limitations, data supporting the initial OGI camera
performance verification and development of the operating envelope, the
training plan for OGI camera operators, OGI camera operator training
and auditing records, records necessary to verify senior OGI camera
operator status, monitoring survey records, quality assurance
verification videos for each operator, and maintenance and calibration
records. Some of the records required by the proposed appendix K are
not required to be kept onsite as long as the owner or operator can
easily access these records and can make the records available for
review if requested by the Administrator.
B. Changes Since Supplemental Proposal
This section of this preamble presents a summary of significant
comments received on the EPA's protocol for the use of OGI in leak
detection being finalized as appendix K to 40 CFR part 60 (referred to
hereafter as appendix K) and the EPA's response to those comments. This
section also presents changes that have been made to appendix K since
the December 2022 Supplemental Proposal.
1. Dwell Time
Comment: Several commenters suggested that the dwell time
requirement in appendix K should be
[[Page 17015]]
removed.\755\ The commenters felt that the dwell time requirements were
overly restrictive, and dwell time should be left to the discretion of
the trained operator. One commenter \756\ stated that the proposed
viewing requirements would increase survey time approximately four-
fold. Commenters were also critical of the proposed allowance for
reduction of the dwell time for complex scenes based on the monitoring
area and number of components according to table 14-1 of appendix
K.\757\ These commenters argued that dwell times and angles are
unnecessary, burdensome, and impractical to implement.
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\755\ EPA-HQ-OAR-2021-0317-2177, -2258, -2421, -2428, and -2196.
\756\ EPA-HQ-OAR-2021-0317-2483.
\757\ EPA-HQ-OAR-2021-0317-2366 and -2483.
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Some commenters provided suggestions for alternative dwell times.
One commenter \758\ suggested that a minimum of 3 seconds per scene
would be appropriate, while another commenter \759\ recommended a
maximum dwell time of 5 seconds per angle of view for scenes with
multiple components. A third commenter \760\ suggested that scenes be
differentiated according to the number of components being imaged and
viewing distance. The commenter stated that an example of a ``simple''
scene would be a scene of 20-25 components viewed from a distance of
15-25 feet. The commenter stated that this approach offers a high
probability of leak detection by a technician and limiting the number
of components to 25 in a simple scene means a technician is likely to
have great discernment or granularity of the image which improves the
ability to detect a leak.
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\758\ EPA-HQ-OAR-2021-0317-2305.
\759\ EPA-HQ-OAR-2021-0317-2421.
\760\ EPA-HQ-OAR-2021-0317-2428.
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Response: The EPA considers dwell time an important component of an
OGI monitoring protocol. It is important to specify the minimum amount
of time that OGI camera operators must survey a scene in order to
reliably assess whether leaks are present. Surveying a scene too
quickly can lead to OGI camera operators not identifying leaks,
potentially leading to an increase in fugitive emissions over time by
leaving the leaks unaddressed. The EPA therefore disagrees with the
comment suggesting removal of the dwell time requirement.
To be clear on our intent, in the final rule, the EPA has clarified
that the dwell time requirements in appendix K represent the minimum
amount of time required to survey a scene in order to provide adequate
probability of leak detection, and that dwell time begins only after
the OGI camera operator has put the camera in an appropriate operating
mode and the scene is in focus and steady. If the OGI camera operating
mode must be changed, the dwell time restarts. We have further
clarified that additional dwell time beyond the minimum requirement may
be necessary to adequately monitor for leaks, depending on conditions
and configuration of the components. OGI camera operators should use
training and knowledge of conditions to adjust dwell time when needed.
However, the EPA agrees with commenters that allowing for a
standard dwell time instead of requiring the dwell time to be based on
the number of components is appropriate in some instances. In the final
rule, the EPA is removing table 14-1 in the proposed appendix K, which
was a mechanism intended to allow a reduction in dwell time by reducing
the number of components being visualized at one time. Instead, the EPA
is finalizing a standard dwell time requirement for ``simple'' scenes.
To implement this change, we have created a definition for a simple
scene in appendix K, where a simple scene is defined as a scene
consisting of 10 or fewer components. For a simple scene, the OGI
camera operator must dwell for a minimum of 10 seconds per angle. The
EPA disagrees that a standard dwell time should be extended to scenes
that do not qualify as a simple scene (i.e., a scene with greater than
10 components) because these scenes are often very complex with
complicated backgrounds and an increased density of components. These
factors make it more difficult for OGI camera operators to visualize
the individual components in the scene, and an OGI camera operator
needs to spend more time looking at the individual components to ensure
there are no leaks. For these scenes, the EPA is retaining the
requirement, as proposed, that the OGI camera operator must dwell on
the scene for a minimum of 2 seconds per component in the field of
view. As we noted in the December 2022 Supplemental Proposal,\761\ 2
seconds per component in the field of view aligns closely with the
estimated time to complete a monitoring survey based on data provided
by OGI camera operators and provides adequate time to determine whether
a leak is present. Although commenters suggested different timeframes
for a minimum dwell time, the commenters did not provide substantive
information on why these different minimum dwell times would ensure
that an OGI camera operator views a scene long enough to find all leaks
that exist. The EPA notes that OGI camera operators can choose to
reduce the dwell time of these more complex scenes by reducing the
viewing distance from components, thereby reducing the number of
components in the field of view and changing the more complex scene
into a simple scene. This would allow the OGI camera operator to use
the standard dwell time for simple scenes.
---------------------------------------------------------------------------
\761\ 87 FR 74839 (December 6, 2022).
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2. Detection Limits
Comment: One commenter \762\ agreed with the new minimum detection
level of butane as 5 grams per hour (g/hr) but questioned the level of
detection for propane. The commenter stated that the foundation of
appendix K and OGI as a technology is based on the response factors,
per section 6.1.1 and Annex 1 of appendix K. Therefore, the commenter
states that propane (a compound with a response factor of 1.000) should
not have a detection threshold higher than methane (a compound with a
response factor of 0.297). The commenter recommended that propane have
a minimum detection level similar to butane, 5 g/hr, since it is also
over 3.3 times more absorptive for the defined technology in the
spectral range of the technology, and the commenter suggested that all
references to the minimum detection threshold of propane in section 8
also be changed to 5 g/hr. Another commenter \763\ questioned why a
lower mass rate criteria was selected for butane when the response
factor for butane and propane are almost identical. The commenter
stated that this seems inconsistent with the language in section 1.2,
which allows for the average response factor approach with respect to
propane.
---------------------------------------------------------------------------
\762\ EPA-HQ-OAR-2021-0317-2421.
\763\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------
Response: The EPA reviewed the detection limit criteria included in
the December 2022 Supplemental Proposal in light of the comments and
updated the TSD for appendix K. As noted in the updated TSD that
accompanies the final appendix K, the expected field detection limit of
propane is 22 g/hr. Based on this detection limit and updated response
factors \764\ for methane and n-butane, we have determined that the
field detection limits of methane and n-butane are 19 g/hr and 29 g/hr,
respectively. It may seem
[[Page 17016]]
counterintuitive that propane has a greater detection limit than
methane, even though propane has a higher response factor. This is due
to the difference in the molecular weights of the compounds. Molecular
weight is used to convert between the concentration (ppmv) and mass
flowrate (g/hr). Because propane is nearly three times as heavy as
methane, the detection limit for propane, when expressed as a mass
flowrate, is higher than the detection limit for methane. Similarly,
butane is heavier than propane, so the detection limit expressed as a
mass flowrate is higher for butane than for propane.\765\
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\764\ See August 18, 2023, email from Yousheng Zeng to Gerri
Garwood, included in the docket for this action.
\765\ See TSD, Optical Gas Imaging Protocol (40 CFR part 60,
Appendix K). September 2023. Pages 124-125.
---------------------------------------------------------------------------
While we note that the laboratory detection limits will be lower
than this, as demonstrated in the supporting documentation provided in
the OGI detection estimation memo \766\ included in the docket, because
the detection limits in appendix K are used to set the operating
envelope, it is important that they are achievable in the field, not
just the laboratory. We have updated the final appendix K TSD and final
text within appendix K to reflect these updated detection limits. We
have also updated the final appendix K TSD to discuss the derivation of
the field detection limits for compounds other than propane.
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\766\ EPA-HQ-OAR-2021-0317-1532.
---------------------------------------------------------------------------
3. Operating Envelopes
Comment: One commenter \767\ stated the operating envelope is
overly complicated and that daily field checks ensure the camera
operator can identify fugitive emissions and set a maximum viewing
distance. The commenter suggested that a change in weather that could
significantly alter the viewing distance could trigger a retest to
ensure the viewing distance set point is still adequate to identify
fugitive emissions. Another commenter \768\ maintained that most OGI
camera manufacturers plan to have completed the development of the
operating envelopes after appendix K is promulgated but urged that a
daily or site-specific distance check should remain an option. The
commenter acknowledged that there may be times when OGI camera
operators will be using an OGI camera that does not yet have any
established operating envelopes either because the camera manufacturer
has yet to publish operating envelopes once appendix K is promulgated,
the OGI camera is new to market, or monitoring conditions for a
specific survey or site are unique regarding the pre-defined operating
envelopes and the camera operator may want to ensure that the delta-T
and viewing distance are appropriately set.
---------------------------------------------------------------------------
\767\ EPA-HQ-OAR-2021-0317-2305.
\768\ EPA-HQ-OAR-2021-0317-2428.
---------------------------------------------------------------------------
Response: The EPA agrees that there may be times when an OGI camera
model does not yet have an established operating envelope, such as
immediately after development of the OGI camera, or when an OGI camera
operator may need to adjust an operating envelope to account for site-
specific conditions, such as wind speed. In the final appendix K, the
EPA has added an option to conduct a daily field check for distance in
lieu of using a pre-defined operating envelope. The EPA notes that this
is an optional field check for distance when an OGI camera operator is
not using a pre-defined operating envelope. For OGI camera operators
using a pre-defined operating envelope, this daily distance check is
not required.
If an OGI camera operator chooses to use this optional daily field
check for distance, it must be documented. The daily field check must
use the same gases at the same flow rate as those specified in section
6.1.2 for the initial verification check and development of the
operating envelopes. The daily field check must be conducted by the OGI
camera operator(s) who will be conducting the monitoring survey using
the OGI camera(s) that will be used to conduct the monitoring survey.
If the OGI camera operator encounters delta-T values that are lower
than or wind speed values that are higher than the values during the
daily field check, the distance check must be repeated.
4. Other Changes
Additionally, the EPA has made a number of clarifications and minor
adjustments to the text of appendix K in response to comments received:
Added definitions for OGI camera operator, simple scene,
and survey hour.
Adjusted the specifications for instrumentation described
in section 6.2 that is used for the initial verification of the camera
specifications.
Added specifications for coordinates when global
positioning systems are used to document the path taken by the OGI
camera operator.
Removed the language that allows for full video records in
lieu of video clips or photographs. We are clarifying that a full video
record does suffice for video clips of leaks, but the addition of the
language in the supplemental proposal caused unintended confusion to
commenters.
Reduced the audit frequency for OGI camera operators from
quarterly to semiannually.
In Annex 1, changed the pixel count for each area from a
minimum of 1 to 0.5 percent of the total pixels of the detector.
In Annex 1, changed the minimum number of measured
infrared radiance pixel area within a data set to 1000 data points.
XV. Prevention of Significant Deterioration and Title V Permitting
This final rule regulates GHGs (in the form of methane limitations)
under CAA section 111. Because regulation of GHGs under CAA section 111
could have implications for other EPA rules and for permits written
under the CAA PSD preconstruction permit program and the CAA title V
operating permit program, the EPA is including provisions in this final
rule that explicitly address some of these potential implications,
consistent with our experience in prior rules regulating GHGs. The EPA
included and explained the basis for similar provisions when
promulgating 2016 NSPS OOOOa, as well as the 2015 subpart TTTT NSPS for
electric utility generating units. See 81 FR 35823, 35871 (June 3,
2016) and 80 FR 64509, 64628 (October 23, 2015). The discussion in
these prior rule preambles equally applies to the oil and gas sources
subject to NSPS OOOOb and EG OOOOc.
In summary, in light of the U.S. Supreme Court's decision in
Utility Air Regulatory Group v. Environmental Protection Agency, 573
U.S. 302 (2014) (UARG), the EPA may not treat GHGs as an air pollutant
for purposes of determining whether a source is a major source (or
modification thereof) for the purpose of PSD applicability. Certain
portions of the EPA's PSD regulations (specifically, the definition of
``subject to regulation'') effectively ensure that most sources will
not trigger PSD solely by virtue of their GHG emissions. E.g., 40 CFR
51.166(b)(48)(iv), 52.21(b)(49)(iv). However, the EPA's PSD regulations
(specifically, the definition of ``regulated NSR pollutant'') provide
additional bases for PSD applicability for pollutants that are
regulated under CAA section 111. To address this latter component of
PSD applicability, the EPA is adding provisions within the subpart
OOOOb NSPS and subpart OOOOc EG to help clarify that the promulgation
of GHG standards under section 111 will not result in additional
sources becoming subject to PSD based solely on GHG emissions, which
would be contrary to the holding in UARG. See 40 CFR
[[Page 17017]]
60.5360b(b)(1)-(2), 60.5361c(b)(1)-(2). These provisions are similar to
those in the 2016 NSPS OOOOa and other section 111 rules that regulate
GHGs. See, e.g., 40 CFR 60.5360a(b)(1)-(2), 60.5515(b)(1)-(2).
The EPA understands there are also concerns that if methane were to
be subject to regulation as a separate air pollutant from GHGs, sources
that emit methane above the PSD thresholds or modifications that
increase methane emissions could be subject to the PSD program. To
address this concern and for purposes of clarity, the EPA is adopting
regulatory text within subpart OOOOb NSPS and subpart OOOOc EG to
clarify that the air pollutant that is subject to regulation is GHGs,
even though the standard is expressed in the form of a limitation on
emissions of methane. See 40 CFR 60.5360b(a), 60.5361c(a). This
language is substantially similar to language found in, for example,
the 2016 NSPS OOOOa and other rules. See, e.g., 40 CFR 60.5360a(a),
60.5515(a).
For sources that are subject to the PSD program based on non-GHG
emissions, the CAA continues to require that PSD permits satisfy the
best available control technology (BACT) requirement for GHGs. Based on
the language in the PSD regulations, the EPA and states may continue to
limit the application of BACT to GHG emissions in those circumstances
where a new source emits GHGs in the amount of at least 75,000 tpy on a
CO2 Eq. basis or an existing major source increases
emissions of GHGs by more than 75,000 tpy on a CO2 Eq.
basis. See 40 CFR 51.166(b)(48)(iv), 52.21(b)(49)(iv). The revisions to
the regulatory text within subparts OOOOb NSPS and OOOOc EG ensure that
this BACT applicability level remains operable to sources of GHGs
regulated under CAA section 111, as have similar revisions in prior
rules. See 40 CFR 60.5360b(b)(1)-(2), 60.5361c(b)(1)-(2); see also,
e.g., 40 CFR 60.5360a(b)(1)-(2), 60.5515(b)(1)-(2). This rule does not
require any additional revisions to SIPs.
Regarding title V, the UARG decision similarly held that the EPA
may not treat GHGs as an air pollutant for purposes of determining
whether a source is a major source for the purpose of title V
applicability. Promulgation of CAA section 111 requirements for GHGs
will not result in the EPA imposing a requirement that stationary
sources obtain a title V permit solely because such sources emit or
have the potential to emit GHGs above the applicable major source
thresholds.\769\
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\769\ The additional regulatory text in the final rule further
ensures that title V regulations are not applied to GHGs solely
because they are regulated under CAA section 111. See 40 CFR
60.5360b(b)(3)-(4), 60.5361c(b)(3)-(4); see also, e.g., 40 CFR
60.5360a(b)(3)-(4), 60.5515(b)(3)-(4). The EPA understands that
concerns regarding the regulation of methane as a separate air
pollutant (described with respect to PSD) also apply to title V. The
EPA's regulatory text here in this final rule--clarifying that the
pollutant subject to regulation is GHGs--similarly addresses these
concerns with respect to title V. See 40 CFR 60.5360b(a),
60.5361c(a).
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To be clear, however, unless exempted by the Administrator through
regulation under CAA section 502(a), any source, including a ``non-
major source,'' subject to a standard or regulation under CAA section
111 is required to apply for, and operate pursuant to, a title V permit
that ensures compliance with all applicable CAA requirements for the
source, including any GHG-related applicable requirements. This aspect
of the title V program is not affected by UARG.\770\ The EPA is
including an exemption from the obligation to obtain a title V permit
for sources subject to NSPS OOOOb and EG OOOOc, unless such sources
would otherwise be required to obtain a permit under 40 CFR 70.3(a) or
40 CFR 71.3(a), as the EPA did in NSPS OOOO and OOOOa.\771\ See 40 CFR
60.5360b(c); see also 40 CFR 60.5370, 60.5370a. However, sources that
are subject to the CAA section 111 standards promulgated in this rule
and that are otherwise required to obtain a title V permit under 40 CFR
70.3(a) or 40 CFR 71.3(a) will be required to apply for, and operate
pursuant to, a title V permit that ensures compliance with all
applicable CAA requirements, including any GHG-related applicable
requirements.
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\770\ See Memorandum from Janet G. McCabe, Acting Assistant
Administrator, Office of Air and Radiation, and Cynthia Giles,
Assistant Administrator, Office of Enforcement and Compliance
Assurance, to Regional Administrators, Regions 1-10, Next Steps and
Preliminary Views on the Application of Clean Air Act Permitting
Programs to Greenhouse Gases Following the Supreme Court's Decision
in Utility Regulatory Group v. Environmental Protection Agency (July
24, 2014) at 5.
\771\ The EPA provided the rationale for exempting this source
category from the title V permitting requirements during the
rulemaking for the 2012 NSPS OOOO. See 76 FR 52737, 52751 (August
23, 2011). That rationale continues to apply to this source
category.
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XVI. Summary of Cost, Environmental, and Economic Impacts
A. What are the air quality impacts?
The EPA projected that, from 2024 to 2038, relative to the
baseline, the final NSPS OOOOb and EG OOOOc will reduce about 58
million short tons of methane emissions (1.5 billion tons
CO2 Eq. using a GWP of 28), 16 million short tons of VOC
emissions, and 590 thousand short tons of HAP emissions from affected
facilities. The EPA projected regulatory impacts beginning in 2024 as
that year represents the first full year of implementation of the final
NSPS OOOOb. The EPA assumes that emissions impacts of the final EG
OOOOc will begin in 2028. The EPA projected impacts though 2038 to
illustrate the accumulating effects of this rule over a longer period.
The EPA did not estimate impacts after 2038 for reasons including
limited information, as explained in the RIA.
B. What are the secondary impacts?
The energy impacts described in this section of this document are
those energy requirements associated with the operation of emissions
control devices. Potential impacts on the national energy economy from
the rule are discussed under economic impacts in section XVI.D of this
document. There will likely be minimal change in emissions control
energy requirements resulting from this rule. Additionally, this final
action continues to encourage the use of emissions controls that
recover hydrocarbon products that can be used onsite as fuel or
reprocessed within the production process for sale.
C. What are the cost impacts?
The EAV of the regulatory compliance cost associated with the final
NSPS OOOOb and EG OOOOc over the 2024 to 2038 period was estimated to
be $1.5 billion per year using a 2-percent discount rate (in 2019
dollars), $1.5 billion per year using a 3-percent discount rate, and
$1.6 billion using a 7-percent discount rate. The corresponding
estimates of the PV of compliance costs were $19 billion using a 2-
percent discount rate, $18 billion using a 3-percent discount rate, and
$14 billion using a 7-percent discount rate.
These estimates include the producer revenues associated with the
projected increase in the recovery of saleable natural gas, using the
2022 Annual Energy Outlook (AEO) projection of natural gas prices to
estimate the value of the change in the recovered gas at the wellhead
projected to result from the final action. Estimates of the value of
the recovered product have been included in previous regulatory
analyses as offsetting compliance costs and are appropriate to include
when assessing the societal cost of a regulation. If the recovery of
saleable natural gas is not accounted for, the EAV of the regulatory
compliance costs of the final rule over the 2024 to 2038
[[Page 17018]]
period were estimated to be $2.4 billion using a 2-percent discount
rate, $2.4 billion using a 3-percent discount rate, and $2.4 billion
per year using a 7-percent discount rate. The PV of these costs were
estimated to be $31 billion using a 2-percent discount rate, $29
billion using a 3-percent discount rate, and $22 billion using a 7-
percent discount rate.
D. What are the economic impacts?
The EPA conducted a suite of economic impact and distributional
analyses for this rule, as detailed in section 4 of the final RIA. To
provide a partial measure of the economic consequences of the final
NSPS OOOOb and EG OOOOc, the EPA developed a pair of single-market,
static partial-equilibrium analyses of national crude oil and natural
gas markets. We implemented the pair of single-market analyses instead
of a coupled market or general equilibrium approach to provide broad
insights into potential national-level market impacts while providing
maximum analytical transparency. We estimated the price and quantity
impacts of the final NSPS OOOOb and EG OOOOc on crude oil and natural
gas markets for a subset of years within the time horizon analyzed in
the RIA. The models are parameterized using production and price data
from the EIA and supply and demand elasticity estimates from the
economics literature.
For oil well sites, the RIA projects that regulatory costs are at
their highest in 2038, the final year analyzed in the RIA. We estimated
that the final rule could result in a maximum decrease in annual crude
oil production of about 41.1 million barrels in 2038 (or about 1.05
percent of baseline projections of onshore crude oil production) with a
maximum price increase of $0.25 per barrel (or about 0.33 percent of
the projected baseline price).
For natural gas-related sites, the RIA projects that regulatory
costs are at their highest in 2028. We estimated that the final rule
could result in a maximum decrease in natural gas production of about
272.5 million Mcf in 2028 (or about 0.75 percent of baseline
projections of onshore natural gas production) with a maximum price
increase of $0.06 per Mcf (or about 1.76 percent of the projected
baseline natural gas price).
Before 2028, the modeled market impacts are smaller than later
impacts as only the incremental requirements under the final NSPS OOOOb
are assumed to be in effect. Please see section 4.1 of the RIA for more
detail on the formulation and implementation of the model as well as a
discussion of several important caveats and limitations associated with
the approach.
As discussed in the RIA for this final rule, employment impacts of
environmental regulations are generally composed of a mix of potential
declines and gains in different areas of the economy over time.
Regulatory employment impacts can vary across occupations, regions, and
industries; by labor and product demand and supply elasticities; and in
response to other labor market conditions. Isolating such impacts is a
challenge, as they are difficult to disentangle from employment impacts
caused by a wide variety of ongoing, concurrent economic changes.
The oil and natural gas industry directly employs approximately
140,000 people in oil and natural gas extraction, a figure which varies
with market prices and technological change. A large number of workers
are also employed in related sectors that provide materials and
services for the industry.\772\ As indicated above, the final NSPS
OOOOb and EG OOOOc are projected to cause small changes in oil and
natural gas production and prices. As a result, demand for labor
employed in oil and natural gas-related activities and associated
industries might experience adjustments as there may be increases in
compliance-related labor requirements as well as changes in employment
due to quantity effects in directly regulated sectors and sectors that
consume oil and natural gas products.
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\772\ Employment figure drawn from the Bureau of Labor
Statistics Current Employment Statistics for NAICS code 211.
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E. What are the benefits?
To satisfy the requirement of E.O. 12866 and to inform the public,
the EPA estimated the climate and health benefits due to the emissions
reductions projected under the final NSPS OOOOb and EG OOOOc. The EPA
expects climate and health benefits due to the emissions reductions
projected under the final NSPS OOOOb and EG OOOOc. The EPA estimated
the climate benefits of methane emission reductions expected from this
final rule using SC-CH4 estimates that reflect recent
advances in the scientific literature on climate change and its
economic impacts and incorporate recommendations made by the National
Academies of Science, Engineering, and Medicine (National Academies
2017). The EPA presented these estimates in a sensitivity analysis in
the December 2022 RIA, solicited public comment on the methodology and
use of these estimates, and has conducted an external peer review of
these estimates, as described further below.
The SC-CH4 is the monetary value of the net harm to
society from emitting a metric ton of CH4 into the atmosphere in a
given year, or the benefit of avoiding that increase. In principle, SC-
CH4 is a comprehensive metric that includes the value of all
climate change impacts (both negative and positive), including (but not
limited to) changes in net agricultural productivity, human health
effects, property damage from increased flood risk, changes in the
frequency and severity of natural disasters, disruption of energy
systems, risk of conflict, environmental migration, and the value of
ecosystem services. The SC-CH4 therefore, reflects the
societal value of reducing emissions of the gas in question by one
metric ton and is the theoretically appropriate value to use in
conducting benefit-cost analyses of policies that affect methane
emissions. In practice, data and modeling limitations restrain the
ability of SC-CH4 estimates to include all physical,
ecological, and economic impacts of climate change, implicitly
assigning a value of zero to the omitted climate damages. The estimates
are, therefore, a partial accounting of climate change impacts and
likely underestimate the marginal benefits of abatement.
Since 2008, the EPA has used estimates of the social cost of
various greenhouse gases (i.e., social cost of carbon dioxide (SC-
CO2), SC-CH4, and social cost of nitrous oxide
(SC-N2O)), collectively referred to as the ``social cost of
greenhouse gases'' (SC-GHG), in analyses of actions that affect GHG
emissions. The values used by the EPA from 2009 through 2016, and since
2021--including in the November 2021 RIA and December 2022 RIA for this
rulemaking--have been consistent with those developed and recommended
by the Interagency Working Group on the SC-GHG (IWG); and the values
used from 2017 through 2020 were consistent with those required by
Executive Order (E.O.) 13783. During that time, the National Academies
conducted a comprehensive review of the SC-CO2 and issued a
final report in 2017 recommending specific criteria for future updates
to the SC-CO2 estimates, a modeling framework to satisfy the
specified criteria, and both near-term updates and longer-term research
needs pertaining to various components of the estimation process. The
IWG was reconstituted in 2021 and E.O. 13990 directed it to develop a
comprehensive update of its SC-GHG estimates, recommendations regarding
areas of
[[Page 17019]]
decision-making to which SC-GHG should be applied, and a standardized
review and updating process to ensure that the recommended estimates
continue to be based on the best available economics and science going
forward.
The EPA is a member of the IWG and is participating in the IWG's
work under E.O. 13990. While that process continues, as noted in
previous EPA RIAs, the EPA is continuously reviewing developments in
the scientific literature on the SC-GHG, including more robust
methodologies for estimating damages from emissions, and looking for
opportunities to further improve SC-GHG estimation going forward. In
the RIA for the December 2022 Supplemental Proposal, the EPA included a
sensitivity analysis of the climate benefits of the supplemental
proposal using a new set of SC-GHG estimates that incorporates recent
research addressing recommendations of the National Academies of
Science, Engineering, and Medicine (2017), in addition to using the IWG
recommended interim SC-GHG estimates presented in the Technical Support
Document: Social Cost of Carbon, Methane, and Nitrous Oxide Interim
Estimates under Executive Order 13990, published in February 2021 (IWG,
2021).
The EPA solicited public comment on the sensitivity analysis and
the accompanying draft technical report, which explains the methodology
underlying the new set of estimates, in the December 2022 Supplemental
Proposal.\773\ To ensure that the methodological updates adopted in the
technical report are consistent with economic theory and reflect the
latest science, the EPA also initiated an external peer review panel to
conduct a high-quality review of the technical report, completed in May
2023. The peer reviewers commended the agency on its development of
this update, calling it a much-needed improvement in estimating the SC-
GHG and a significant step towards addressing the National Academies'
recommendations with defensible modeling choices based on current
science. The peer reviewers provided numerous recommendations for
refining the presentation and for future modeling improvements,
especially with respect to climate change impacts and associated
damages that are not currently included in the analysis. Additional
discussion of omitted impacts and other updates have been incorporated
into the technical report to address peer reviewer recommendations.
Complete information about the external peer review, including the peer
reviewer selection process, the final report with individual
recommendations from peer reviewers, and the EPA's response to each
recommendation is available on the EPA's website. The EPA is a member
of the Interagency Working Group (IWG) on the SC-GHG and continues to
participate in its work. The EPA's new SC-GHG estimates along with the
peer review of the updated methodology will be among the many technical
inputs available to the IWG as it continues its work.
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\773\ See volume 2 of the RTC, chapter 20, in EPA-HQ-OAR-2021-
0317.
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An overview of the methodological updates incorporated into the new
SC-GHG estimates is provided in the RIA. A more detailed explanation of
each input and the modeling process is provided in the technical
report, EPA Report on the Social Cost of Greenhouse Gases: Estimates
Incorporating Recent Scientific Advances (EPA 2023), which is also
included as supporting material for the RIA in the docket.\774\
However, we emphasize that the monetized benefits analysis is entirely
distinct from the statutory BSER determinations proposed herein and is
presented solely for the purposes of complying with E.O. 12866. As
discussed in more detail in the November 2021 Proposal, the December
2022 Supplemental Proposal, and earlier in this action, the EPA weighed
the relevant statutory factors to determine the appropriate standards
and did not rely on the monetized benefits analysis for purposes of
determining the standards. E.O. 12866 separately requires the EPA to
perform a benefit-cost analysis, including monetizing costs and
benefits where practicable, and the EPA has conducted such an analysis.
The monetized climate benefits calculated using the SC-CH4
are included in the benefit-cost analysis, and thus, as is generally
the case with any analytical methods, data, or results associated with
RIAs, the EPA welcomes the opportunity to continually improve its
understanding through public input on these estimates.
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\774\ For more information about the development of these
estimates, see www.epa.gov/environmental-economics/scghg.
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The EPA estimated the PV of the climate benefits over the 2024 to
2038 period to be $110 billion at a 2 percent near-term Ramsey discount
rate. The EAV of these benefits is estimated to be $8.5 billion per
year at the 2 percent near-term Ramsey discount rate. These values
represent only a partial accounting of climate impacts from methane
emissions and do not account for health effects of ozone exposure from
the increase in methane emissions.
Under the final NSPS OOOOb and EG OOOOc, the EPA expects that the
projected VOC emissions reductions will improve air quality and improve
health and welfare associated with exposure to ozone, PM2.5,
and HAP. In the national-level analysis of public health impacts, the
EPA used the environmental Benefits Mapping and Analysis Program--
Community Edition (BenMAP-CE) software program to quantify counts of
premature deaths and illnesses attributable to photochemical modeled
changes in summer season average ozone concentrations resulting from
VOC emissions changes. The methods for quantifying the number and value
of air pollution-attributable premature deaths and illnesses are
described in the TSD titled Estimating PM2.5- and Ozone-
Attributable Health Benefits \775\. The reductions in health-harming
pollution would result in significant public health benefits including
avoided premature deaths, reductions in new asthma cases and incidences
of asthma symptoms, reductions in hospital admissions and emergency
department visits, and reductions in lost school days. These health
benefits are also monetized and the EPA estimated the PV of the ozone
health benefits over the 2024 to 2038 period to be $7.0 billion at a 2
percent discount rate, $6.1 billion at a 3 percent discount rate, and
$3.5 billion at a 7 percent discount rate. The EAV of these benefits is
estimated to be $540 million at a 2 percent discount rate, $510 million
at a 3 percent discount rate, and $380 million at a 7 percent discount
rate.
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\775\ https://www.epa.gov/system/files/documents/2023-01/Estimating%20PM2.5-%20and%20Ozone-Attributable%20Health%20Benefits%20TSD_0.pdf.
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These values represent only a partial accounting of the potential
benefits of this final rule. Several categories of climate, human
health, and welfare benefits from methane, VOC, and HAP emissions
reductions remain unmonetized and are thus not directly reflected in
the quantified benefit estimates. The RIA presents a series of
qualitative discussions of these unquantified and unmonetized benefits.
F. What analyses of environmental justice did we conduct?
As discussed earlier in this preamble and in the November 2021
proposal, the EPA engaged extensively with representatives of
communities with environmental justice concerns to inform this
rulemaking, and heard directly from environmental justice
[[Page 17020]]
organizations and community representatives during the public hearings
and as part of the public comment process for both the November 2021
Proposal and December 2022 Supplemental Proposal. Our engagement with
these stakeholders surfaced several concerns regarding the health
effects of air pollution associated with oil and gas facilities, the
implications of climate change and associated extreme weather events
for health and well-being in overburdened and vulnerable communities,
and accessibility to data and information regarding sources near
environmental justice communities. These stakeholders also highlighted
the importance of reducing emissions of methane and other health-
harming air pollutants from specific sources subject to this rule, such
as from malfunctioning control devices and flaring of associated gas,
super-emitter events, fugitive emissions from well sites, compressor
stations, and storage vessels.
The EPA gave these comments careful consideration as part of the
overall record for this rulemaking. Consistent with applicable
executive orders and EPA policy, the Agency has also carefully analyzed
the environmental justice implications of the climate-related benefits
that will result from this rule, as well as the benefits associated
with reductions in emissions of ozone precursors (namely VOCs) and
hazardous air pollutants. The EPA believes that the suite of regulatory
protections established in this rule, and the resulting reductions in
harmful air pollution from new and existing oil and gas sources, will
have a range of significant benefits for communities with environmental
justice concerns.
Among other things, this rule will lead to significant reductions
in methane pollution amounting to approximately 1.5 billion tons
CO2-e through 2038, yielding climate-related benefits valued
at $110 billion. Because climate change is already having
disproportionate and adverse impacts on communities with environmental
justice concerns, these methane reductions and their associated
climate-related benefits are of particular importance for these
communities.
Along with these climate-related benefits, this final rule is also
anticipated to achieve significant VOC reductions of 16 million tons
and HAP reductions of 590 thousand tons. Many of these reductions come
from applying available control measures to sources that environmental
justice organizations and communities have identified as being
frequently located near overburdened and vulnerable populations, and as
posing important air quality and health concerns for communities. By
ensuring that these sources are subject to nationally applicable
requirements that reflect highly effective technologies and approaches
for limiting and reducing emissions, the EPA believes that the NSPS and
EG being finalized here will provide a high and consistent degree of
protection against the full suite of harmful air pollutants associated
with oil and gas sources, including in communities with environmental
justice concerns that are located near these sources and exposed to
these emissions.
1. Environmental Justice and the Impacts of Climate Change
In 2009, under the Endangerment and Cause or Contribute Findings
for Greenhouse Gases Under Section 202(a) of the Clean Air Act
(``Endangerment Finding,'' 74 FR 66496), the Administrator considered
how climate change threatens the health and welfare of the U.S.
population.\776\ As part of that consideration, she also considered
risks to minority and low-income individuals and communities, finding
that certain parts of the U.S. population may be especially vulnerable
based on their characteristics or circumstances. These groups include
economically and socially disadvantaged communities, including those
that have been historically marginalized or overburdened; individuals
at vulnerable lifestages, such as the elderly, the very young, and
pregnant or nursing women; those already in poor health or with
comorbidities; the disabled; those experiencing homelessness, mental
illness, or substance abuse; and/or Indigenous or minority populations
dependent on one or limited resources for subsistence due to factors
including but not limited to geography, access, and mobility.
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\776\ Earlier studies and reports can be found at https://www.epa.gov/cira/social-vulnerability-report.
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Scientific assessment reports produced over the past decade by the
USGCRP,777 778 the IPCC,779 780 781 782 the
National Academies of Science, Engineering, and
Medicine,783 784 and
[[Page 17021]]
the EPA \785\ add more evidence that the impacts of climate change
raise potential EJ concerns. These reports conclude that less-affluent,
traditionally marginalized and predominantly non-White communities can
be especially vulnerable to climate change impacts because they tend to
have limited resources for adaptation, are more dependent on climate-
sensitive resources such as local water and food supplies or have less
access to social and information resources. Some communities of color,
specifically populations defined jointly by ethnic/racial
characteristics and geographic location (e.g., African-American, Black,
and Hispanic/Latino communities; Native Americans, particularly those
living on Tribal lands and Alaska Natives), may be uniquely vulnerable
to climate change health impacts in the U.S., as discussed below. In
particular, the 2016 scientific assessment on the Impacts of Climate
Change on Human Health \786\ found with high confidence that
vulnerabilities are place- and time-specific, lifestages and ages are
linked to immediate and future health impacts, and social determinants
of health are linked to greater extent and severity of climate change-
related health impacts.
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\777\ USGCRP, 2018: Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller,
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, 1515 pp. doi:10.7930/NCA4.2018.
\778\ USGCRP, 2016: The Impacts of Climate Change on Human
Health in the United States: A Scientific Assessment. Crimmins,
A.,J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J.
Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M.
Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S.
Global Change Research Program, Washington, DC, 312 pp. https://dx.doi.org/10.7930/J0R49NQX.
\779\ Oppenheimer, M., M. Campos, R. Warren, J. Birkmann, G.
Luber, B. O'Neill, and K. Takahashi, 2014: Emergent risks and key
vulnerabilities. In: Climate Change 2014: Impacts, Adaptation, and
Vulnerability. Part A: Global and Sectoral Aspects. Contribution of
Working Group II to the Fifth Assessment Report of the
Intergovernmental Panel on Climate Change [Field, C.B., V.R. Barros,
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee,
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N.
Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)].
Cambridge University Press, Cambridge, United Kingdom and New York,
NY, USA, pp. 1039-1099.
\780\ Porter, J.R., L. Xie, A.J. Challinor, K. Cochrane, S.M.
Howden, M.M. Iqbal, D.B. Lobell, and M.I. Travasso, 2014: Food
security and food production systems. In: Climate Change 2014:
Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral
Aspects. Contribution of Working Group II to the Fifth Assessment
Report of the Intergovernmental Panel on Climate Change [Field,
C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E.
Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma,
E.S. Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L.
White (eds.)]. Cambridge University Press, Cambridge, United Kingdom
and New York, NY, USA, pp. 485-533.
\781\ Smith, K.R., A. Woodward, D. Campbell-Lendrum, D.D.
Chadee, Y. Honda, Q. Liu, J.M. Olwoch, B. Revich, and R. Sauerborn,
2014: Human health: impacts, adaptation, and co-benefits. In:
Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A:
Global and Sectoral Aspects. Contribution of Working Group II to the
Fifth Assessment Report of the Intergovernmental Panel on Climate
Change [Field, C.B., V.R. Barros, D.J. Dokken, K.J. Mach, M.D.
Mastrandrea, T.E. Bilir, M. Chatterjee, K.L. Ebi, Y.O. Estrada, R.C.
Genova, B. Girma, E.S. Kissel, A.N. Levy, S. MacCracken, P.R.
Mastrandrea, and L.L. White (eds.)]. Cambridge University Press,
Cambridge, United Kingdom and New York, NY, USA, pp. 709-754.
\782\ IPCC, 2018: Global Warming of 1.5 [deg]C. An IPCC Special
Report on the impacts of global warming of 1.5 [deg]C above pre-
industrial levels and related global greenhouse gas emission
pathways, in the context of strengthening the global response to the
threat of climate change, sustainable development, and efforts to
eradicate poverty [Masson-Delmotte, V., P. Zhai, H.-O. P[ouml]rtner,
D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C.
P[eacute]an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X.
Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, M. Tignor, and T.
Waterfield (eds.)]. In Press.
\783\ National Research Council. 2011. America's Climate
Choices. Washington, DC: The National Academies Press. https://doi.org/10.17226/12781.
\784\ National Academies of Sciences, Engineering, and Medicine.
2017. Communities in Action: Pathways to Health Equity. Washington,
DC: The National Academies Press. https://doi.org/10.17226/24624.
\785\ EPA. 2021. Climate Change and Social Vulnerability in the
United States: A Focus on Six Impacts. U.S. Environmental Protection
Agency, EPA 430-R-21-003.
\786\ USGCRP, 2016: The Impacts of Climate Change on Human
Health in the United States: A Scientific Assessment.
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Per the NCA4, ``Climate change affects human health by altering
exposures to heat waves, floods, droughts, and other extreme events;
vector-, food- and waterborne infectious diseases; changes in the
quality and safety of air, food, and water; and stresses to mental
health and well-being.'' \787\ Many health conditions such as
cardiopulmonary or respiratory illness and other health impacts are
associated with and exacerbated by an increase in GHGs and climate
change outcomes, which is problematic as these diseases occur at higher
rates within vulnerable communities. Importantly, negative public
health outcomes include those that are physical in nature, as well as
mental, emotional, social, and economic.
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\787\ Ebi, K.L., J.M. Balbus, G. Luber, A. Bole, A. Crimmins, G.
Glass, S. Saha, M.M. Shimamoto, J. Trtanj, and J.L. White-Newsome,
2018: Human Health. In Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller,
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, pp. 539-571. doi:10.7930/
NCA4.2018.CH14.
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The scientific assessment literature, including the previously
referenced reports, demonstrates that there are myriad ways in which
these populations may be affected at the individual and community
levels. Outdoor workers, such as construction or utility workers and
agricultural laborers, who are frequently part of already at-risk
groups, are exposed to poor air quality and extreme temperatures
without relief. Furthermore, individuals within EJ populations of
concern face greater housing and clean water insecurity and bear
disproportionate economic impacts and health burdens associated with
climate change effects. They also have less or limited access to
healthcare and affordable, adequate health or homeowner insurance. The
urban heat island effect can add additional stress to vulnerable
populations in densely populated cities who do not have access to air
conditioning.\788\ Finally, resiliency and adaptation are more
difficult for economically disadvantaged communities: They tend to have
less liquidity, individually and collectively, to move or to make the
types of infrastructure or policy changes necessary to limit or reduce
the hazards they face. They frequently face systemic, institutional
challenges that limit their power to advocate for and receive resources
that would otherwise aid in resiliency and hazard reduction and
mitigation.
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\788\ USGCRP, 2016.
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The assessment literature cited in the EPA's 2009 Endangerment
Finding, as well as Impacts of Climate Change on Human Health, also
concluded that certain populations and people in particular stages of
life, including children, are most vulnerable to climate-related health
effects. The assessment literature produced from 2016 to the present
strengthens these conclusions by providing more detailed findings
regarding related vulnerabilities and the projected impacts youth may
experience. These assessments--including the NCA4 (2018) and The
Impacts of Climate Change on Human Health in the United States (2016)--
describe how children's unique physiological and developmental factors
contribute to making them particularly vulnerable to climate change.
Impacts to children are expected from air pollution, infectious and
waterborne illnesses, and mental health effects resulting from extreme
weather events. In addition, children are among those especially
susceptible to allergens, as well as health effects associated with
heat waves, storms, and floods. Additional health concerns may arise in
low-income households, especially those with children, if climate
change reduces food availability and increases prices, leading to food
insecurity within households. More generally, these reports note that
extreme weather and flooding can cause or exacerbate poor health
outcomes by affecting mental health because of stress; contributing to
or worsening existing conditions, again due to stress or also as a
consequence of exposures to water and air pollutants; or by impacting
hospital and emergency services operations.\789\ Further, in urban
areas in particular, flooding can have significant economic
consequences due to effects on infrastructure, pollutant exposures, and
drowning dangers. The ability to withstand and recover from flooding is
dependent in part on the social vulnerability of the affected
population and individuals experiencing an event.\790\ In addition,
children are among those especially susceptible to allergens, as well
as health effects associated with heat waves, storms, and floods.
Additional health concerns may arise in low-income households,
especially those with children, if climate change reduces food
availability and increases prices, leading to food insecurity within
households.
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\789\ Ebi, K.L., J.M. Balbus, G. Luber, A. Bole, A. Crimmins, G.
Glass, S. Saha, M.M. Shimamoto, J. Trtanj, and J.L. White-Newsome,
2018: Human Health. In Impacts, Risks, and Adaptation in the United
States: Fourth National Climate Assessment, Volume II [Reidmiller,
D.R., C.W. Avery, D.R. Easterling, K.E. Kunkel, K.L.M. Lewis, T.K.
Maycock, and B.C. Stewart (eds.)]. U.S. Global Change Research
Program, Washington, DC, USA, pp. 539-571. doi:10.7930/
NCA4.2018.CH14.
\790\ National Academies of Sciences, Engineering, and Medicine
2019. Framing the Challenge of Urban Flooding in the United States.
Washington, DC: The National Academies Press. https://doi.org/10.17226/25381.
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The Impacts of Climate Change on Human Health (USGCRP, 2016) also
found that some communities of color, low-income groups, people with
limited English proficiency, and certain immigrant groups (especially
those who are undocumented) live with many of the factors that
contribute to their vulnerability to the health impacts of climate
change. While difficult to isolate from related socioeconomic factors,
race appears to be an important factor in vulnerability to climate-
related stress, with elevated risks for mortality from high
temperatures reported for Black or African-American individuals
compared to White individuals after controlling for factors such as air
conditioning use. Moreover, people of color are disproportionately
exposed to air pollution based on where they live, and
disproportionately vulnerable due to higher baseline prevalence of
underlying diseases such as asthma, so
[[Page 17022]]
climate exacerbations of air pollution are expected to have
disproportionate effects on these communities. Locations with greater
health threats include urban areas (due to, among other factors, the
``heat island'' effect where built infrastructure and lack of green
spaces increases local temperatures), areas where airborne allergens
and other air pollutants already occur at higher levels, and
communities experienced depleted water supplies or vulnerable energy
and transportation infrastructure.
The recent EPA report on climate change and social vulnerability
\791\ examined four socially vulnerable groups (individuals who are low
income, minority, without high school diplomas, and/or 65 years and
older) and their exposure to several different climate impacts (air
quality, coastal flooding, extreme temperatures, and inland flooding).
This report found that Black and African-American individuals were 40
percent more likely to currently live in areas with the highest
projected increases in mortality rates due to climate-driven changes in
extreme temperatures, and 34 percent more likely to live in areas with
the highest projected increases in childhood asthma diagnoses due to
climate-driven changes in particulate air pollution. The report found
that Hispanic and Latino individuals are 43 percent more likely to live
in areas with the highest projected labor hour losses in weather-
exposed industries due to climate-driven warming, and 50 percent more
likely to live in coastal areas with the highest projected increases in
traffic delays due to increases in high-tide flooding. The report found
that American Indian and Alaska Native individuals are 48 percent more
likely to live in areas where the highest percentage of land is
projected to be inundated due to sea level rise, and 37 percent more
likely to live in areas with high projected labor hour losses. Asian
individuals were found to be 23 percent more likely to live in coastal
areas with projected increases in traffic delays from high-tide
flooding. Those with low income or no high school diploma are about 25
percent more likely to live in areas with high projected losses of
labor hours, and 15 percent more likely to live in areas with the
highest projected increases in asthma due to climate-driven increases
in particulate air pollution, and in areas with high projected
inundation due to sea level rise.
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\791\ EPA. 2021. Climate Change and Social Vulnerability in the
United States: A Focus on Six Impacts. U.S. Environmental Protection
Agency, EPA 430-R-21-003.
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In a more recent 2023 report, Climate Change Impacts on Children's
Health and Well-Being in the U.S., the EPA considered the degree to
which children's health and well-being may be impacted by five climate-
related environmental hazards--extreme heat, poor air quality, changes
in seasonality, flooding, and different types of infectious diseases
(U.S. EPA, 2023). The report found that children's academic achievement
is projected to be reduced by 4-7 percent per child, as a result of
moderate and higher levels of warming, impacting future income levels.
The report also projects increases in the numbers of annual emergency
department visits associated with asthma, and that the number of new
asthma diagnoses increases by 4-11 percent due to climate-driven
increases in air pollution relative to current levels. In addition,
more than 1 million children in coastal regions are projected to be
temporarily displaced from their homes annually due to climate-driven
flooding, and infectious disease rates are similarly anticipated to
rise, with the number of new Lyme disease cases in children living in
22 states in the eastern and midwestern U.S. increasing by
approximately 3,000-23,000 per year compared to current levels.
Overall, the report confirmed findings of broader climate science
assessments that children are uniquely vulnerable to climate-related
impacts and that in many situations, children in the U.S. who identify
as Black, Indigenous, and People of Color, are limited English-
speaking, do not have health insurance, or live in low-income
communities may be disproportionately exposed to the most severe
impacts of climate change.
2. Impacts of Climate Change on Indigenous Communities
Indigenous communities face disproportionate risks from the impacts
of climate change, particularly those communities impacted by
degradation of natural and cultural resources within established
reservation boundaries and threats to traditional subsistence
lifestyles. Indigenous communities whose health, economic well-being,
and cultural traditions depend upon the natural environment will likely
be affected by the degradation of ecosystem goods and services
associated with climate change. The IPCC indicates that losses of
customs and historical knowledge may cause communities to be less
resilient or adaptable.\792\ The NCA4 (2018) noted that while
indigenous peoples are diverse and will be impacted by the climate
changes universal to all Americans, there are several ways in which
climate change uniquely threatens indigenous peoples' livelihoods and
economies.\793\ In addition, there can be institutional barriers
(including policy-based limitations and restrictions) to their
management of water, land, and other natural resources that could
impede adaptive measures.
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\792\ Porter, et al., 2014: Food security and food production
systems.
\793\ Jantarasami, L.C., R. Novak, R. Delgado, E. Marino, S.
McNeeley, C. Narducci, J. Raymond-Yakoubian, L. Singletary, and K.
Powys Whyte, 2018: Tribes and Indigenous Peoples. In Impacts, Risks,
and Adaptation in the United States: Fourth National Climate
Assessment, Volume II [Reidmiller, D.R., C.W. Avery, D.R.
Easterling, K.E. Kunkel, K.L.M. Lewis, T.K. Maycock, and B.C.
Stewart (eds.)]. U.S. Global Change Research Program, Washington,
DC, USA, pp. 572-603. doi:10.7930/NCA4. 2018. CH15.
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For example, indigenous agriculture in the Southwest is already
being adversely affected by changing patterns of flooding, drought,
dust storms, and rising temperatures leading to increased soil erosion,
irrigation water demand, and decreased crop quality and herd sizes. The
Confederated Tribes of the Umatilla Indian Reservation in the Northwest
have identified climate risks to salmon, elk, deer, roots, and
huckleberry habitat. Housing and sanitary water supply infrastructure
are vulnerable to disruption from extreme precipitation events.
Confounding general Native American response to natural hazards are
limitations imposed by policies such as the Dawes Act of 1887 and the
Indian Reorganization Act of 1934, which ultimately restrict Indigenous
peoples' autonomy regarding land-management decisions through Federal
trusteeship of certain Tribal lands and mandated Federal oversight of
management decisions. Additionally, NCA4 noted that Indigenous peoples
are subjected to institutional racism effects, such as poor
infrastructure, diminished access to quality healthcare, and greater
risk of exposure to pollutants. Consequently, Native Americans often
have disproportionately higher rates of asthma, cardiovascular disease,
Alzheimer's disease, diabetes, and obesity. These health conditions and
related effects (disorientation, heightened exposure to
PM2.5, etc.) can all contribute to increased vulnerability
to climate-driven extreme heat and air pollution events, which also may
be exacerbated by stressful situations, such as extreme weather events,
wildfires, and other circumstances.
[[Page 17023]]
NCA4 and IPCC's Fifth Assessment Report \794\ also highlighted
several impacts specific to Alaskan Indigenous Peoples. Coastal erosion
and permafrost thaw will lead to more coastal erosion, rendering winter
travel riskier and exacerbating damage to buildings, roads, and other
infrastructure--impacts on archaeological sites, structures, and
objects that will lead to a loss of cultural heritage for Alaska's
indigenous people. In terms of food security, the NCA4 discussed
reductions in suitable ice conditions for hunting, warmer temperatures
impairing the use of traditional ice cellars for food storage, and
declining shellfish populations due to warming and acidification. While
the NCA4 also noted that climate change provided more opportunity to
hunt from boats later in the fall season or earlier in the spring, the
assessment found that the net impact was an overall decrease in food
security.
---------------------------------------------------------------------------
\794\ Porter, et al., 2014: Food security and food production
systems.
---------------------------------------------------------------------------
3. Environmental Justice Impacts of Ozone Exposure Due to Oil and
Natural Gas VOC Impacts
Although EJ concerns for each rulemaking are unique and should be
considered on a case-by-case basis, the EPA's EJ Technical Guidance
(U.S. EPA, 2015) states that ``[t]he analysis of potential EJ concerns
for regulatory actions should address three questions:
1. Are there potential EJ concerns associated with environmental
stressors affected by the regulatory action for population groups of
concern in the baseline?
2. Are there potential EJ concerns associated with environmental
stressors affected by the regulatory action for population groups of
concern for the regulatory option(s) under consideration?
3. For the regulatory option(s) under consideration, are potential
EJ concerns created [, exacerbated,] or mitigated compared to the
baseline?''
To address these questions, the EPA developed an analytical
approach that considers the purpose and specifics of this proposed
rulemaking, as well as the nature of known and potential exposures and
health impacts. The purpose of this RIA is to provide estimates of the
potential costs and benefits of the illustrative national control
strategies in 2038 for the selected policy option. The selected policy
option evaluated in the RIA is expected to reduce VOC emissions.
Consequently, this means that ozone formation and exposure is expected
to be reduced such that some areas are expected to experience greater
air quality improvements, and thus health improvements. As differences
in both exposure and susceptibility (i.e., intrinsic individual risk
factors) contribute to environmental impacts, the analytical approach
used here first determines whether exposure and health effect
disparities exist under the baseline scenario. The approach then
evaluates if and how disparities are impacted when illustrative
emissions control strategies are analyzed. Both the exposure and health
effects analyses were developed using available scientific evidence
from the selected policy option for the Oil & Gas rule, for the future
year 2038, and are associated with various uncertainties. Consistent
with the methods the EPA uses to fully characterize the benefits of a
regulatory action, these EJ analyses evaluate the full set of exposure
and health outcome distributions resulting from this proposed action at
the national scale.
The EJ exposure assessment portion of the analysis focuses on
associating ambient ozone concentrations with various demographic
variables. Because this type of analysis requires less a priori
information, we were able to include a broad array of demographic
characteristics. Estimating actual health outcomes modified by
demographic population requires additional scientific information,
which constrained the scope of the second portion of the assessment. We
focused the EJ health effects analysis on populations and health
outcomes with the strongest scientific support (U.S. EPA, 2019, U.S.
EPA, 2020, U.S. EPA, 2022a). However, the EJ health effects analysis
does not include information about differences in other factors that
could affect the likelihood of adverse impacts (e.g., access to health
care, BMI) across groups, due to limitations on the underlying
data.\795\ Both the EJ exposure and health effects analyses are subject
to uncertainties related to input parameters and assumptions. For
example, both analyses focus on seasonal average ozone concentrations
and do not evaluate whether concentrations experienced by different
groups persist across the distribution of daily ozone exposures.
Additionally, the EJ health effects analysis is subject to additional
uncertainties related to concentration-response relationships and
baseline incidence data.
---------------------------------------------------------------------------
\795\ We do not ascribe differential health effects to be caused
by race or ethnicity. Instead, race and ethnicity likely serve as
proxies for a variety of environmental and social stressors.
---------------------------------------------------------------------------
Complex analyses using estimated parameters and inputs from
numerous models are likely to include multiple sources of uncertainty.
As this analysis is based on the same ozone spatial fields as the
benefits assessment, it is subject to similar types of uncertainty.
XVII. Statutory and Executive Order Reviews
Additional information about these statutes and E.O. can be found
at https://www.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 14094: Modernizing Regulatory Review
This action is a ``significant regulatory action'' as defined under
section 3(f)(1) of Executive Order 12866, as amended by Executive Order
14094. Accordingly, the EPA submitted this action to OMB for Executive
Order 12866 review. Documentation of any changes made in response to
the Executive Order 12866 review is available in the docket for this
action. The EPA prepared an analysis of the potential costs and
benefits associated with this action. This analysis, ``Regulatory
Impact Analysis for the Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review,'' is
available in the docket and describes in detail the EPA's assumptions
and characterizes the various sources of uncertainties affecting the
estimates.
The PV and EAV of the projected benefits, costs, and net benefits
over the 2024 to 2038 period under the final rule using discount rates
of 2, 3, and 7 percent is presented in table 28. A discussion of the
costs of the final rule is in section 2 of the RIA and a discussion of
the benefits is in section 3.
[[Page 17024]]
Table 28--Benefits, Costs, Net Benefits, and Emissions Reductions Under the Final Rules, 2024-2038
[Dollar estimates in millions of 2019 dollars] \a\
----------------------------------------------------------------------------------------------------------------
2 Percent near-term ramsey discount rate
-----------------------------------------------------------------------------
PV EAV PV EAV PV EAV
----------------------------------------------------------------------------------------------------------------
Climate Benefits \b\.............. $110,000 $8,500 $110,000 $8,500 $110,000 $8,500
----------------------------------------------------------------------------------------------------------------
2 Percent discount rate
3 Percent discount rate
7 Percent discount rate
----------------------------------------------------------------------------------------------------------------
PV EAV PV EAV PV EAV
----------------------------------------------------------------------------------------------------------------
Ozone Health Benefits \c\......... $7,000 $540 $6,100 $510 $3,500 $380
Net Compliance Costs.............. 19,000 1,500 18,000 1,500 14,000 1,600
Compliance Costs.............. 31,000 2,400 29,000 2,400 22,000 2,400
Value of Product Recovery..... 13,000 980 11,000 950 7,400 820
Net Benefits \d\.................. 97,000 7,600 97,000 7,500 98,000 7,300
----------------------------------------------------------------------------------------------------------------
Non-Monetized Benefits............ Climate and ozone-related health benefits from reducing 58 million short
tons of methane from 2024 to 2038.
Benefits to provision of ecosystem services associated with reduced ozone
concentrations from reducing 16 million short tons of VOC from 2024 to 2038.
PM2.5-related health benefits from reducing 16 million short tons of VOC
from 2024 to 2038.
HAP benefits from reducing 590 thousand short tons of HAP from 2024 to 2038.
----------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures. Totals may not appear to add correctly due to rounding.
\b\ Climate benefits are based on reductions in methane emissions and are calculated using three different
estimates of the SC-CH4 (under 1.5 percent, 2.0 percent, and 2.5 percent near-term Ramsey discount rates). For
the presentational purposes of this table, we show the climate benefits associated with the SC-CH4 at the 2
percent near-term Ramsey discount rate. Please see tables 3.4 and 3.5 in the RIA for the full range of
monetized climate benefit estimates. All net benefits are calculated using climate benefits discounted at the
2 percent near-term rate.
\c\ Monetized benefits include those related to public health associated with reductions in ozone
concentrations. The health benefits are associated with several point estimates.
\d\ Several categories of climate, human health, and welfare benefits from methane, VOC, and HAP emissions
reductions remain unmonetized and are thus not directly reflected in the quantified benefit estimates in the
table.
B. Paperwork Reduction Act (PRA)
The information collection activities in this rule have been
submitted for approval to the OMB under the PRA. The ICR document that
the EPA prepared has been assigned OMB Control No. 2060-0721 and EPA
ICR number 2523.05. You can find a copy of the ICR in the docket for
this rule, and it is briefly summarized here. The information
collection requirements are not enforceable until OMB approves them. As
noted in section X.N, the templates for the semiannual and annual
reports for these subparts will be on the CEDRI website.\796\
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\796\ https://www.epa.gov/electronic-reporting-air-emissions/cedri.
---------------------------------------------------------------------------
40 CFR part 60, subpart OOOOa. The respondents are owners or
operators of onshore oil and natural gas affected facilities. For the
purposes of this ICR, it is assumed that oil and natural gas affected
facilities located in the U.S. are owned and operated by the oil and
natural gas industry, and that none of the affected facilities in the
U.S. are owned or operated by Federal, state, Tribal, or local
government. All affected facilities are assumed to be privately owned
for-profit businesses.
The EPA estimates an average of 4,250 respondents will be affected
by NSPS OOOOa over the three-year period (2023-2025). The average
annual burden for the recordkeeping and reporting requirements for
these owners and operators is 375,338 person-hours, with an average
annual cost of $126,543,957 over the three-year period.
Respondents/affected entities: Oil and natural gas operators and
owners.
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: 4,250.
Frequency of response: Varies depending on affected facility.\797\
---------------------------------------------------------------------------
\797\ The specific frequency for each information collection
activity within this request is shown in tables 1a through 1d of the
Supporting Statement in the public docket.
---------------------------------------------------------------------------
Total estimated burden: 375,338 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $126,543,957 (2019$), which includes no
capital costs or O&M costs.
40 CFR part 60, subpart OOOOb. The respondents are owners or
operators of onshore oil and natural gas affected facilities and third
parties that are approved as notifiers of super-emitter emissions
events. For the purposes of this ICR, it is assumed that oil and
natural gas affected facilities located in the U.S. are owned and
operated by the oil and natural gas industry, and that none of the
affected facilities in the U.S. are owned or operated by Federal,
state, Tribal, or local government. All affected facilities are assumed
to be privately owned for-profit businesses.
The EPA estimates an average of 1,849 respondents will be affected
by NSPS OOOOb over the 3-year period 2023-2025. The average annual
burden for the recordkeeping and reporting requirements for these
owners and operators is 883,625 person-hours, with an average annual
cost of $58,535,262 over the three-year period.
Respondents/affected entities: Oil and natural gas operators and
owners; approved third-party notifiers.
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: 1,849.
Frequency of response: Varies depending on affected facility.\798\
---------------------------------------------------------------------------
\798\ The specific frequency for each information collection
activity within this request is shown in tables 1a through 1d of the
Supporting Statement in the public docket.
---------------------------------------------------------------------------
Total estimated burden: 883,625 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $58,535,262 (2019$), which includes
$12,182,846 in capital costs.
40 CFR part 60, subpart OOOOc. This rule does not directly impose
specific requirements on oil and natural gas
[[Page 17025]]
facilities located in states or areas of Indian country. The rule also
does not impose specific requirements on Tribal governments that have
affected facilities located in their area of Indian country. This rule
does impose specific requirements on state governments with affected
oil and natural gas facilities. The information collection requirements
are based on the recordkeeping and reporting burden associated with
developing, implementing, and enforcing a plan to limit GHG emissions
from existing sources in the oil and natural gas sector. These
recordkeeping and reporting requirements are specifically authorized by
CAA section 114 (42 U.S.C. 7414). All information submitted to the EPA
pursuant to the recordkeeping and reporting requirements for which a
claim of confidentiality is made is safeguarded according to Agency
policies set forth in 40 CFR part 2, subpart B.
The annual burden for this collection of information for the states
(averaged over the first 3 years following promulgation) is estimated
to range from 166,000 to 208,000 hours at a total annual labor cost of
between $21 to $26 million. The annual burden for the Federal
government associated with the state collection of information
(averaged over the first 3 years following promulgation) is estimated
to be 22,520 hours at a total annual labor cost of $1,399,930. The
annual burden for industry (averaged over the first 3 years following
promulgation) is estimated to be 2.2 million hours at a total annual
labor cost of $166 million. We realize, however, that some facilities
may not incur these costs within the first 3 years and may incur them
during the fourth or fifth year instead. Therefore, this ICR presents a
conservatively high burden estimate for the initial 3 years following
promulgation of the EG. Burden is defined at 5 CFR 1320.3(b).
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB
approves this ICR, the Agency will announce that approval in the
Federal Register and publish a technical amendment to 40 CFR part 9 to
display the OMB control number for the approved information collection
activities contained in this final rule.
C. Regulatory Flexibility Act (RFA)
Pursuant to sections 603 and 609(b) of the RFA, the EPA prepared an
initial regulatory flexibility analysis (IRFA) for the proposed rule
and convened a Small Business Advocacy Review (SBAR) Panel to obtain
advice and recommendations from small entity representatives that
potentially would be subject to the rule's requirements. Summaries of
the IRFA and Panel recommendations are presented in the proposed rule
at 86 FR 63260 (November 15, 2021) and 87 FR 74702 (December 6, 2022).
The complete IRFA is available in the RIA for the December 2022
Supplemental Proposal (see section 4.3 of the RIA).
As required by section 604 of the RFA, the EPA prepared a final
regulatory flexibility analysis (FRFA) for this action. The FRFA
addresses the issues raised by public comments on the IRFA for the
proposed rule. The complete FRFA is available for review in the docket
and is summarized here. The scope of the FRFA is limited to the NSPS
OOOOb. The impacts of the EG OOOOc are not evaluated here because the
EG OOOOc does not place explicit requirements on the regulated
industry. Those impacts will be evaluated pursuant to the development
of a Federal plan.
The final rulemaking takes a significant step forward in mitigating
climate change and improving human health by reducing GHG and VOC
emissions from the oil and natural gas industry, specifically the Crude
Oil and Natural Gas source category. The oil and natural gas industry
is the United States' largest industrial emitter of methane. Human
emissions of methane, a potent GHG, are responsible for about one third
of the warming due to well-mixed GHGs, the second most important human
warming agent after carbon dioxide. The EPA is finalizing the actions
described in the preamble in accordance with its legal obligations and
authorities following a review directed by E.O. 13990, ``Protecting
Public Health and the Environment and Restoring Science to Tackle the
Climate Crisis,'' issued on January 20, 2021. The EPA intends for the
rulemaking to address the far-reaching harmful consequences and real
economic costs of climate change. According to the IPCC, ``It is
unequivocal that human influence has warmed the atmosphere, ocean and
land. Widespread and rapid changes in the atmosphere, ocean, cryosphere
and biosphere have occurred.'' These changes have led to increases in
heat waves and wildfire weather, reductions in air quality, more
intense hurricanes and rainfall events, and rising sea level. These
changes, along with future projected changes, endanger the physical
survival, health, economic well-being, and quality of life of people
living in America, especially those in the most vulnerable communities.
The EPA finalizes certain NSPS and to promulgate additional NSPS
for both methane and VOC emissions from new oil and natural gas sources
in the production, processing, transmission and storage segments of the
industry; and promulgates EG to require states to regulate methane
emissions from existing sources in those segments. The large amount of
methane emissions from the oil and natural gas industry coupled with
the adverse effects of methane on the global climate compel immediate
regulatory action. The final rule comports with the EPA's CAA section
111 obligation to reduce dangerous pollution and responds to the
urgency expressed by the current Congress. With the proposal, the EPA
is taking additional steps in the regulation of the Crude Oil and
Natural Gas source category to protect human health and the
environment.
The significant issues raised in public comments specifically in
response to the initial regulatory flexibility analysis came from the
Office of Advocacy within the Small Business Administration. In
response to the Advocacy's comments, the EPA agreed that issuing a
revised IRFA with the December 2022 Supplemental Proposal was
warranted, and the revision was published as section 4.3 in the
December 2022 Supplemental Proposal RIA. The revised IRFA addressed
Advocacy's critiques of the IRFA contained in the November 2021
Proposal RIA by providing a robust discussion of regulatory
alternatives related to provisions for the following elements: fugitive
emissions requirements, alternative technologies, associated gas
requirements, process controller and pumps requirements, and
reciprocating compressor requirements. For the final regulatory
flexibility analysis, the EPA is also including discussion of
regulatory alternatives for centrifugal compressor and liquids
unloading requirements. Taken together, this discussion addresses
Advocacy's concerns about the insufficiency of the discussion of
regulatory alternatives in the November 2021 Proposal IRFA. In
addition, the revised IRFA noted that the December 2022 Supplemental
Proposal did not require OGI in accordance with the proposed appendix K
for production sites. While equipment leaks at gas plants were still
proposed to be monitored using OGI in accordance with appendix K in the
December 2022 Supplemental Proposal, the burden estimates summarized in
the revised IRFA reflected burden associated with appendix K. Finally,
the
[[Page 17026]]
burden estimates were updated to reflect the proposed NSPS OOOOb.
Following the issuance of the December 2022 Supplemental Proposal,
Advocacy provided additional comments. While noting that it continued
to have significant concerns about the impact the rule would have on
small businesses in the oil and gas production sector, Advocacy
acknowledged the work that the EPA did to improve its RFA compliance
through the IRFA between proposals. More detailed responses to
Advocacy's comments can be found in Chapter 21 of both Volume I and
Volume II of the RTC document.
The RFA defines small entities as including ``small businesses,''
``small governments,'' and ``small organizations'' (5 U.S.C. 601). The
regulatory revisions being considered by the EPA for this rulemaking
are expected to affect a variety of small businesses but would not
affect any small governments or small organizations. The RFA references
the definition of ``small business'' found in the Small Business Act,
which authorizes the Small Business Administration (SBA) to further
define ``small business'' by regulation. The detailed listing of SBA
definitions of small business for oil and natural gas industries or
sectors, by NAICS code, that are potentially affected by this proposal
is included in table 4-12 of the RIA. The EPA conducted this initial
regulatory flexibility analysis at the ultimate (i.e., highest) level
of ownership, evaluating ultimate parent entities.
To estimate the number of small businesses potentially impacted by
the rule, the EPA developed a list of operators of oil and natural gas
wells, natural gas processing plants, and natural gas compressor
stations. The initial list of operators included 1,451 well site
operators that completed a well in 2019, 297 processing plant
operators, and 574 compressor station operators. The EPA then conducted
a small business coding exercise as shown in table 4-13 of the RIA. In
total, 998 of the 1,451 well site operators (69 percent) matched to 914
ultimate parent companies; 270 of 297 processing plant operators (91
percent) matched to 149 ultimate parent companies; and 519 of 574
compressor station operators (90 percent) matched to 315 ultimate
parent companies.
To estimate the compliance cost impacts of the proposed rule on
small entities, the EPA used the dataset of operators matched to
ultimate parent companies discussed in the previous section and apply
the sum of incremental costs for all relevant affected facility
categories. Because the incremental costs depend on unknown
characteristics of operator-specific well sites, processing plants, and
compressor stations, we use average equipment counts at each facility
type to derive estimates of average impacts at each facility type.
Ultimately, the EPA estimated cost-to-sales ratios for each small
entity to summarize the impacts of the proposed NSPS. See information
and results presented in tables 4-14 to 4-16 of the RIA.
Prior to the November 2021 Proposal, the EPA convened a SBAR Panel
to obtain recommendations from small entity representatives on elements
of the regulation. The Panel identified significant alternatives for
consideration by the Administrator of the EPA, which were summarized in
a final report.\799\ Based on the Panel recommendations, as well as
comments received in response to the November 2021 Proposal and
December 2022 Supplemental Proposal, the EPA is finalizing several
regulatory alternatives that could accomplish the stated objectives of
the CAA while minimizing any significant economic impact of the final
rule on small entities. While the RIA included a full detailed
discussion of these alternatives, the EPA is including two examples
below.
---------------------------------------------------------------------------
\799\ See Document ID EPA-HQ-OAR-2021-0317-0074.
---------------------------------------------------------------------------
First, as described in section XI.A. of this preamble, the EPA
finalizing certain changes to the fugitives emissions standards that
were proposed in November 2021 for NSPS OOOOb and revised in the
December 2022 Supplemental Proposal. The EPA believes that two of these
proposed changes will reduce impacts on small businesses: (1) requiring
OGI monitoring for well sites and centralized production facilities
following the monitoring plan required in proposed 40 CFR 60.5397b
instead of requiring the procedures being proposed in appendix K for
these sites and (2) defining monitoring technique and frequency based
on the equipment present at a well site. The EPA describes these two
changes below.
In the final rule, the EPA is not requiring OGI monitoring in
accordance with the proposed appendix K for well sites or centralized
production facilities, as was proposed in the November 2021 Proposal.
Instead, the EPA is requiring OGI surveys following the procedures
specified in the regulatory text for NSPS OOOOb (at 40 CFR 60.5397b) or
according to EPA Method 21. This change is consistent with the
requirements for OGI surveys found in NSPS OOOOa at 40 CFR 60.5397a.
This final change is a result of the extensive comments the EPA
received from oil and natural gas operators and other groups on the
numerous complexities associated with following the proposed appendix
K, especially considering the remoteness and size of many of these well
sites.\800\ In addition, commenters pointed out that OGI has always
been the BSER for fugitive monitoring at well sites and was never
designed as a replacement for EPA Method 21, while appendix K was
designed for use at more complex processing facilities that have
historically been subject to monitoring following EPA Method 21. The
EPA agrees with the commenters and is finalizing requirements within
NSPS OOOOb at 40 CFR 60.5397b in lieu of the procedures in appendix K
for fugitive emissions monitoring at well sites or centralized
production facilities. See section X.I.V of the preamble for additional
information on what the EPA is finalizing for appendix K related to
other sources (e.g., natural gas processing plants). The EPA believes
this will particularly benefit small entities because it will
streamline the requirements for conducting and documenting OGI surveys
at these smaller, less complex sites. Additionally, this change
provides a uniform set of requirements for regulated entities that may
have assets subject to different subparts within the same region, which
leads to increased regulatory certainty and eases the compliance
burden. At the same time, the EPA believes this does not compromise the
stated objectives of the Clean Air Act because these same requirements
are already allowed in NSPS OOOOa and outline many of the same data
elements required by appendix K.
---------------------------------------------------------------------------
\800\ See final rule preamble section XI.A. and see Document ID
Nos. EPA-HQ-OAR-2021-0317-0579, -0743, -0764, -0777, -0782, -0786, -
0793, -0802, -0807, -0808, -0810, -0814, -0817, -0820, -0831, -0834,
and -0938.
---------------------------------------------------------------------------
Next, the final rule includes fugitive monitoring frequencies and
detection techniques that are based on the type of equipment located at
a well site, instead of the baseline methane emissions threshold that
was included in the November 2021 Proposal and revised in the December
2022 Supplemental Proposal. Specifically, the EPA is finalizing four
distinct subcategories of well sites:
Well sites with only a single wellhead,
Small well sites with a single wellhead and only one piece
of major
[[Page 17027]]
production and processing equipment,\801\
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\801\ Small well sites are defined as single wellhead well sites
that do not contain any controlled storage vessels, control devices,
pneumatic controller affected facilities, or pneumatic pump affected
facilities, and include only one other piece of major production and
processing equipment. Major production and processing equipment that
would be allowed at a small well site would include a single
separator, glycol dehydrator, centrifugal and reciprocating
compressor, heater/treater, and storage vessel that is not
controlled. By this definition, a small well site could only
potentially contain a well affected facility (for well completion
operations or gas well liquids unloading operations that do not
utilize a CVS to route emissions to a control device) and a fugitive
emissions components affected facility. No other affected
facilities, including those utilizing CVS (such as pneumatic pumps
routing to control) can be present for a well site to meet the
definition of a small well site. The EPA is soliciting comment on
this definition for small well sites, including whether additional
metrics should be used beyond equipment counts, as well as the
proposed standards and requirements for this subcategory of sites.
---------------------------------------------------------------------------
Well sites with only two or more wellheads and no other
major production and processing equipment, and
Well sites with one or more controlled storage vessels,
control devices, natural gas-driven pneumatic controllers or pumps, or
two or more other major production and processing equipment, including
centralized production facilities.
The EPA is finalizing these distinct subcategories of well sites
after consideration of comments on the November 2021 Proposal and the
December 2022 Supplemental Proposal that stated the original baseline
methane emissions threshold approach would be difficult to implement,
especially for small businesses that may be less familiar with the use
of emission factors from the EPA's Greenhouse Gas Reporting Program.
The EPA believes that owners and operators, including small entities,
can readily identify the number and types of major equipment located at
a well site without the need for complicated calculations of emissions.
Further, the EPA is finalizing specific monitoring frequencies and
techniques as the BSER for each well site subcategory individually. For
example, the EPA is finalizing the use of audible, visual, and
olfactory (AVO) inspections at well sites containing only a single
wellhead and at small well sites. This monitoring technique does not
require specialized equipment or operator training, but does allow the
identification of large leaks, which are of the most concern from an
environmental standpoint. Further, AVO monitoring can easily be built
into regular maintenance activities that are designed to keep the
equipment at the site in good working order. The final requirements are
responsive to a SER recommendation that the EPA allow AVO and soap
bubble tests as an option for finding fugitive emissions, particularly
because they are low cost and easy to implement alternatives for
detecting leaks, and an Advocacy recommendation that the EPA allow AVO
as an alternative in limited circumstances, such as part of an off-ramp
for facilities unlikely to emit more than insignificant methane or with
a demonstrated history of insignificant emissions. The EPA believes
this will particularly benefit small entities because AVO surveys at
these types of well sites are effective at identifying the types of
large emissions from sources located at these well sites at a much
lower cost than OGI surveys. For example, the costs associated with the
quarterly AVO inspections are estimated at $660/year, whereas the costs
associated with an annual OGI survey for this type of well site are
estimated at approximately $2,000/yr. Inspections via AVO allow for
more frequent inspections for large emissions events at these well
sites, which results in faster emissions mitigation, than a single OGI
survey each year.
In a second example, in the November 2021 Proposal, the EPA
proposed that an owner or operator of a reciprocating compressor
affected facility would be required to monitor the rod packing
emissions annually by conducting flow rate measurements. When the
measured flow rate exceeded 2 scfm (in pressurized mode), replacement
of the rod packing would have been required. Alternatively, the
November 2021 Proposal would have also provided owners and operators
the option of routing rod packing emissions to a process via a closed
vent system under negative pressure in order to comply with the rule.
The proposed option to route to a process would have been allowed as an
alternative under NSPS OOOOb because implementing this option, where
feasible, would achieve greater emission reductions than the proposed
performance-based emissions threshold standard. The December 2022
Supplemental Proposal proposed changes and specific clarifications to
the November 2021 Proposal standards for NSPS OOOOb. For the proposed
replacement of the rod packing based on an emission limit and annual
measurement requirement, we proposed: (1) To clarify that the standard
of performance is a numeric standard (not a work practice standard) of
2 scfm, (2) to allow for repair (in addition to replacement) of the rod
packing in order to maintain an emission rate at or below 2 scfm, and
(3) to allow for monitoring based on 8,760 hours of operation instead
of based on a calendar year. The EPA also proposed regulatory text that
defined the required flow rate measurement methods and/or procedure
requirements, and recordkeeping and reporting requirements. For the
alternative option of routing rod packing emissions to a process via a
closed vent system under negative pressure, the EPA proposed to remove
the negative pressure requirement.
As described in the preamble to the final rule,\802\ the EPA is
finalizing changes to the proposed requirements for reciprocating
compressors in for NSPS OOOOb as a result of comments received on the
November 2021 Proposal and December 2022 Supplemental Proposal. The EPA
believes the following rule changes will reduce impacts on small
businesses.
---------------------------------------------------------------------------
\802\ See final rule preamble section XI.I.
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Concerns were expressed regarding the EPA's November 2021 Proposal
and December 2022 Supplemental Proposal that shifted rod packing
changeout requirements from a designated schedule of once every 3 years
to a performance standard based on an annual flow rate measurement.
While the November 2021 Proposal format of the performance standard
based on volumetric flow rate measurements was as a work practice
standard, the December 2022 Supplemental Proposal format of the
performance standard was as a numeric standard. Commenters on the
December 2022 Supplemental Proposal expressed that, as a numeric
standard, the performance standard based on flow measurements was
unworkable. It was also noted that a performance standard is often more
expensive than a fixed equipment change-out standard because of the
additional monitoring and recordkeeping necessary to demonstrate
compliance with the performance standard, which they believed could
negatively impact small businesses. These commenters also supported the
fixed schedule rod packing change-out standard because this is the
standard owners and operators have implemented for reciprocating
compressors under NSPS OOOOa and stated that the annual flow rate
performance work practice standard would lead to more rod packing
changeouts than would be required based on the November OOOOa fixed-
schedule packing change out requirements.
[[Page 17028]]
The EPA is finalizing the following requirement changes associated
with the reciprocating compressor rod packing volumetric flow rate
measurement performance standard based on November 2021 Proposal and
December 2022 Supplemental Proposal comments: (1) a 2 scfm volumetric
flow rate per cylinder performance work practice standard, (2) repair
(in addition to replacement) of the rod packing is allowed to maintain
an emission rate at or below 2 scfm per cylinder; and (3) monitoring
based on 8,760 hours of operation instead of based on a calendar year.
These final requirements for reciprocating compressors are responsive
to comments and concerns expressed by industry (including small
businesses).
The EPA believes the final rule 2 scfm volumetric flow rate per
cylinder performance work practice standard approach benefits small
entities because facilities can use monitoring data to determine
emission levels at which it is necessary to repair or replace rod
packing. This approach can result in operational benefits, including a
longer life for existing equipment, improvements in operating
efficiencies, and long-term cost savings. Allowing an owner or operator
to repair the rod packing (in addition to replacement of the rod
packing) to maintain an emission rate at or below 2 scfm per cylinder
alleviates the need to replace the rod packing when only a simple
repair may be needed to maintain volumetric flow rate at or below 2
scfm per cylinder. Requiring owners and operators to conduct volumetric
flow rate monitoring based on 8,760 hours of operation instead of based
on a calendar year reduces the burden on owners and operators where
compressors are not operational for multiple months or are used
intermittently. Additionally, by requiring that monitoring frequency
based on hours of operation, owners and operators have the flexibility
to stagger maintenance activity throughout the year. The final rule
defines the required flow rate measurement methods and/or procedures,
repair and replacement requirements, and recordkeeping and reporting
requirements.
In addition, the following regulatory options have been added to
the final rule: (1) owners and operators are allowed to change out
reciprocating compressor rod packing every 8,760 hours of operation in
lieu of conducting volumetric flow rate monitoring every 8,760 hours;
and (2) owners and operators are allowed to route emissions to a
control device via a closed vent system in addition to routing
emissions via a closed vent system to a process. For the alternative
option of routing rod packing emissions to a process via a closed vent
system under negative pressure, the EPA is finalizing the removal of
the negative pressure requirement. By allowing owners and operators to
change out rod packing every 8,760 hours of operation in lieu of
conducting volumetric flow rate monitoring every 8,760 hours, owners
and operators have the option to choose a more-stringent rod packing
change out schedule (on or before every 8,760 hours of operation) and
avoid the need to conduct volumetric flow rate monitoring. Lastly, by
the final rule allowing owners and operators to route emissions to a
control device in addition to routing emissions to a process, the EPA
has added flexibility to the compliance options available for owners
and operators.
In addition, the EPA is preparing a Small Entity Compliance Guide
to help small entities comply with this rule. The guide will be
available on the 60 days after publication of the final rule at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/implementation-oil-and-natural-gas-air.
D. Unfunded Mandates Reform Act (UMRA)
The NSPS contains a Federal mandate under UMRA, 2 U.S.C. 1531-1538,
that may result in expenditures of $100 million or more for state,
Tribal, and local governments, in the aggregate, or the private sector
in any 1 year. Accordingly, the EPA has prepared under section 202 of
the UMRA a written statement of the benefit-cost analysis, which can be
found in section XVI of this preamble, and in Chapter 1 of the RIA.
Consistent with section 205 of UMRA, the EPA has identified and
considered a reasonable number of regulatory alternatives. These
alternatives are described in section XI of this preamble.
The EG is promulgated under CAA section 111(d) and does not impose
any direct compliance requirements on designated facilities, apart from
the requirement for states to develop state plans. As explained in
section XIV.G of the November 2021 Proposal \803\ and section V of the
December 2022 Supplemental Proposal, the EG also does not impose
specific requirements on Tribal governments that have designated
facilities located in their area of Indian country. The burden for
states to develop state plans following promulgation of the rule is
estimated to be below $100 million in any 1 year. Thus, the EG is not
subject to the requirements of section 203 or section 205 of the UMRA.
---------------------------------------------------------------------------
\803\ See 86 FR 63256 (November 15, 2021) and 87 FR 74702
(December 6, 2022).
---------------------------------------------------------------------------
The NSPS and EG are also not subject to the requirements of section
203 of UMRA because, as described in 2 U.S.C. 1531-38, they contain no
regulatory requirements that might significantly or uniquely affect
small governments. Specifically, for the EG the state governments to
which rule requirements apply are not considered small governments. In
light of the interest among governmental entities, the EPA conducted
outreach with national organizations representing states and Tribal
governmental entities while formulating the proposed rule as discussed
in the November 2021 Proposal, the December 2022 Supplemental Proposal,
and section VII of this final preamble.\804\ The EPA considered the
stakeholders' experiences and lessons learned to help inform how to
better structure this final rule and consider ongoing challenges that
will require continued collaboration with stakeholders.
---------------------------------------------------------------------------
\804\ See 86 FR 63145 (November 15, 2021).
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E. Executive Order 13132: Federalism
The final NSPS OOOO, OOOOa, and OOOOb and final EG OOOOc do not
have federalism implications. These actions will not have substantial
direct effects on the states as defined in the E.O., on the
relationship between the Federal Government and the states, or on the
distribution of power and responsibilities among the various levels of
government.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action has Tribal implications. However, it will neither
impose substantial direct compliance costs on federally recognized
Tribal governments, nor preempt Tribal law, and does not have
substantial direct effects on one or more Indian Tribes, the
relationship between the Federal Government and Indian Tribes or on the
distribution of power and responsibilities between the Federal
Government and Indian Tribes, as specified in E.O. 13175. See 65 FR
67249 (November 9, 2000). As stated in the November 2021 Proposal, the
EPA found that 112 unique Tribal lands are located within 50 miles of
an affected oil and natural gas source, and 32 Tribes have one or more
oil or natural gas sources on their lands.\805\ While many of the
affected and designated facilities impacted by final NSPS and EG on
[[Page 17029]]
Tribal lands are owned by private entities, some Tribes also own
affected and or designated facilities. There would be Tribal
implications associated with this rulemaking in the case where a unit
is owned by a Tribal government or in the case of the NSPS, a Tribal
government is given delegated authority to enforce the rulemaking.
Tribes are not required to develop plans to implement the EG under CAA
section 111(d) for designated existing sources. The EPA notes that this
final rule does not directly impose specific requirements on designated
facilities, including those located in Indian country. Before
developing any standards for sources on Tribal land, the EPA would
consult with leaders from affected Tribes.
---------------------------------------------------------------------------
\805\ 86 FR 63143 (November 15, 2021).
---------------------------------------------------------------------------
Tribal consultations were completed after the November 2021
Proposal at the request of the Northern Arapahoe Tribe, MHA Nation, and
Eastern Shoshone Tribe.\806\ Additional Tribal consultation was
completed at the request of MHA Nation and an informational meeting was
held with the Ute Tribe after the December 2022 Supplemental
Proposal.\807\ Consistent with previous actions affecting the Crude Oil
and Natural Gas source category, the EPA understands there is continued
significant Tribal interest because of the growth of the oil and
natural gas production in Indian country. In accordance with the EPA
Policy on Consultation and Coordination with Indian Tribes, the EPA
will continue to engage in consultation with Tribal officials as these
rules become implemented.
---------------------------------------------------------------------------
\806\ See Memorandum in EPA-HQ-OAR-2021-0317.
\807\ See Memorandum in EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is subject to E.O. 13045 (62 FR 19885, April 23, 1997)
because it is a significant regulatory action as defined by E.O.
12866(3)(f)(1), and the EPA believes that the environmental health or
safety risk addressed by this action has a disproportionate effect on
children. Accordingly, the Agency has evaluated the environmental
health and welfare effects of climate change on children. GHGs,
including methane, contribute to climate change and are emitted in
significant quantities by the oil and gas industry. The EPA believes
that the GHG emission reductions resulting from implementation of these
standards and guidelines will further improve children's health. The
assessment literature cited in the EPA's 2009 Endangerment Findings
concluded that certain populations and life stages, including children,
the elderly, and the poor, are most vulnerable to climate-related
health effects (74 FR 66524, December 15, 2009). The assessment
literature since 2009 strengthens these conclusions by providing more
detailed findings regarding these groups' vulnerabilities and the
projected impacts they may experience (e.g., the 2016 Climate and
Health Assessment \808\). These assessments describe how children's
unique physiological and developmental factors contribute to making
them particularly vulnerable to climate change. Impacts to children are
expected from heat waves, air pollution, infectious and waterborne
illnesses, and mental health effects resulting from extreme weather
events. In addition, children are among those especially susceptible to
most allergic diseases, as well as health effects associated with heat
waves, storms, and floods. Additional health concerns may arise in low-
income households, especially those with children, if climate change
reduces food availability and increases prices, leading to food
insecurity within households. More detailed information on the impacts
of climate change to human health and welfare is provided in sections
III and VI of the November 2021 Proposal,\809\ section VII of the
December 2022 Supplemental Proposal,\810\ and section XVI of this
document. Under the final NSPS OOOOb and EG OOOOc, the EPA expects that
VOC and methane emissions reductions will improve air quality and
mitigate climate impacts which will benefit the health and welfare of
children.
---------------------------------------------------------------------------
\808\ USGCRP, 2016: The Impacts of Climate Change on Human
Health in the United States: A Scientific Assessment. Crimmins, A.,
J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J.
Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M.
Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S.
Global Change Research Program, Washington, DC, 312 pp. http://dx.doi.org/10.7930/J0R49NQX.
\809\ See 86 FR 63124 and 86 FR 63139 (November 15, 2021).
\810\ See 87 FR 74702 (December 6, 2022).
---------------------------------------------------------------------------
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action, which is a significant regulatory action under E.O.
12866, has a significant adverse effect on the supply, distribution or
use of energy as that phrase is defined in E.O. 13211. The
documentation for this decision is contained in section 4.1.4 of the
Regulatory Impact Analysis for the Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review for this
final action. To make this determination, we compare the projected
change in crude oil and natural gas production to guidance articulated
in a January 13, 2021, OMB memorandum, Furthering Compliance with
Executive Order 13211, Titled ``Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use.'' \811\ With
respect to crude oil production, the guidance indicates that a
regulatory action produces a significant adverse effect if it is
expected to produce reductions in crude oil supply in excess of 20
million barrels per year. With respect to natural gas production, the
guidance indicates that a regulatory action produces a significant
adverse effect if it reduces natural gas production in excess of 40
million mcf per year.\812\ We estimate maximum production reductions of
about 41.4 million barrels of crude oil (1.05 percent of projected
baseline production) and 272.5 million Mcf per year (0.75 percent).
---------------------------------------------------------------------------
\811\ See https://www.whitehouse.gov/wp-content/uploads/2021/01/M-21-12.pdf.
\812\ The 2021 E.O. 13211 guidance memo states that the natural
gas production decrease that indicates the regulatory action is a
significant energy action is 40 mcf per year. Because this is a
relatively small amount of natural gas and previous guidance from
2001 indicated a threshold of 25 million Mcf, we assume the 2021
memo was intended to establish 40 million Mcf as the indicator of an
adverse energy effect. See https://www.whitehouse.gov/wp-content/uploads/2017/11/2001-M-01-27-Guidance-for-Implementing-E.O.-13211.pdf.
---------------------------------------------------------------------------
I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR
Part 51
This rulemaking involves technical standards. Therefore, the EPA
conducted searches for the Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review through the
Enhanced National Standards Systems Network (NSSN) Database managed by
the American National Standards Institute (ANSI). Searches were
conducted for EPA Methods 1, 1A, 2, 2A, 2C, 2D, 3A, 3B, 3C, 4, 6, 10,
15, 16, 16A, 18, 21, 22, 25A of 40 CFR part 60, appendix A, EPA-454/B-
08-002, and EPA-600/R-12/531. No applicable voluntary consensus
standards (VCS) were identified for EPA Methods 1A, 2A, 2D, 21, and 22
and none were brought to its attention in comments. All potential
standards were reviewed to determine the practicality of the VCS for
this rule. Two VCS were
[[Page 17030]]
identified as an acceptable alternative to EPA test methods for the
purpose of this rule. First, ANSI/ASME PTC 19-10-1981, Flue and Exhaust
Gas Analyses (Part 10) (manual portions only and not the instrumental
portion) was identified to be used in lieu of EPA Methods 3B, 6, 6A,
6B, 15A and 16A. This standard includes manual and instrumental methods
of analysis for CO2, carbon monoxide (CO), H2S,
NOX, O2, and SO2. Second, ASTM
International (ASTM) D6420-99 (2010), ``Test Method for Determination
of Gaseous Organic Compounds by Direct Interface Gas Chromatography/
Mass Spectrometry'' is an acceptable alternative to EPA Method 18 with
the following caveats, only use when the target compounds are all
known, and the target compounds are all listed in ASTM D6420 as
measurable. ASTM D6420 should never be specified as a ``total VOC''
Method. (ASTM D6420-99 (2010) is not incorporated by reference in 40
CFR part 60.) The search identified 19 VCS that were potentially
applicable for this proposed rule in lieu of EPA reference methods.
However, these have been determined to not be practical due to lack of
equivalency, documentation, validation of data and other important
technical and policy considerations. For additional information, please
see the September 10, 2021, memo titled, ``Voluntary Consensus Standard
Results for New, Reconstructed, and Modified Sources and Emissions
Guidelines for Existing Sources: Oil and Natural Gas Sector Climate
Review.'' \813\ In this rule, the EPA is including regulatory text for
40 CFR part 60, subparts OOOOb and OOOOc that includes incorporation by
reference. In accordance with requirements of 40 CFR 60.17, the EPA is
incorporating the following sixteen standards by reference.
---------------------------------------------------------------------------
\813\ See Document ID No. EPA-HQ-OAR-2021-0317-0072.
---------------------------------------------------------------------------
ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses
[Part 10, Instruments and Apparatus] (Issued August 31, 1981) covers
measuring the O2 or CO2 content of the exhaust
gas. It highlights and specifies methods, apparatus, and calculations
which are used in conjunction with Performance Test Codes to determine
quantitatively, the gaseous constituents of exhausts resulting from
stationary combustion sources. The PTC Supplement also describes the
most commonly used instrumentation and analytical procedures used for
flue and exhaust gas analyses.
ASTM D86-96, Distillation of Petroleum Products (Approved
April 10, 1996) covers the distillation of natural gasolines, motor
gasolines, aviation gasolines, aviation turbine fuels, special boiling
point spirits, naphthas, white spirit, kerosine, gas oils, distillate
fuel oils, and similar petroleum products, utilizing either manual or
automated equipment.
ASTM D1945-03 (Reapproved 2010), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography covers the determination
of the chemical composition of natural gases and similar gaseous
mixtures within a certain range of composition. This test method may be
abbreviated for the analysis of lean natural gases containing
negligible amounts of hexanes and higher hydrocarbons, or for the
determination of one or more components.
ASTM D1945-14 (Reapproved 2019), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography covers the determination
of the chemical composition of natural gases and similar gaseous
mixtures within a certain range of composition. This test method may be
abbreviated for the analysis of lean natural gases containing
negligible amounts of hexanes and higher hydrocarbons, or for the
determination of one or more components.
ASTM D2879-83, Test Method for Vapor Pressure-Temperature
Relationship and Initial Decomposition Temperature of Liquids by
Isoteniscope. This test method covers the determination of the vapor
pressure of pure liquids, the vapor pressure exerted by mixtures in a
closed vessel at 40 +/-5 percent ullage, and the initial thermal
decomposition temperature of pure and mixed liquids.
ASTM D2879-96, Test Method for Vapor Pressure-Temperature
Relationship and Initial Decomposition Temperature of Liquids by
Isoteniscope. This method is a revision of ASTM D2879-83. It is suited
for use over a wide range of temperature ranging from ambient to 748 K
and can include below ambient temperature when suitable constant-
temperature bath for such temperature is used.
ASTM D2879-97, Test Method for Vapor Pressure-Temperature
Relationship and Initial Decomposition Temperature of Liquids by
Isoteniscope. This method is a revision of ASTM D2879-96. Most
petroleum products boil over a fairly wide temperature range and an
ideal combination will show a progressive reduction in vapor pressure
as lighter fluid components and may exert pressure in a closed system.
This test method is simulated in the isoteniscope -a constant volume
apparatus.
ASTM D3588-98 (Reapproved 2003), Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuel covers procedures for calculating heating value, relative
density, and compressibility factor at base conditions for natural gas
mixtures from compositional analysis. It applies to all common types of
utility gaseous fuels.
ASTM D4891-89 (Reapproved 2006), Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion covers the determination of the heating value of natural
gases and similar gaseous mixtures within a certain range of
composition.
ASTM D6348-12e1, Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy. This field test method employs an
extractive sampling system to direct stationary source effluent to an
FTIR spectrometer for the identification and quantification of gaseous
compounds. Also, this method employs converting the volume
concentration to a mass emission rate utilizing a compound's molecular
weight, and the effluent volumetric flow rate, temperature and pressure
in determining the impact of that particular compound to the
atmosphere.
ASTM D6522-20, Standard Test Method for Determination of
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in
Emissions from Natural Gas-Fired Reciprocating Engines, Combustion
Turbines, Boilers, and Process Heaters Using Portable Analyzers covers
the determination of NOX, CO, and O2
concentrations in controlled and uncontrolled emissions from natural
gas-fired reciprocating engines, combustion turbines, boilers, and
process heaters.
ASTM E168-16 (Reapproved 2023), Standard Practices for
General Techniques of Infrared Quantitative Analysis covers the
techniques most often used in infrared quantitative analysis. Practices
associated with the collection and analysis of data on a computer are
included as well as practices that do not use a computer.
ASTM E169-16 (Reapproved 2022), Standard Practices for
General Techniques of Ultraviolet Quantitative Analysis provide general
information on the techniques most often used in ultraviolet and
visible quantitative analysis. The purpose is to render unnecessary the
repetition of these descriptions of techniques in individual methods
for quantitative analysis.
ASTM E260-96, General Gas Chromatography Procedures is a
general
[[Page 17031]]
guide to the application of gas chromatography with packed columns for
the separation and analysis of vaporizable or gaseous organic and
inorganic mixtures and as a reference for the writing and reporting of
gas chromatography methods.
EPA-454/B-08-002, Quality Assurance Handbook for Air
Pollution Measurement Systems Volume IV: Meteorological Measurements
Version 2.0 (Final), March 2008. This guidance is designed to provide
clear and concise information to the State/Local/Tribal (SLT) air
pollution control agencies that operate meteorological monitoring
equipment and systems.
EPA-600/R-12/531, EPA Traceability Protocol for Assay and
Certification of Gaseous Calibration Standards (Issued May 2012) is
mandatory for certifying the calibration gases being used for the
calibration and audit of ambient air quality analyzers and continuous
emission monitors that are required by numerous parts of the CFR.
The EPA determined that the ASTM and ASME/ANSI standards,
notwithstanding the age of the standards, are reasonably available
because they are available for purchase from the following addresses:
ASTM International 100 Barr Harbor Drive, Post Office Box C700, West
Conshohocken, PA 19428-2959, +1.610.832.9500, www.astm.org; or
ProQuest, 300 North Zeeb Road, Ann Arbor, MI 48106, +1.877.779.6768,
www.proquest.com; and the American Society of Mechanical Engineers
(ASME), Three Park Avenue, New York, NY 10016-5990, +1.800.843.5990,
[email protected], www.asme.org. The EPA determined that the EPA
standard is reasonably available because it is publicly available
through the EPA's website: https://nepis.epa.gov/Adobe/PDF/P100EKJR.pdf.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations and
Executive Order 14096: Revitalizing Our Nation's Commitment to
Environmental Justice for All
The EPA believes that the human health or environmental conditions
that exist prior to this action result in or have the potential to
result in disproportionate and adverse human health or environmental
effects on communities with EJ concerns. With respect to exposure to
ambient ground-level ozone, the baseline scenario is similar to that
described by other RIAs in that there are small but disproportionate
and adverse effects on some populations analyzed including American
Indians, Asians, Hispanics, those who are Linguistically isolated,
those living in Redlined areas, and those living on Tribal land. On
average, these demographic groups are exposed to at least 0.9 ppb (and
at most 2.0 ppb) higher ozone concentrations than the reference
population.
As described above, this final rulemaking will result in reductions
in VOCs, which are an important precursor contributing to ground-level
ozone formation in many regions of the country. VOC emissions from oil
and gas operations are believed to be a factor contributing to elevated
ozone levels in multiple areas of the country including Colorado, New
Mexico, Texas, Utah and Wyoming. Although the EPA's analysis indicates
that the final rulemaking will have relatively small effects on ambient
ozone concentrations when compared to baseline conditions, the EPA
nonetheless anticipates that communities with environmental justice
concerns will benefit from reductions in VOC emissions that contribute
to ozone formation in diverse areas of the country.
At the same time, the reductions in ozone concentrations that will
result from this rulemaking are expected to be evenly distributed
across most demographic groups. The EPA believes that this action is
likely to reduce existing disproportionate and adverse effects on
people who live on Tribal lands in some states (most notably Colorado).
However, for all other demographic groups and geographic locations, the
EPA believes this action is not likely to meaningfully change existing
disproportionate and adverse effects. The reductions in ozone
concentrations due to the policy option are similar in magnitude across
most demographic groups and small relative to baseline conditions, such
that it is unlikely that the policy option will exacerbate or mitigate
any disproportionate exposures to ozone that were present at baseline.
The documentation for this assessment is contained in section 4 of
the Regulatory Impact Analysis for the Proposed Standards of
Performance for New, Reconstructed, and Modified Sources and Emissions
Guidelines for Existing Sources: Oil and Natural Gas Sector Climate
Review prepared for the November 2021 Proposal,\814\ in section 4 of
the Regulatory Impact Analysis of the Supplemental Proposal for the
Standards of Performance for New, Reconstructed, and Modified Sources
and Emissions Guidelines for Existing Sources: Oil and Natural Gas
Sector Climate Review prepared for the December 2022 Supplemental
Proposal,\815\ and in section 4 of the Regulatory Impact Analysis for
the Standards of Performance for New, Reconstructed, and Modified
Sources and Emissions Guidelines for Existing Sources: Oil and Natural
Gas Sector Climate Review prepared for this action.
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\814\ See Document ID No. EPA-HQ-OAR-2021-0317-0173.
\815\ See Document ID No. EPA-HQ-OAR-2021-0317-1566.
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This rulemaking will also reduce methane pollution that contributes
to climate change, which itself has substantial and adverse impacts on
environmental justice communities. Methane emissions represent a
significant share of total GHG emissions and hence are a major
contributor to climate change. In 2009, under the Endangerment and
Cause or Contribute Findings for Greenhouse Gases Under Section 202(a)
of the Clean Air Act (``Endangerment Finding''), the Administrator
considered how climate change threatens the health and welfare of the
U.S. population. As part of that consideration, she also considered
risks to people of color and low-income individuals and communities,
finding that certain parts of the U.S. population may be especially
vulnerable based on their characteristics or circumstances. These
groups include economically and socially vulnerable communities;
individuals at vulnerable life stages, such as the elderly, the very
young, and pregnant or nursing women; those already in poor health or
with comorbidities; the disabled; those experiencing homelessness,
mental illness, or substance abuse; and/or Indigenous or people of
color dependent on one or limited resources for subsistence due to
factors including but not limited to geography, access, and mobility.
Scientific assessment reports produced over the past decade by the
U.S. Global Change Research Program (USGCRP), the IPCC, and the
National Academies of Science, Engineering, and Medicine add more
evidence that the impacts of climate change raise potential EJ
concerns.\816\
---------------------------------------------------------------------------
\816\ IPCC. (2018). Global Warming of 1.5 [deg]C. An IPCC
Special Report on the impacts of global warming of 1.5 [deg]C above
pre-industrial levels and related global greenhouse gas emission
pathways, in the context of strengthening the global response to the
threat of climate change, sustainable development, and efforts to
eradicate poverty (V. Masson-Delmotte, P. Zhai, H.-O. P[ouml]rtner,
D. Roberts, J. Skea, P.R. Shukla, A. Pirani, W. Moufouma-Okia, C.
P[eacute]an, R. Pidcock, S. Connors, J.B.R. Matthews, Y. Chen, X.
Zhou, M.I. Gomis, E. Lonnoy, T. Maycock, a. M. Tignor, & T.
Waterfield Eds.).; Oppenheimer, M., Campos, M., Warren, R.,
Birkmann, J., Luber, G., O'Neill, B., & Takahashi, K. (2014).
Emergent risks and key vulnerabilities. In C.B. Field, V.R. Barros,
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee,
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N.
Levy, S. MacCracken, P.R. Mastrandrea, & L.L. White (Eds.), Climate
Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global
and Sectoral Aspects. Contribution of Working Group II to the Fifth
Assessment Report of the Intergovernmental Panel on Climate Change
(pp. 1039-1099). Cambridge, United Kingdom and New York, NY:
Cambridge University Press; Porter, J.R., Xie, L., Challinor, A.J.,
Cochrane, K., Howden, M., Iqbal, M.M., & Lobell, D.B. (2014). Food
security and food production systems. In C.B. Field, V.R. Barros,
D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. Chatterjee,
K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N.
Levy, S. MacCracken, P.R. Mastrandrea, & L.L. White (Eds.), Climate
Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global
and Sectoral Aspects. Contribution of Working Group II to the Fifth
Assessment Report of the Intergovernmental Panel on Climate Change
(pp. 485-533). Cambridge, United Kingdom and New York, NY: Cambridge
University Press; Smith, K. R., Woodward, A., Campbell-Lendrum, D.,
Chadee, D. D., Honda, Y., Liu, Q., . . . Sauerborn, R. (2014). Human
Health: Impacts, Adaptation, and Co-Benefits. In C.B. Field, V.R.
Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M.
Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S.
Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, & L.L.White
(Eds.), Climate Change 2014: Impacts, Adaptation, and Vulnerability.
Part A: Global and Sectoral Aspects. Contribution of Working Group
II to the Fifth Assessment Report of the Intergovernmental Panel on
Climate Change (pp. 709-754). Cambridge, United Kingdom and New
York, NY: Cambridge University Press; USGCRP. (2016). The Impacts of
Climate Change on Human Health in the United States: A Scientific
Assessment. Washington DC: U.S. Global Change Research Program.
https://dx.doi.org/10.7930/J0R49NQX; USGCRP. (2018). Impacts, Risks,
and Adaptation in the United States: Fourth National Climate
Assessment, Volume II. Washington DC: U.S. Global Change Research
Program. https://dx.doi.org/10.7930/NCA4.2018.
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[[Page 17032]]
These reports conclude that poorer or predominantly non-White
communities can be especially vulnerable to climate change impacts
because they tend to have limited adaptive capacities and are more
dependent on climate-sensitive resources such as local water and food
supplies, or have less access to social and information resources. Some
communities of color, specifically populations defined jointly by
ethnic/racial characteristics and geographic location, may be uniquely
vulnerable to climate change health impacts in the U.S. In particular,
the 2016 scientific assessment on the Impacts of Climate Change on
Human Health found with high confidence that vulnerabilities are place-
and time-specific, life stages and ages are linked to immediate and
future health impacts, and social determinants of health are linked to
greater extent and severity of climate change-related health impacts.
The GHG emission reductions associated with this proposal would
contribute to efforts to reduce the probability of severe impacts
related to climate change. Individuals living in socially and
economically disadvantaged communities, such as those living at or
below the poverty line or who are experiencing homelessness or social
isolation, are at greater risk of health effects from climate change.
This is also true with respect to people at vulnerable life stages,
specifically women who are pre- and perinatal, or are nursing; in utero
fetuses; children at all stages of development; and the elderly. Per
the Fourth National Climate Assessment (NCA4), ``Climate change affects
human health by altering exposures to heat waves, floods, droughts, and
other extreme events; vector-, food- and waterborne infectious
diseases; changes in the quality and safety of air, food, and water;
and stresses to mental health and well-being.'' Many health conditions
such as cardiopulmonary or respiratory illness and other health impacts
are associated with and exacerbated by an increase in GHGs and climate
change outcomes, which is problematic as these diseases occur at higher
rates within vulnerable communities. Importantly, negative public
health outcomes include those that are physical in nature, as well as
mental, emotional, social, and economic.
To this end, the scientific assessment literature, including the
aforementioned reports, demonstrates that there are myriad ways in
which these populations may be affected at the individual and community
levels. Individuals face differential exposure to criteria pollutants,
in part due to the proximities of highways, trains, factories, and
other major sources of pollutant-emitting sources to less-affluent
residential areas. Outdoor workers, such as construction or utility
crews and agricultural laborers, who frequently are comprised of
already at-risk groups, are exposed to poor air quality and extreme
temperatures without relief. Furthermore, individuals within EJ
populations of concern face greater housing, clean water, and food
insecurity and bear disproportionate economic impacts and health
burdens associated with climate change effects. They have less or
limited access to healthcare and affordable, adequate health or
homeowner insurance. Finally, resiliency and adaptation are more
difficult for economically disadvantaged communities: They have less
liquidity, individually and collectively, to move or to make the types
of infrastructure or policy changes to limit or reduce the hazards they
face. They frequently are less able to self-advocate for resources that
would otherwise aid in building resilience and hazard reduction and
mitigation.
In a 2021 report, Climate Change and Social Vulnerability in the
United States: A Focus on Six Impacts, the EPA considered the degree to
which four socially vulnerable populations--defined based on income,
educational attainment, race and ethnicity, and age--may be more
exposed to the highest impacts of climate change.\817\ The report found
that Blacks and African American populations are approximately 40
percent more likely to currently live in these areas of the U.S.
projected to experience the highest increases in mortality rates due to
changes in temperature. Additionally, Hispanic and Latino individuals
in weather exposed industries were found to be 43 percent more likely
to currently live in areas with the highest projected labor hour losses
due to temperature changes. American Indian and Alaska Native
individuals are projected to be 48 percent more likely to currently
live in areas where the highest percentage of land may be inundated by
sea level rise. Overall, the report confirmed findings of broader
climate science assessments that Americans identifying as people of
color, those with low-income, and those without a high school diploma
face higher differential risks of experiencing the most damaging
impacts of climate change.
---------------------------------------------------------------------------
\817\ U.S. EPA. (2021c) Climate Change and Social Vulnerability
in the United States: A Focus on Six Impacts (EPA-430-R-21-003)
Retrieved from Washington, DC: https://epa.gov/cira/social-vulnerability-report.
---------------------------------------------------------------------------
The assessment literature cited in the EPA's 2009 and 2016
Endangerment and Cause or Contribute Findings, as well as Impacts of
Climate Change on Human Health (2016) and the NCA4 (2018), also
concluded that certain populations and life stages, including children,
are especially sensitive to climate-related health effects. In a more
recent 2023 report, Climate Change Impacts on Children's Health and
Well-Being in the U.S., the EPA considered the degree to which
children's health and well-being may be impacted by five climate-
related environmental hazards--extreme heat, poor air quality, changes
in seasonality, flooding, and different types of infectious
diseases.\818\ The report found that children's academic achievement is
projected to be reduced by 4-7 percent per child, as a result of
moderate and higher levels of warming, impacting future income levels.
The report also projects increases in the numbers of
[[Page 17033]]
annual emergency department visits associated with asthma, and that the
number of new asthma diagnoses increases by 4-11% due to climate-driven
increases in air pollution relative to current levels. In addition,
more than 1 million children in coastal regions are projected to be
temporarily displaced from their homes annually due to climate-driven
flooding, and infectious disease rates are similarly anticipated to
rise, with the number of new Lyme disease cases in children living in
22 states in the eastern and midwestern U.S. increasing by
approximately 3,000-23,000 per year compared to current levels.
Overall, the report confirmed findings of broader climate science
assessments that children are uniquely vulnerable to climate-related
impacts and that in many situations, children in the U.S. who identify
as Black, Indigenous, and People of Color, are limited English-
speaking, do not have health insurance, or live in low-income
communities may be disproportionately exposed to the most severe
impacts of climate change.
---------------------------------------------------------------------------
\818\ U.S. EPA. (2023b). Climate Change and Children's Health
and Wellbeing in the United States. https://www.epa.gov/system/files/documents/2023-04/CLiME_Final%20Report.pdf.
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Native American Tribal communities possess unique vulnerabilities
to climate change, particularly those impacted by degradation of
natural and cultural resources within established reservation
boundaries and threats to traditional subsistence lifestyles. Tribal
communities whose health, economic well-being, and cultural traditions
depend upon the natural environment will likely be affected by the
degradation of ecosystem goods and services associated with climate
change. The IPCC indicates that losses of customs and historical
knowledge may cause communities to be less resilient or adaptable. The
NCA4 noted that while Indigenous peoples are diverse and will be
impacted by the climate changes universal to all Americans, there are
several ways in which climate change uniquely threatens Indigenous
peoples' livelihoods and economies. In addition, there can
institutional barriers to their management of water, land, and other
natural resources that could impede adaptive measures.
For example, Indigenous agriculture in the Southwest is already
being adversely affected by changing patterns of flooding, drought,
dust storms, and rising temperatures leading to increased soil erosion,
irrigation water demand, and decreased crop quality and herd sizes. The
Confederated Tribes of the Umatilla Indian Reservation in the Northwest
have identified climate risks to salmon, elk, deer, roots, and
huckleberry habitat. Housing and sanitary water supply infrastructure
are vulnerable to disruption from extreme precipitation events.
NCA4 noted that Indigenous peoples often have disproportionately
higher rates of asthma, cardiovascular disease, Alzheimer's, diabetes,
and obesity, which can all contribute to increased vulnerability to
climate-driven extreme heat and air pollution events. These factors
also may be exacerbated by stressful situations, such as extreme
weather events, wildfires, and other circumstances.
NCA4 and IPCC Fifth Assessment Report also highlighted several
impacts specific to Alaskan Indigenous Peoples. Coastal erosion and
permafrost thaw will lead to more coastal erosion, exacerbated risks of
winter travel, and damage to buildings, roads, and other
infrastructure--these impacts on archaeological sites, structures, and
objects that will lead to a loss of cultural heritage for Alaska's
Indigenous people. In terms of food security, the NCA4 discussed
reductions in suitable ice conditions for hunting, warmer temperatures
impairing the use of traditional ice cellars for food storage, and
declining shellfish populations due to warming and acidification. While
the NCA also noted that climate change provided more opportunity to
hunt from boats later in the fall season or earlier in the spring, the
assessment found that the net impact was an overall decrease in food
security.
In addition, the U.S. Pacific Islands and the indigenous
communities that live there are also uniquely vulnerable to the effects
of climate change due to their remote location and geographic
isolation. They rely on the land, ocean, and natural resources for
their livelihoods, but face challenges in obtaining energy and food
supplies that need to be shipped in at high costs. As a result, they
face higher energy costs than the rest of the nation and depend on
imported fossil fuels for electricity generation and diesel. These
challenges exacerbate the climate impacts that the Pacific Islands are
experiencing. NCA4 notes that Indigenous peoples of the Pacific are
threatened by rising sea levels, diminishing freshwater availability,
and negative effects to ecosystem services that threaten these
individuals' health and well-being.
K. Congressional Review Act (CRA)
This action is subject to the CRA, and the EPA will submit the rule
report to each House of the Congress and to the Comptroller General of
the United States. This action meets the criteria set forth in 5 U.S.C.
804(2).
List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedures,
Air pollution control, Incorporation by reference, Reporting and
recordkeeping requirements.
Michael S. Regan,
Administrator.
For the reasons stated in the preamble, the Environmental
Protection Agency amends part 60 of title 40, chapter I, of the Code of
Federal Regulations as follows:
PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 4701, et seq.
Subpart A--General Provisions
0
2. Section 60.17 is amended by:
0
a. Revising paragraphs (a), (g) introductory text, (g)(14), and (h)
introductory text;
0
b. Revising paragraphs (h)(19) and (h)(76);
0
c. Redesignating paragraphs(h)(213) through (223) as paragraphs
(h)(218) through (228), paragraphs(h)(210) through (212) as paragraphs
(h)(214) through (216), paragraphs (h)(197) through (209) as paragraphs
(h)(200) through (212), paragraphs(h)(192) through (196) as paragraphs
(h)(194) through (198), and paragraphs (h)(77) through (191) as
paragraphs (h)(78) through (192), respectively;
0
d. Adding new paragraph (h)(77);
0
e. Revising newly redesignated paragraphs (h)(112), (113), (114),
(142), and (h)(173);
0
f. Add new paragraphs (h)(193), (199), (213), and (217);
0
g. Revising newly redesignated paragraph (h)(220) and (j) introductory
text;
0
j. Redesignating paragraphs (j)(2) through (j)(5) as paragraphs (j)(3)
through (j)(6);
0
k. Adding new paragraph (j)(2); and
0
l. Revising the newly redesignated paragraph (j)(4).
The revisions and additions read as follows:
Sec. 60.17 Incorporations by reference.
(a) Certain material is incorporated by reference into this part
with the approval of the Director of the Federal Register under 5
U.S.C. 552(a) and 1 CFR part 51. To enforce any edition other than that
specified in this section, the EPA must publish notice of change in the
Federal Register and the material
[[Page 17034]]
must be available to the public. All approved incorporation by
reference (IBR) material is available for inspection at the EPA and at
the National Archives and Records Administration (NARA). Contact the
EPA at: EPA Docket Center, Public Reading Room, EPA WJC West, Room
3334, 1301 Constitution Ave. NW, Washington, DC, telephone: 202-566-
1744. For information on the availability of this material at NARA,
visit www.archives.gov/federal-register/cfr/ibr-locations.html or email
[email protected]. The material may be obtained from the sources
in the following paragraphs of this section.
* * * * *
(g) American Society of Mechanical Engineers (ASME), Two Park
Avenue, New York, NY 10016-5990; phone: (800) 843-2763; email:
[email protected]; website: www.asme.org.
* * * * *
(14) ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus], Issued August 31, 1981;, IBR approved
for Sec. Sec. 60.56c(b); 60.63(f); 60.106(e); 60.104a(d), (h), (i),
and (j); 60.105a(b), (d), (f), and (g); 60.106a(a); 60.107a(a), (c),
and (d); 60.275(e); 60.275a(e); 60.275b(e); tables 1 and 3 to subpart
EEEE; tables 2 and 4 to subpart FFFF; table 2 to subpart JJJJ;
Sec. Sec. 60.285a(f); 60.396(a); 60.2145(s) and (t); 60.2710(s) and
(t); 60.2730(q); 60.4415(a); 60.4900(b); 60.5220(b); tables 1 and 2 to
subpart LLLL; tables 2 and 3 to subpart MMMM; Sec. Sec. 60.5406(c);
60.5406a(c); 60.5406b(c); 60.5407a(g); 60.5407b(g); 60.5413(b);
60.5413a(b) and (d); 60.5413b(b) and (d); Sec. Sec. 60.5413c(b) and
(d).
* * * * *
(h) ASTM International, 100 Barr Harbor Drive, P.O. Box CB700, West
Conshohocken, Pennsylvania 19428-2959; phone: (800) 262-1373; website:
www.astm.org.
* * * * *
(19) ASTM D86-96, Distillation of Petroleum Products, approved
April 10, 1996; IBR approved for Sec. Sec. 60.562-2(d). 60.593(d).
60.593a(d); 60.633(h); 60.5401(f); 60.5401a(f); 60.5402b(d);
60.5402c(d).
* * * * *
(76) ASTM D1945-03 (Reapproved 2010), Standard Method for Analysis
of Natural Gas by Gas Chromatography, approved January 1, 2010; IBR
approved for Sec. Sec. 60.107a(d); 60.5413(d); 60.5413a(d);
60.5413b(d); 60.5413c(d).
(77) ASTM D1945-14 (Reapproved 2019), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography, approved December 1,
2019; IBR approved for Sec. Sec. 60.5417b(d); 60.5417c(d).
* * * * *
(112) ASTM D2879-83, Test Method for Vapor Pressure-Temperature
Relationship and Initial Decomposition Temperature of Liquids by
Isoteniscope, approved 1983; IBR approved for Sec. Sec. 60.111b(f);
60.116b(e) and (f); 60.485(e); 60.485a(e); 60.5403b(d); 60.5406c(d).
(113) ASTM D2879-96, Test Method for Vapor Pressure-Temperature
Relationship and Initial Decomposition Temperature of Liquids by
Isoteniscope, approved 1996; IBR approved for Sec. Sec. 60.111b(f);
60.116b(e) and (f); 60.485(e); 60.485a(e); 60.5403b(d); 60.5406c(d).
(114) ASTM D2879-97, Test Method for Vapor Pressure-Temperature
Relationship and Initial Decomposition Temperature of Liquids by
Isoteniscope, approved 1997; IBR approved for Sec. Sec. 60.111b(f);
60.116b(e) and (f); 60.485(e); 60.485a(e); 60.5403b(d); 60.5406c(d).
* * * * *
(142) ASTM D3588-98 (Reapproved 2003), Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels, approved May 10, 2003; IBR approved for Sec. Sec.
60.107a(d); 60.5413(d); 60.5413a(d); 60.5413b(d); 60.5413c(d).
* * * * *
(173) ASTM D4891-89 (Reapproved 2006), Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion, approved June 1, 2006; IBR approved for Sec. Sec.
60.107a(d); 60.5413(d); 60.5413a(d); 60.5413b(d); 60.5413c(d).
* * * * *
(193) ASTM D6348-12e1, Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy, approved February 1, 2012; IBR approved
for Sec. 60.5413c(b).
* * * * *
(199) ASTM D6522-20, Standard Test Method for Determination of
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in
Emissions from Natural Gas-Fired Reciprocating Engines, Combustion
Turbines, Boilers, and Process Heaters Using Portable Analyzers,
approved June 1, 2020; IBR approved for Sec. Sec. 60.5413b(b);
60.5413c(b).
* * * * *
(213) ASTM E168-16, (Reapproved 2023), Standard Practices for
General Techniques of Infrared Quantitative Analysis, approved January
1, 2023; IBR approved for Sec. Sec. 60.5400b(a); 60.5400c(a);
60.5401b(a); 60.5401c(a).
* * * * *
(217) ASTM E169-16 (Reapproved 2022), Standard Practices for
General Techniques of Ultraviolet-Visible Quantitative Analysis,
approved November 1, 2022; IBR approved for Sec. Sec. 60.5400b(a);
60.5400c; 60.5401b(a); 60.5401c(a).
* * * * *
(220) ASTM E260-96, General Gas Chromatography Procedures, approved
April 10, 1996; IBR approved for Sec. Sec. 60.485a(d), 60.593(b),
60.593a(b), 60.632(f), 60.5400(f), 60.5400a(f), 60.5406(b),
60.5406a(b)(3), 60.5400b(a)(2), 60.5401b(a)(2), 60.5406b(b)(3),
60.5400c(a), and 60.5401c(a).
(j) U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue
NW, Washington, DC 20460; phone: (202) 272-0167; website: www.epa.gov.
* * * * *
(2) EPA-454/B-08-002, Quality Assurance Handbook for Air Pollution
Measurement Systems; Volume IV: Meteorological Measurements, Version
2.0 (Final), March 2008; IBR approved for Appendix K to this part.
* * * * *
(4) EPA-600/R-12/531, EPA Traceability Protocol for Assay and
Certification of Gaseous Calibration Standards, Issued May 2012; IBR
approved for Sec. Sec. 60.5413(d); 60.5413a(d); 60.5413b(d);
60.5413c(d).
* * * * *
Subpart KKK--Standards of Performance for Equipment Leaks of VOC
From Onshore Natural Gas Processing Plants for Which Construction,
Reconstruction, or Modification Commenced After January 20, 1984,
and on or Before August 23, 2011
0
3. Section 60.630 is amended by adding paragraph (f) to read as
follows:
Sec. 60.630 Applicability and designation of affected facility.
* * * * *
(f) An affected facility must continue to comply with the
requirements of this subpart until it begins complying with a more
stringent requirement, that applies to the same affected facility, in
an approved, and effective, State or Federal plan that implements
subpart OOOOc of this part, or modifies or reconstructs after December
6, 2022, and thus becomes subject to subpart OOOOb of this part.
[[Page 17035]]
Subpart OOOO--Standards of Performance for Crude Oil and Natural
Gas Facilities for Which Construction, Modification, or
Reconstruction Commenced After August 23, 2011, and on or Before
September 18, 2015
0
4. Section 60.5360 is revised to read as follows:
Sec. 60.5360 What is the purpose of this subpart?
This subpart establishes emission standards and compliance
schedules for the control of volatile organic compounds (VOC) and
sulfur dioxide (SO2) emissions from affected facilities that
commence construction, modification, or reconstruction after August 23,
2011, and on or before September 18, 2015.
0
5. Amend Sec. 60.5365 by:
0
a. Revising the introductory text, and paragraphs (b), (c), and (d)(1);
0
b. Adding paragraph (d)(2); and
0
c. Revising the introductory text of paragraph (e).
The revisions and addition read as follows:
Sec. 60.5365 Am I subject to this subpart?
You are subject to the applicable provisions of this subpart if you
are the owner or operator of one or more of the onshore affected
facilities listed in paragraphs (a) through (g) of this section for
which you commence construction, modification, or reconstruction after
August 23, 2011, and on or before September 18, 2015. An affected
facility must continue to comply with the requirements of this subpart
until it begins complying with a more stringent requirement, that
applies to the same affected facility, in an approved, and effective,
state or Federal plan that implements subpart OOOOc of this part, or
modifies or reconstructs after December 6, 2022, and thus becomes
subject to subpart OOOOb of this part.
* * * * *
(b) Each centrifugal compressor affected facility, which is a
single centrifugal compressor using wet seals that is located between
the wellhead and the point of custody transfer to the natural gas
transmission and storage segment. A centrifugal compressor located at a
well site, or an adjacent well site and servicing more than one well
site, is not an affected facility under this subpart.
(c) Each reciprocating compressor affected facility, which is a
single reciprocating compressor located between the wellhead and the
point of custody transfer to the natural gas transmission and storage
segment. A reciprocating compressor located at a well site, or an
adjacent well site and servicing more than one well site, is not an
affected facility under this subpart.
(d)(1) For the oil production segment (between the wellhead and the
point of custody transfer to an oil pipeline), each pneumatic
controller affected facility, which is a single continuous bleed
natural gas-driven pneumatic controller operating at a natural gas
bleed rate greater than 6 standard cubic feet per hour.
(2) For the natural gas production segment (between the wellhead
and the point of custody transfer to the natural gas transmission and
storage segment and not including natural gas processing plants), each
pneumatic controller affected facility, which is a single continuous
bleed natural gas-driven pneumatic controller operating at a natural
gas bleed rate greater than 6 standard cubic feet per hour.
* * * * *
(e) Each storage vessel affected facility, which is a single
storage vessel located in the oil and natural gas production segment,
natural gas processing segment or natural gas transmission and storage
segment, and has the potential for VOC emissions equal to or greater
than 6 tons per year (tpy) as determined according to this section by
October 15, 2013, for Group 1 storage vessels and by April 15, 2014, or
30 days after startup (whichever is later) for Group 2 storage vessels,
except as provided in paragraphs (e)(1) through (4) of this section.
The potential for VOC emissions must be calculated using a generally
accepted model or calculation methodology, based on the maximum average
daily throughput determined for a 30-day period of production prior to
the applicable emission determination deadline specified in this
section. The determination may take into account requirements under a
legally and practically enforceable limit in an operating permit or
other requirement established under a Federal, State, local or Tribal
authority.
* * * * *
0
6. Add Sec. 60.5371 to read as follows:
Sec. 60.5371 What standards apply to super-emitter events?
This section applies to super-emitter events. For purposes of this
section, a super-emitter event is defined as any emissions event that
is located at an individual well site or compressor station and that is
detected using remote detection methods and has a quantified emission
rate of 100 kg/hr of methane or greater. Upon receiving a notification
of a super emitter event issued by the EPA under Sec. 60.5371b(c),
owners or operators must take the actions listed in paragraphs (a) and
(b) of this section. Within 5 calendar days of receiving a notification
from the EPA of a super-emitter event, the owner or operator of an oil
and natural gas facility (e.g., a well site, centralized production
facility, natural gas processing plant, or compressor station) must
initiate a super-emitter event investigation.
(a) Identification of super-emitter events. (1) If you do not own
or operate an oil and natural gas facility within 50 meters from the
latitude and longitude provided in the notification subject to the
regulation under this subpart, report this result to the EPA under
paragraph (e) of this section. Your super-emitter event investigation
is deemed complete under this subpart.
(2) If you own or operate an oil and natural gas facility within 50
meters from the latitude and longitude provided in the notification
subject to regulation under this subpart, you must investigate to
determine the source of super-emitter event. The investigation may
include but is not limited to the actions specified below in paragraphs
(a)(2)(i) through (iii) of this section.
(i) Review any maintenance activities or process activities from
the affected facilities subject to regulation under this subpart,
starting from the date of detection of the super-emitter event as
identified in the notification, until the date of investigation, to
determine if the activities indicate any potential source(s) of the
super-emitter event emissions.
(ii) Review all monitoring data from control devices (e.g., flares)
from the affected facilities subject to regulation under this subpart
from the initial date of detection of the super-emitter event as
identified in the notification, until the date of receiving the
notification from the EPA to identify malfunctions of control devices
or periods when the control devices were not in compliance with
applicable requirements and that indicate a potential source of the
super-emitter event emissions.
(iii) Screen the entire well site or compressor station with OGI,
or Method 21 of appendix A-7 to this part, or an alternative test
method(s) approved per Sec. 60.5398b(d), to determine if a super-
emitter event is present.
(b) Super-emitter event report. For equipment subject to regulation
under this subpart, you must submit the results of the super-emitter
event investigation conducted under paragraph (a) of this section to
the EPA in accordance with paragraph (b)(1) of this section. If the
super-emitter event (i.e., emission at 100 kg/hr of methane or more) is
ongoing at the time of the
[[Page 17036]]
initial report, submit the additional information in accordance with
paragraph (b)(2) of this section. You must attest to the information
included in the report as specified in paragraph (b)(3) of this
section.
(1) Within 15 days of receiving a notification from the EPA under
Sec. 60.5371b(c), you must submit a report of the super-emitter event
investigation conducted under paragraph (a) of this section through the
Super-Emitter Program Portal. You must include the applicable
information in paragraphs (b)(1)(i) through (viii) of this section in
the report. If you have identified a demonstrable error in the
notification, the report may include a statement of the demonstrable
error.
(i) Notification Report ID of the super-emitter event notification.
(ii) Identification of whether you are the owner or operator of an
oil and natural gas facility within 50 meters from the latitude and
longitude provided in the EPA notification. If you do not own or
operate an oil and natural gas facility within 50 meters from the
latitude and longitude provided in the EPA notification, you are not
required to report the information in paragraphs (b)(1)(iii) through
(viii) of this section.
(iii) General identification information for the facility,
including, facility name, the physical address, applicable ID Number
(e.g., EPA ID Number, API Well ID Number), the owner or operator or
responsible official (where applicable) and their email address.
(iv) Identification of whether there is an affected facility or
associated equipment subject to regulation under this subpart at a well
site or compressor station you own or operate within 50 meters from the
latitude and longitude provided in the EPA notification.
(v) Indication of whether you were able to identify the source of
the super-emitter event. If you indicate you were unable to identify
the source of the super-emitter event, you must certify that all
applicable investigations specified in paragraphs (d)(6)(i) through (v)
of this section have been conducted for all affected facilities and
associated equipment subject to this subpart that are at this oil and
natural gas facility, and you have determined that the affected
facilities and associated equipment are not the source of the super-
emitter event. If you indicate that you were not able to identify the
source of the super-emitter event, you are not required to report the
information in paragraphs (b)(1)(vi) through (viii) of this section.
(vi) The source(s) of the super-emitter event.
(vii) Identification of whether the source of the super-emitter
event is an affected facility or associated equipment subject to
regulation under of this subpart. If the source of the super-emitter
event is equipment subject to regulation under this subpart, identify
the applicable regulation(s) under this subpart.
(viii) Indication of whether the super-emitter event is ongoing at
the time of the initial report submittal (i.e., emission at 100 kg/hr
of methane or more).
(A) If the super-emitter event is not ongoing at the time of the
initial report submittal, provide the estimated date and time the
super-emitter event ended.
(B) If the super-emitter event is ongoing at the time of the
initial report submittal, provide a short narrative of your plan to end
the super-emitter event, including the targeted end date for the
efforts to be completed and the super-emitter event ended.
(2) If the super-emitter event is ongoing at the time of the
initial report submittal, within 5 business days of the date the super-
emitter event ends, you must update your initial report through the
Super-Emitter Program Portal (available at http://www.epa.gov/super-emitter) to provide the end date and time of the super-emitter event.
(3) You must sign the following attestation must be signed by the
owner or operator into when submitting data into the Super-Emitter
Program Portal: ``I certify that the information provided in this
report regarding the specified super-emitter event was prepared under
my direction or supervision. I further certify that the investigations
were conducted, and this report was prepared pursuant to the
requirements of Sec. 60.5371(a) and (b). Based on my professional
knowledge and experience, and inquiry of personnel involved in the
assessment, the certification submitted herein is true, accurate, and
complete. I am aware that knowingly false statements may be punishable
by fine or imprisonment.''
0
7. Amend Sec. 60.5420 by revising paragraph (c)(5)(iv) to read as
follows:
Sec. 60.5420 What are my notification, reporting, and recordkeeping
requirements?
* * * * *
(c) * * *
(5) * * *
(iv) For storage vessels that are skid-mounted or permanently
attached to something that is mobile (such as trucks, railcars, barges,
or ships), records indicating the number of consecutive days that the
vessel is located at a site in the oil and natural gas production
segment, natural gas processing segment or natural gas transmission and
storage segment. If a storage vessel is removed from a site and, within
30 days, is either returned to or replaced by another storage vessel at
the site to serve the same or similar function, then the entire period
since the original storage vessel was first located at the site,
including the days when the storage vessel was removed, will be added
to the count towards the number of consecutive days.
* * * * *
0
8. Amend Sec. 60.5430 by:
0
a. Removing the definition for ``Crude Oil and Natural Gas Production
source category'';
0
b. Revising the definition for ``Custody transfer''; and
0
c. Removing the definition for ``Local distribution company (LDC)
custody transfer station'' and ``Natural gas transmission and storage
segment''.
The revision reads as follows:
Sec. 60.5430 What definitions apply to this subpart?
* * * * *
Custody transfer means the transfer of natural gas after processing
and/or treatment in the producing operations, or from storage vessels
or automatic transfer facilities or other such equipment, including
product loading racks, to pipelines or any other forms of
transportation.
* * * * *
Subpart OOOOa--Standards of Performance for Crude Oil and Natural
Gas Facilities for Which Construction, Modification or
Reconstruction Commenced After September 18, 2015 and On or Before
December 6, 2022
0
9. Revise the subpart heading of subpart OOOOa to read as set forth
above.
0
10. Revise Sec. 60.5360a to read as follows:
Sec. 60.5360a What is the purpose of this subpart?
(a) Scope. This subpart establishes emission standards and
compliance schedules for the control of the pollutant greenhouse gases
(GHG). The greenhouse gas standard in this subpart is in the form of a
limitation on emissions of methane from affected facilities in the
crude oil and natural gas source category that commence construction,
modification, or reconstruction after September 18, 2015. This subpart
also establishes emission standards and compliance schedules for the
control of volatile organic compounds (VOC) and sulfur dioxide
[[Page 17037]]
(SO2) emissions from affected facilities in the crude oil
and natural gas source category that commence construction,
modification, or reconstruction after September 18, 2015, and on or
before December 6, 2022.
(b) Prevention of Significant Deterioration (PSD) and title V
thresholds for Greenhouse Gases. (1) For the purposes of 40 CFR
51.166(b)(49)(ii), with respect to GHG emissions from affected
facilities, the ``pollutant that is subject to the standard promulgated
under section 111 of the Act'' shall be considered to be the pollutant
that otherwise is subject to regulation under the Act as defined in 40
CFR 51.166(b)(48) and in any State Implementation Plan (SIP) approved
by the EPA that is interpreted to incorporate, or specifically
incorporates, 40 CFR 51.166(b)(48).
(2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to
GHG emissions from affected facilities, the ``pollutant that is subject
to the standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is subject to regulation
under the Clean Air Act as defined in 40 CFR 52.21(b)(49).
(3) For the purposes of 40 CFR 70.2, with respect to greenhouse gas
emissions from affected facilities, the ``pollutant that is subject to
any standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in 40 CFR 70.2.
(4) For the purposes of 40 CFR 71.2, with respect to greenhouse gas
emissions from affected facilities, the ``pollutant that is subject to
any standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in 40 CFR 71.2.
0
11. Amend Sec. 60.5365a by revising the introductory text and
paragraph (a)(4) to read as follows:
Sec. 60.5365a Am I subject to this subpart?
You are subject to the applicable provisions of this subpart if you
are the owner or operator of one or more of the onshore affected
facilities listed in paragraphs (a) through (j) of this section, that
is located within the Crude Oil and Natural Gas source category, as
defined in Sec. 60.5430a, for which you commence construction,
modification, or reconstruction after September 18, 2015, and on or
before December 6, 2022. Facilities located inside and including the
Local Distribution Company (LDC) custody transfer station are not
subject to this subpart. An affected facility must continue to comply
with the requirements of this subpart until it begins complying with a
more stringent requirement, that applies to the same affected facility,
in an approved, and effective, state or Federal plan that implements
subpart OOOOc of this part, or modifies or reconstructs after December
6, 2022, and thus becomes subject to subpart OOOOb of this part.
(a) * * *
(4) A well initially constructed after September 18, 2015, and on
or before December 6, 2022, that conducts a well completion operation
following hydraulic refracturing is considered an affected facility
regardless of this provision.
* * * * *
0
12. Add Sec. 60.5371a to read as follows:
Sec. 60.5371a What standards apply to super-emitter events?
This section applies to super-emitter events. For purposes of this
section, a super-emitter event is defined as any emissions event that
is located at or near an oil and gas facility (e.g., individual well
site, natural gas processing plant or compressor station) and that is
detected using remote detection methods and has a quantified emission
rate of 100 kg/hr of methane or greater. Upon receiving a notification
of a super emitter event issued by the EPA under Sec. 60.5371b(c) in
subpart OOOOb of this part, owners or operators must take the actions
listed in paragraphs (a) and (b) of this section. Within 5 calendar
days of receiving a notification from the EPA of a super-emitter event,
the owner or operator of an oil and natural gas facility (e.g., a well
site, centralized production facility, natural gas processing plant, or
compressor station) must initiate a super-emitter event investigation.
(a) Identification of super-emitter events. (1) If you do not own
or operate an oil and natural gas facility within 50 meters from the
latitude and longitude provided in the notification subject to the
regulation under this subpart, report this result to the EPA under
paragraph (e) of this section. Your super-emitter event investigation
is deemed complete under this subpart.
(2) If you own or operate an oil and natural gas facility within 50
meters from the latitude and longitude provided in the notification,
and there is an affected facility or associated equipment subject to
this subpart onsite, you must investigate to determine the source of
the super-emitter event in accordance with paragraph (a)(2) of this
section, maintain records of your investigation, and report the results
in accordance with paragraph (b) of this section.
(3) The investigation required by paragraph (a)(2) of this section
may include but is not limited to the actions specified below in
paragraphs (a)(3)(i) through (iv) of this section.
(i) Review any maintenance activities or process activities from
the affected facilities subject to regulation under this subpart,
starting from the date of detection of the super-emitter event as
identified in the notification, until the date of investigation, to
determine if the activities indicate any potential source(s) of the
super-emitter event emissions.
(ii) Review all monitoring data from control devices (e.g., flares)
from the affected facilities subject to regulation under this subpart
from the initial date of detection of the super-emitter event as
identified in the notification, until the date of receiving the
notification from the EPA to identify malfunctions of control devices
or periods when the control devices were not in compliance with
applicable requirements and that indicate a potential source of the
super-emitter event emissions.
(iii) If you conducted a fugitive emissions survey in accordance
with Sec. 60.5397a between the initial date of detection of the super-
emitter event as identified in the notification and the date the
notification from the EPA was received, review the results of the
survey to identify any potential source(s) of the super-emitter event
emissions.
(iv) Screen the entire facility with OGI, Method 21 of appendix A-7
to this part, or an alternative test method(s) approved per Sec.
60.5398b(d) of subpart OOOOb of this part, to determine if a super-
emitter event is present.
(b) Super-emitter event report. You must submit the results of the
super-emitter event investigation conducted under paragraph (a) of this
section to the EPA in accordance with paragraph (b)(1) of this section.
If the super-emitter event (i.e., emission at 100 kg/hr of methane or
more) is ongoing at the time of this initial report, submit the
additional information in accordance with paragraph (b)(2) of this
section. You must attest to the information included in the report as
specified in paragraph (b)(3) of this section.
(1) Within 15 days of receiving a notification from the EPA under
Sec. 60.5371b(c), you must submit a report of the super-emitter event
investigation conducted under paragraph (a) of this section through the
Super-Emitter Program Portal, at www.epa.gov/super-emitter. You must
include the applicable information in paragraphs (b)(1)(i) through
(viii) of this section in the report. If you have identified a
demonstrable error in the notification,
[[Page 17038]]
the report may include a statement of the demonstrable error.
(i) Notification Report ID of the super-emitter event notification
(which is provided in the EPA notification).
(ii) Identification of whether you are the owner or operator of an
oil and natural gas facility within 50 meters from the latitude and
longitude provided in the EPA notification. If you do not own or
operate an oil and natural gas facility within 50 meters from the
latitude and longitude provided in the EPA notification, you are not
required to report the information in paragraphs (b)(1)(iii) through
(viii) of this section.
(iii) General identification information for the facility,
including facility name, the physical address, applicable ID Number
(e.g., EPA ID Number, API Well ID Number), the owner or operator or
responsible official (where applicable), and their email address.
(iv) Identification of whether there is an affected facility or
associated equipment subject to regulation under this subpart at this
oil and natural gas facility.
(v) Indication of whether you were able to identify the source of
the super-emitter event. If you indicate you were unable to identify
the source of the super-emitter event, you must certify that all
applicable investigations specified in paragraphs (a)(2)(i) through
(iv) of this section have been conducted for all affected facilities
and associated equipment subject to regulation under this subpart that
are at this oil and natural gas facility, and you have determined that
these affected facilities and associated equipment are not the source
of the super-emitter event. If you indicate that you were not able to
identify the source of the super-emitter event, you are not required to
report the information in paragraphs (b)(1)(vi) through (viii) of this
section.
(vi) The source(s) of the super-emitter event.
(vii) Identification of whether the source of the super-emitter
event is an affected facility or associated equipment subject to
regulation under of this subpart. If the source of the super-emitter
event is an affected facility or associated equipment subject to
regulation under this subpart, identify the applicable regulation(s)
under this subpart.
(viii) Indication of whether the super-emitter event is ongoing at
the time of the initial report submittal (i.e., emissions at 100 kg/hr
of methane or more).
(A) If the super-emitter event is not ongoing at the time of the
initial report submittal, provide the actual (or if not known,
estimated) date and time the super-emitter event ended.
(B) If the super-emitter event is ongoing at the time of the
initial report submittal, provide a short narrative of your plan to end
the super-emitter event, including the targeted end date for the
efforts to be completed and the super-emitter event ended.
(2) If the super-emitter event is ongoing at the time of the
initial report submittal, within 5 business days of the date the super-
emitter event ends you must update your initial report through the
Super-Emitter Program Portal, to provide the end date and time of the
super-emitter event.
(3) You must sign the following attestation when submitting data
into the Super-Emitter Program Portal: ``I certify that the information
provided in this report regarding the specified super-emitter event was
prepared under my direction or supervision. I further certify that the
investigations were conducted, and this report was prepared pursuant to
the requirements of Sec. 60.5371a(a) and (b). Based on my professional
knowledge and experience, and inquiry of personnel involved in the
assessment, the certification submitted herein is true, accurate, and
complete. I am aware that knowingly false statements may be punishable
by fine or imprisonment.''
0
13. Amend Sec. 60.5375a by revising the section heading and the
introductory text to read as follows:
Sec. 60.5375a What GHG and VOC standards apply to well affected
facilities?
If you are the owner or operator of a well affected facility as
described in Sec. 60.5365a(a) that also meets the criteria for a well
affected facility in Sec. 60.5365(a) (in subpart OOOO of this part),
you must reduce GHG (in the form of a limitation on emissions of
methane) and VOC emissions by complying with paragraphs (a) through (g)
of this section. If you own or operate a well affected facility as
described in Sec. 60.5365a(a) that does not meet the criteria for a
well affected facility in Sec. 60.5365(a) (in subpart OOOO of this
part), you must reduce GHG and VOC emissions by complying with
paragraphs (f)(3) and (4) or paragraph (g) of this section for each
well completion operation with hydraulic fracturing prior to November
30, 2016, and you must comply with paragraphs (a) through (g) of this
section for each well completion operation with hydraulic fracturing on
or after November 30, 2016.
* * * * *
0
14. Amend Sec. 60.5380a by revising the section heading, introductory
text, and paragraph (a)(1) to read as follows:
Sec. 60.5380a What GHG and VOC standards apply to centrifugal
compressor affected facilities?
You must comply with the GHG and VOC standards in paragraphs (a)
through (d) of this section for each centrifugal compressor affected
facility.
(a)(1) You must reduce methane and VOC emissions from each
centrifugal compressor wet seal fluid degassing system by 95.0 percent.
* * * * *
0
15. Amend Sec. 60.5385a by revising the section heading, introductory
text, and paragraph (a)(3) to read as follows:
Sec. 60.5385a What GHG and VOC standards apply to reciprocating
compressor affected facilities?
You must reduce GHG (in the form of a limitation on emissions of
methane) and VOC emissions by complying with the standards in
paragraphs (a) through (d) of this section for each reciprocating
compressor affected facility.
(a) * * *
(3) Collect the methane and VOC emissions from the rod packing
using a rod packing emissions collection system that operates under
negative pressure and route the rod packing emissions to a process
through a closed vent system that meets the requirements of Sec.
60.5411a(a) and (d).
* * * * *
0
16. Amend Sec. 60.5390a by revising the section heading and
introductory text to read as follows:
Sec. 60.5390a What GHG and VOC standards apply to pneumatic
controller affected facilities?
For each pneumatic controller affected facility you must comply
with the GHG and VOC standards, based on natural gas as a surrogate for
GHG and VOC, in either paragraph (b)(1) or (c)(1) of this section, as
applicable. Pneumatic controllers meeting the conditions in paragraph
(a) of this section are exempt from the requirements in paragraph
(b)(1) or (c)(1) of this section.
* * * * *
0
17. Amend Sec. 60.5393a by revising the section heading and
introductory text to read as follows:
Sec. 60.5393a What GHG and VOC standards apply to pneumatic pump
affected facilities?
For each pneumatic pump affected facility you must comply with the
GHG and VOC standards, based on natural gas as a surrogate for GHG and
VOC, in either paragraph (a) or (b) of this
[[Page 17039]]
section, as applicable, on or after November 30, 2016.
* * * * *
0
18. Amend Sec. 60.5397a by:
0
a. Revising the section heading, introductory text, and paragraph (a);
0
b. Revising the introductory text of paragraph (g) and paragraph
(g)(2);
0
c. Adding paragraph (g)(6); and
0
d. Revising paragraph (h)(3).
The revisions and addition read as follows:
Sec. 60.5397a What fugitive emissions GHG and VOC standards apply to
the affected facility which is the collection of fugitive emissions
components at a well site and the affected facility which is the
collection of fugitive emissions components at a compressor station?
For each affected facility under Sec. 60.5365a(i) and (j), you
must reduce GHG (in the form of a limitation on emissions of methane)
and VOC emissions by complying with the requirements of paragraphs (a)
through (j) of this section. The requirements in this section are
independent of the closed vent system and cover requirements in Sec.
60.5411a. Alternatively, you may comply with the requirements of Sec.
60.5398b, including the notification, recordkeeping, and reporting
requirements outlined in Sec. 60.5424b. For the purpose of this
subpart, compliance with the requirements in Sec. 60.5398b will be
deemed compliance with this section. When complying with Sec.
60.5398b, the definitions in Sec. 60.5430b shall apply for those
activities conducted under Sec. 60.5398b.
(a) You must monitor all fugitive emission components, as defined
in Sec. 60.5430a, in accordance with paragraphs (b) through (g) of
this section. You must repair all sources of fugitive emissions in
accordance with paragraph (h) of this section. You must keep records in
accordance with paragraph (i) of this section and report in accordance
with paragraph (j) of this section. For purposes of this section,
fugitive emissions are defined as any visible emission from a fugitive
emissions component observed using optical gas imaging or an instrument
reading of 500 parts per million (ppm) or greater using Method 21 of
appendix A-7 to this part.
* * * * *
(g) A monitoring survey of each collection of fugitive emissions
components at a well site or at a compressor station must be performed
at the frequencies specified in paragraphs (g)(1) and (2) of this
section, with the exceptions noted in paragraphs (g)(3) through (6) of
this section.
* * * * *
(2) Except as provided in this paragraph (g)(2), a monitoring
survey of the collection of fugitive emissions components at a
compressor station must be conducted at least quarterly after the
initial survey. Consecutive quarterly monitoring surveys must be
conducted at least 60 days apart. A monitoring survey of the collection
of fugitive emissions components at a compressor station located on the
Alaskan North Slope must be conducted at least annually. Consecutive
annual monitoring surveys must be conducted at least 9 months apart and
no more than 13 months apart.
* * * * *
(6) The requirements of paragraph (g)(2) of this section are waived
for any collection of fugitive emissions components at a compressor
station located within an area that has an average calendar month
temperature below 0 [deg]F for two of three consecutive calendar months
of a quarterly monitoring period. The calendar month temperature
average for each month within the quarterly monitoring period must be
determined using historical monthly average temperatures over the
previous three years as reported by a National Oceanic and Atmospheric
Administration source or other source approved by the Administrator.
The requirements of paragraph (g)(2) of this section shall not be
waived for two consecutive quarterly monitoring periods.
(h) * * *
(3) Delay of repair will be allowed if the conditions in paragraphs
(h)(3)(i) or (ii) of this section are met.
(i) If the repair is technically infeasible, would require a vent
blowdown, a compressor station shutdown, a well shutdown or well shut-
in, or would be unsafe to repair during operation of the unit, the
repair must be completed during the next scheduled compressor station
shutdown for maintenance, scheduled well shutdown, scheduled well shut-
in, after a scheduled vent blowdown, or within 2 years of detecting the
fugitive emissions, whichever is earliest. For purposes of this
paragraph (h)(3), a vent blowdown is the opening of one or more
blowdown valves to depressurize major production and processing
equipment, other than a storage vessel.
(ii) If the repair requires replacement of a fugitive emissions
component or a part thereof, but the replacement cannot be acquired and
installed within the repair timelines specified in paragraphs (h)(1)
and (2) of this section due to either of the conditions specified in
paragraphs (h)(3)(ii)(A) or (B) of this section, the repair must be
completed in accordance with paragraph (h)(3)(ii)(C) of this section
and documented in accordance with Sec. 60.5420a(c)(15)(vii)(I).
(A) Valve assembly supplies had been sufficiently stocked but are
depleted at the time of the required repair.
(B) A replacement fugitive emissions component or a part thereof
requires custom fabrication.
(C) The required replacement must be ordered no later than 10
calendar days after the first attempt at repair. The repair must be
completed as soon as practicable, but no later than 30 calendar days
after receipt of the replacement component, unless the repair requires
a compressor station or well shutdown. If the repair requires a
compressor station or well shutdown, the repair must be completed in
accordance with the timeframe specified in paragraph (h)(3)(i) of this
section.
* * * * *
0
19. Amend Sec. 60.5398a by revising the section heading and paragraph
(a) to read as follows:
Sec. 60.5398a What are the alternative means of emission limitations
for GHG and VOC from well completions, reciprocating compressors, the
collection of fugitive emissions components at a well site and the
collection of fugitive emissions components at a compressor station?
(a) If, in the Administrator's judgment, an alternative means of
emission limitation will achieve a reduction in GHG (in the form of a
limitation on emissions of methane) and VOC emissions at least
equivalent to the reduction in GHG and VOC emissions achieved under
Sec. 60.5375a, Sec. 60.5385a, or Sec. 60.5397a, the Administrator
will publish, in the Federal Register, a document permitting the use of
that alternative means for the purpose of compliance with Sec.
60.5375a, Sec. 60.5385a, or Sec. 60.5397a. The authority to approve
an alternative means of emission limitation is retained by the
Administrator and shall not be delegated to States under section 111(c)
of the Clean Air Act (CAA).
* * * * *
0
20. Amend Sec. 60.5399a by revising paragraphs (a), (f), (i), and (m)
to read as follows:
[[Page 17040]]
Sec. 60.5399a What alternative fugitive emissions standards apply to
the affected facility which is the collection of fugitive emissions
components at a well site and the affected facility which is the
collection of fugitive emissions components at a compressor station:
Equivalency with state, local, and Tribal programs?
* * * * *
(a) Alternative fugitive emissions standards. If, in the
Administrator's judgment, an alternative fugitive emissions standard
will achieve a reduction in methane and VOC emissions at least
equivalent to the reductions achieved under Sec. 60.5397a, the
Administrator will publish, in the Federal Register, a notice
permitting use of the alternative fugitive emissions standard for the
purpose of compliance with Sec. 60.5397a. The authority to approve
alternative fugitive emissions standards is retained by the
Administrator and shall not be delegated to States under section 111(c)
of the CAA.
* * * * *
(f) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a well site or a compressor
station in the State of California. An affected facility, which is the
collection of fugitive emissions components, as defined in Sec.
60.5430a, located at a well site or a compressor station in the State
of California may elect to comply with the monitoring, repair, and
recordkeeping requirements in the California Code of Regulations, title
17, sections 95665-95667, effective January 1, 2020, as an alternative
to complying with the requirements in Sec. 60.5397a(f)(1) and (2),
(g)(1) through (4), (h), and (i). The information specified in Sec.
60.5420a(b)(7)(iii)(A) and the information specified in either Sec.
60.5420a(b)(7)(iii)(B) or (C) may be provided as an alternative to the
requirements in Sec. 60.5397a(j).
* * * * *
(i) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a compressor station in the
State of Ohio. An affected facility, which is the collection of
fugitive emissions components, as defined in Sec. 60.5430a, located at
a compressor station in the State of Ohio may elect to comply with the
monitoring, repair, and recordkeeping requirements in Ohio General
Permit 18.1, effective February 7, 2017, as an alternative to complying
with the requirements in Sec. 60.5397a(f)(2), (g)(2) through (4), (h),
and (i), provided the monitoring instrument used is optical gas imaging
or a Method 21 instrument (see appendix A-7 to this part) with a leak
definition and reading of 500 ppm or greater. Monitoring must be
conducted on at least a quarterly basis and skip periods cannot be
applied. The information specified in Sec. 60.5420a(b)(7)(iii)(A) and
the information specified in either Sec. 60.5420a(b)(7)(iii)(B) or (C)
may be provided as an alternative to the requirements in Sec.
60.5397a(j).
* * * * *
(m) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a compressor station in the
State of Texas. An affected facility, which is the collection of
fugitive emissions components, as defined in Sec. 60.5430a, located at
a compressor in the State of Texas may elect to comply with the
monitoring, repair, and recordkeeping requirements in the Air Quality
Standard Permit for Oil and Gas Handling and Production Facilities,
section I(6), effective November 8, 2012, or at 30 Texas Administrative
Code section 116.620, effective September 4, 2000, as an alternative to
complying with the requirements in Sec. 60.5397a(f)(2), (g)(2) through
(4), (h), and (i), provided the monitoring instrument used is optical
gas imaging or a Method 21 instrument (see appendix A-7 to this part)
with a leak definition and reading of 500 ppm or greater. Monitoring
must be conducted on at least a quarterly basis and skip periods may
not be applied. If using the alternative in this paragraph (m), the
information specified in Sec. 60.5420a(b)(7)(iii)(A) and (C) must be
provided in lieu of the requirements in Sec. 60.5397a(j).
* * * * *
0
21. Amend Sec. 60.5400a by revising the section heading and paragraph
(c) to read as follows:
Sec. 60.5400a What equipment leak GHG and VOC standards apply to
affected facilities at an onshore natural gas processing plant?
* * * * *
(c) You may apply to the Administrator for permission to use an
alternative means of emission limitation that achieves a reduction in
emissions of methane and VOC at least equivalent to that achieved by
the controls required in this subpart according to the requirements of
Sec. 60.5402a.
* * * * *
Sec. 60.5401a What are the exceptions to the equipment leak GHG and
VOC standards for affected facilities at onshore natural gas processing
plants?
0
22. Amend Sec. 60.5401a by revising the section heading to read as set
forth above.
0
23. Amend Sec. 60.5402a by revising the section heading, paragraph
(a), and paragraph (d)(2) introductory text to read as follows:
Sec. 60.5402a What are the alternative means of emission limitations
for GHG and VOC equipment leaks from onshore natural gas processing
plants?
(a) If, in the Administrator's judgment, an alternative means of
emission limitation will achieve a reduction in GHG and VOC emissions
at least equivalent to the reduction in GHG and VOC emissions achieved
under any design, equipment, work practice or operational standard, the
Administrator will publish, in the Federal Register, a document
permitting the use of that alternative means for the purpose of
compliance with that standard. The document may condition permission on
requirements related to the operation and maintenance of the
alternative means.
* * * * *
(d) * * *
(2) The application must include operation, maintenance, and other
provisions necessary to assure reduction in methane and VOC emissions
at least equivalent to the reduction in methane and VOC emissions
achieved under the design, equipment, work practice or operational
standard in paragraph (a) of this section by including the information
specified in paragraphs (d)(2)(i) through (x) of this section.
* * * * *
0
24. Amend Sec. 60.5410a by:
0
a. Revising paragraphs (a) introductory text, (b)(1), (d) introductory
text, and (f); and
0
b. Removing paragraph (k).
The revisions read as follows:
Sec. 60.5410a How do I demonstrate initial compliance with the
standards for my well, centrifugal compressor, reciprocating
compressor, pneumatic controller, pneumatic pump, storage vessel,
collection of fugitive emissions components at a well site, collection
of fugitive emissions components at a compressor station, and equipment
leaks at onshore natural gas processing plants and sweetening unit
affected facilities?
* * * * *
(a) To achieve initial compliance with the methane and VOC
standards for each well completion operation conducted at your well
affected facility
[[Page 17041]]
you must comply with paragraphs (a)(1) through (4) of this section.
* * * * *
(b)(1) To achieve initial compliance with standards for your
centrifugal compressor affected facility you must reduce methane and
VOC emissions from each centrifugal compressor wet seal fluid degassing
system by 95.0 percent or greater as required by Sec. 60.5380a(a) and
as demonstrated by the requirements of Sec. 60.5413a.
* * * * *
(d) To achieve initial compliance with methane and VOC emission
standards for your pneumatic controller affected facility you must
comply with the requirements specified in paragraphs (d)(1) through (6)
of this section, as applicable.
* * * * *
(f) For affected facilities at onshore natural gas processing
plants, initial compliance with the methane and VOC standards is
demonstrated if you are in compliance with the requirements of Sec.
60.5400a.
* * * * *
0
25. Amend Sec. 60.5412a by revising paragraphs (a)(1)(i) and (a)(2) to
read as follows:
Sec. 60.5412a What additional requirements must I meet for
determining initial compliance with control devices used to comply with
the emission standards for my centrifugal compressor, and storage
vessel affected facilities?
* * * * *
(a) * * *
(1) * * *
(i) You must reduce the mass content of methane and VOC in the
gases vented to the device by 95.0 percent by weight or greater as
determined in accordance with the requirements of Sec. 60.5413a(b),
with the exceptions noted in Sec. 60.5413a(a).
* * * * *
(2) Each vapor recovery device (e.g., carbon adsorption system or
condenser) or other non-destructive control device must be designed and
operated to reduce the mass content of methane and VOC in the gases
vented to the device by 95.0 percent by weight or greater as determined
in accordance with the requirements of Sec. 60.5413a(b). As an
alternative to the performance testing requirements in Sec.
60.5413a(b), you may demonstrate initial compliance by conducting a
design analysis for vapor recovery devices according to the
requirements of Sec. 60.5413a(c).
* * * * *
0
26. Amend Sec. 60.5413a by revising paragraphs (b)(4) introductory
text, (b)(4)(ii) and (d)(11)(iii) to read as follows:
Sec. 60.5413a What are the performance testing procedures for control
devices used to demonstrate compliance at my centrifugal compressor and
storage vessel affected facilities?
* * * * *
(b) * * *
(4) You must use Method 25A of appendix A-7 to this part to measure
TOC, as propane, to determine compliance with the TOC exhaust gas
concentration limit specified in Sec. 60.5412a(a)(1)(ii) or
(d)(1)(iv)(B). If you are determining compliance with the TOC exhaust
gas concentration limit specified in Sec. 60.5412a(d)(1)(iv)(B), you
may also use Method 18 of appendix A-6 to this part to measure methane
and ethane, and you may subtract the measured concentration of methane
and ethane from the Method 25A measurement to demonstrate compliance
with the concentration limit. You must determine the concentration in
parts per million by volume on a wet basis and correct it to 3 percent
oxygen, using the procedures in paragraphs (b)(4)(i) through (iii) of
this section.
* * * * *
(ii) If you are determining compliance with the TOC exhaust gas
concentration limit specified in Sec. 60.5412a(d)(1)(iv)(B), you may
subtract the concentration of methane and ethane from the Method 25A
TOC, as propane, concentration for each run.
* * * * *
(d) * * *
(11) * * *
(iii) A manufacturer must demonstrate a destruction efficiency of
at least 95 percent for THC, as propane. A control device model that
demonstrates a destruction efficiency of 95 percent for THC, as
propane, will meet the control requirement for 95 percent destruction
of VOC and methane (if applicable) required under this subpart.
* * * * *
0
27. Amend Sec. 60.5415a by:
0
a. Revising paragraphs (b)(1) and paragraph (f); and
0
b. Removing paragraphs (i) and (j).
The revisions read as follows:
Sec. 60.5415a How do I demonstrate continuous compliance with the
standards for my well, centrifugal compressor, reciprocating
compressor, pneumatic controller, pneumatic pump, storage vessel,
collection of fugitive emissions components at a well site, and
collection of fugitive emissions components at a compressor station
affected facilities, equipment leaks at onshore natural gas processing
plants and sweetening unit affected facilities?
* * * * *
(b) * * *
(1) You must reduce methane and VOC emissions from the wet seal
fluid degassing system by 95.0 percent or greater.
* * * * *
(f) For affected facilities at onshore natural gas processing
plants, continuous compliance with methane and VOC requirements is
demonstrated if you are in compliance with the requirements of Sec.
60.5400a.
* * * * *
0
28. Amend Sec. 60.5420a by:
0
a. Removing and reserving paragraph (b)(7)(i)(C);
0
b. Adding paragraph (b)(7)(iv);
0
c. Revising paragraphs (b)(9)(i), (b)(11), and (c)(5)(iv);
0
d. Removing and reserving paragraphs (c)(15)(ii) through (iv);
0
e. Revising the introductory text of paragraph (c)(15)(vii)(I) and
paragraph (c)(15)(vii)(I)(8); and
0
f. Adding paragraphs (c)(15)(vii)(I)(9) and (c)(15)(ix).
The additions and revisions read as follows:
Sec. 60.5420a What are my notification, reporting, and recordkeeping
requirements?
* * * * *
(b) * * *
(7) * * *
(iv) If you comply with the alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraph
(b)(7)(ii) of this section, you must provide the information specified
in Sec. 60.5424b.
* * * * *
(9) * * *
(i) For data collected using test methods supported by the EPA's
Electronic Reporting Tool (ERT) as listed on the EPA's ERT website
(https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of the test, you must submit the
results of the performance test to the EPA via the Compliance and
Emissions Data Reporting Interface (CEDRI), except as outlined in this
paragraph (b)(9)(i). (CEDRI can be accessed through the
[[Page 17042]]
EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/).) Performance
test data must be submitted in a file format generated through the use
of the EPA's ERT or an alternate electronic file format consistent with
the extensible markup language (XML) schema listed on the EPA's ERT
website. The EPA will make all the information submitted through CEDRI
available to the public without further notice to you. Do not use CEDRI
to submit information you claim as confidential business information
(CBI). Although we do not expect persons to assert a claim of CBI, if
you wish to assert a CBI claim, you must submit a complete file
generated through the use of the EPA's ERT or an alternate electronic
file consistent with the XML schema listed on the EPA's ERT website,
including information claimed to be CBI, to the EPA following the
procedures in paragraphs (b)(9)(i)(A) and (B) of this section. Clearly
mark the part or all of the information that you claim to be CBI.
Information not marked as CBI may be authorized for public release
without prior notice. Information marked as CBI will not be disclosed
except in accordance with procedures set forth in 40 CFR part 2. All
CBI claims must be asserted at the time of submission. Anything
submitted using CEDRI cannot later be claimed CBI. Furthermore, under
CAA section 114(c), emissions data is not entitled to confidential
treatment, and the EPA is required to make emissions data available to
the public. Thus, emissions data will not be protected as CBI and will
be made publicly available. The same ERT or alternate file submitted to
the CBI office with the CBI omitted must be submitted to the EPA via
the EPA's CDX as described earlier in this paragraph (b)(9)(i).
(A) The preferred method to receive CBI is for it to be transmitted
electronically using email attachments, File Transfer Protocol, or
other online file sharing services. Electronic submissions must be
transmitted directly to the OAQPS CBI Office at the email address
[email protected], and as described above, should include clear CBI
markings. ERT files should be flagged to the attention of the Group
Leader, Measurement Policy Group. If assistance is needed with
submitting large electronic files that exceed the file size limit for
email attachments, and if you do not have your own file sharing
service, please email [email protected] to request a file transfer link.
(B) If you cannot transmit the file electronically, you may send
CBI information through the postal service to the following address:
U.S. EPA, Attn: OAQPS Document Control Officer and Measurement Policy
Group Leader, Mail Drop: C404-02, 109 T.W. Alexander Drive, P.O. Box
12055, RTP, NC 27711. The mailed CBI material should be double wrapped
and clearly marked. Any CBI markings should not show through the outer
envelope.
* * * * *
(11) You must submit reports to the EPA via CEDRI, except as
outlined in this paragraph (b)(11). CEDRI can be accessed through the
EPA's CDX (https://cdx.epa.gov/). You must use the appropriate
electronic report template on the CEDRI website for this subpart
(https://www.epa.gov/electronic-reporting-air-emissions/cedri/). If the
reporting form specific to this subpart is not available on the CEDRI
website at the time that the report is due, you must submit the report
to the Administrator at the appropriate address listed in Sec. 60.4.
Once the form has been available in CEDRI for at least 90 calendar
days, you must begin submitting all subsequent reports via CEDRI. The
date reporting forms become available will be listed on the CEDRI
website. Unless the Administrator or delegated state agency or other
authority has approved a different schedule for submission of reports,
the reports must be submitted by the deadlines specified in this
subpart, regardless of the method in which the reports are submitted.
The EPA will make all the information submitted through CEDRI available
to the public without further notice to you. Do not use CEDRI to submit
information you claim as CBI. Although we do not expect persons to
assert a claim of CBI, if you wish to assert a CBI claim for some of
the information in the report, submit a complete file using the
appropriate electronic report template on the CEDRI website, including
information claimed to be CBI, to the EPA following the procedures in
paragraphs (b)(11)(i) and (ii) of this section. Clearly mark the part
or all of the information that you claim to be CBI. Information not
marked as CBI may be authorized for public release without prior
notice. Information marked as CBI will not be disclosed except in
accordance with procedures set forth in 40 CFR part 2. All CBI claims
must be asserted at the time of submission. Anything submitted using
CEDRI cannot later be claimed CBI. Furthermore, under CAA section
114(c), emissions data is not entitled to confidential treatment, and
the EPA is required to make emissions data available to the public.
Thus, emissions data will not be protected as CBI and will be made
publicly available. Submit the same file submitted to the CBI office
with the CBI omitted must be submitted to the EPA via the EPA's CDX as
described earlier in this paragraph (b)(11).
(i) The preferred method to receive CBI is for it to be transmitted
electronically using email attachments, File Transfer Protocol, or
other online file sharing services. Electronic submissions must be
transmitted directly to the OAQPS CBI Office at the email address
[email protected], and as described above, should include clear CBI
markings. Files should be flagged to the attention of the Oil and
Natural Gas Sector Lead. If assistance is needed with submitting large
electronic files that exceed the file size limit for email attachments,
and if you do not have your own file sharing service, please email
[email protected] to request a file transfer link.
(ii) If you cannot transmit the file electronically, you may send
CBI information through the postal service to the following address:
U.S. EPA, Attn: OAQPS Document Control Officer and Oil and Natural Gas
Sector Lead, Mail Drop: C404-02, 109 T.W. Alexander Drive, P.O. Box
12055, RTP, NC 27711. The mailed CBI material should be double wrapped
and clearly marked. Any CBI markings should not show through the outer
envelope.
* * * * *
(c) * * *
(5) * * *
(iv) For storage vessels that are skid-mounted or permanently
attached to something that is mobile (such as trucks, railcars, barges,
or ships), records indicating the number of consecutive days that the
vessel is located at a site in the crude oil and natural gas production
segment, natural gas processing segment, or natural gas transmission
and storage segment. If a storage vessel is removed from a site and,
within 30 days, is either returned to the site or replaced by another
storage vessel at the site to serve the same or similar function, then
the entire period since the original storage vessel was first located
at the site, including the days when the storage vessel was removed,
will be added to the count towards the number of consecutive days.
* * * * *
(15) * * *
(vii) * * *
(I) Documentation of each fugitive emission detected during the
monitoring survey, including the information specified in paragraphs
(c)(15)(vii)(I)(1) through (9) of this section.
* * * * *
(8) For each fugitive emission component placed on delay of repair
for
[[Page 17043]]
reason of replacement component unavailability, the operator must
document: the date the component was added to the delay of repair list,
the date the replacement fugitive component or part thereof was
ordered, the anticipated component delivery date (including any
estimated shipment or delivery date provided by the vendor), and the
actual arrival date of the component.
(9) Date of planned shutdowns that occur while there are any
components that have been placed on delay of repair.
* * * * *
(ix) If you comply with the alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(c)(15)(vi) through (vii) of this section, you must maintain the
records specified in Sec. 60.5424b.
* * * * *
Sec. 60.5421a What are my additional recordkeeping requirements for
my affected facility subject to GHG and VOC requirements for onshore
natural gas processing plants?
0
29. Amend Sec. 60.5421a by revising the section heading to read as set
forth above.
Sec. 60.5422a What are my additional reporting requirements for my
affected facility subject to GHG and VOC requirements for onshore
natural gas processing plants?
0
30. Amend Sec. 60.5422a by revising the section heading to read as set
forth above.
0
31. Amend Sec. 60.5430a by:
0
a. Revising definitions for ``Compressor station'', ``Crude Oil and
Natural Gas Production source category'', ``Equipment'', and ``Fugitive
emissions component''; and
0
b. Removing definition for ``Natural gas transmission and storage
segment''.
The revisions read as follows:
Sec. 60.5430a What definitions apply to this subpart?
* * * * *
Compressor station means any permanent combination of one or more
compressors that move natural gas at increased pressure through
gathering or transmission pipelines, or into or out of storage. This
includes, but is not limited to, gathering and boosting stations and
transmission compressor stations. The combination of one or more
compressors located at a well site, or located at an onshore natural
gas processing plant, is not a compressor station for purposes of Sec.
60.5397a.
* * * * *
Crude oil and natural gas source category means:
(1) Crude oil production, which includes the well and extends to
the point of custody transfer to the crude oil transmission pipeline or
any other forms of transportation; and
(2) Natural gas production, processing, transmission, and storage,
which include the well and extend to, but do not include, the local
distribution company custody transfer station.
* * * * *
Equipment, as used in the standards and requirements in this
subpart relative to the equipment leaks of GHG (in the form of methane)
VOC from onshore natural gas processing plants, means each pump,
pressure relief device, open-ended valve or line, valve, and flange or
other connector that is in VOC service or in wet gas service, and any
device or system required by those same standards and requirements in
this subpart.
* * * * *
Fugitive emissions component means any component that has the
potential to emit fugitive emissions of methane or VOC at a well site
or compressor station, including valves, connectors, pressure relief
devices, open-ended lines, flanges, covers and closed vent systems not
subject to Sec. 60.5411 or Sec. 60.5411a, thief hatches or other
openings on a controlled storage vessel not subject to Sec. 60.5395 or
Sec. 60.5395a, compressors, instruments, and meters. Devices that vent
as part of normal operations, such as natural gas-driven pneumatic
controllers or natural gas-driven pumps, are not fugitive emissions
components, insofar as the natural gas discharged from the device's
vent is not considered a fugitive emission. Emissions originating from
other than the device's vent, such as the thief hatch on a controlled
storage vessel, would be considered fugitive emissions.
* * * * *
0
32. Add subpart OOOOb, to part 60 to read as follows:
Subpart OOOOb--Standards of Performance for Crude Oil and Natural
Gas Facilities for Which Construction, Modification or
Reconstruction Commenced After December 6, 2022
60.5360b What is the purpose of this subpart?
60.5365b Am I subject to this subpart?
60.5370b When must I comply with this subpart?
60.5371b What GHG and VOC standards apply to super-emitter events?
60.5375b What GHG and VOC standards apply to well completions at
well affected facilities?
60.5376b What GHG and VOC standards apply to gas well liquids
unloading operations at well affected facilities?
60.5377b What GHG and VOC standards apply to associated gas wells at
well affected facilities?
60.5380b What GHG and VOC standards apply to centrifugal compressor
affected facilities?
60.5385b What GHG and VOC standards apply to reciprocating
compressor affected facilities?
60.5386b What test methods and procedures must I use for my
centrifugal compressor and reciprocating compressor affected
facilities?
60.5390b What GHG and VOC standards apply to process controller
affected facilities?
60.5393b What GHG and VOC standards apply to pump affected
facilities?
60.5395b What GHG and VOC standards apply to storage vessel affected
facilities?
60.5397b What GHG and VOC standards apply to fugitive emissions
components affected facilities?
60.5398b What alternative GHG and VOC standards apply to fugitive
emissions components affected facilities and what inspection and
monitoring requirements apply to covers and closed vent systems when
using an alternative technology?
60.5399b What are the alternative means of emission limitations for
GHG and VOC from well completions, liquids unloading operations,
centrifugal compressors, reciprocating compressors, fugitive
emissions components, and process unit equipment affected
facilities; and what are the alternative fugitive emissions
standards based on State, local, and Tribal programs?
60.5400b What GHG and VOC standards apply to process unit equipment
affected facilities?
60.5401b What are the alternative GHG and VOC standards for process
unit equipment affected facilities?
60.5402b What are the exceptions to the GHG and VOC standards for
process unit equipment affected facilities?
60.5403b What test methods and procedures must I use for my process
unit equipment affected facilities?
60.5405b What standards apply to sweetening unit affected
facilities?
60.5406b What test methods and procedures must I use for my
sweetening unit affected facilities?
60.5407b What are the requirements for monitoring of emissions and
operations from my sweetening unit affected facilities?
60.5408b What is an optional procedure for measuring hydrogen
sulfide in acid gas--Tutwiler Procedure?
60.5410b How do I demonstrate initial compliance with the standards
for each of my affected facilities?
60.5411b What additional requirements must I meet to determine
initial compliance for my covers and closed vent systems?
60.5412b What additional requirements must I meet for determining
initial compliance of my control devices?
[[Page 17044]]
60.5413b What are the performance testing procedures for control
devices?
60.5415b How do I demonstrate continuous compliance with the
standards for each of my affected facilities?
60.5416b What are the initial and continuous cover and closed vent
system inspection and monitoring requirements?
60.5417b What are the continuous monitoring requirements for my
control devices?
60.5420b What are my notification, reporting, and recordkeeping
requirements?
60.5421b What are my additional recordkeeping requirements for
process unit equipment affected facilities?
60.5422b What are my additional reporting requirements for process
unit equipment affected facilities?
60.5423b What are my additional recordkeeping and reporting
requirements for sweetening unit affected facilities?
60.5424b What are my additional recordkeeping and reporting
requirements if I comply with the alternative GHG and VOC standards
for fugitive emissions components affected facilities and covers and
closed vent systems?
60.5425b What parts of the General Provisions apply to me?
60.5430b What definitions apply to this subpart?
60.5432b How do I determine whether a well is a low pressure well
using the low pressure well equation?
60.5433b-60.5439b [Reserved]
Table 1 to Subpart OOOOb of Part 60--Alternative Technology Periodic
Screening Frequency at Well Sites, Centralized Production, and
Compressor Stations Facilities Subject to AVO Inspections with
Quarterly OGI or EPA Method 21 Monitoring
Table 2 to Subpart OOOOb of Part 60--Alternative Technology Periodic
Screening Frequency at Well Sites and Centralized Production
Facilities Subject to AVO Inspections and/or Semiannual OGI or EPA
Method 21 Monitoring
Table 3 to Subpart OOOOb of Part 60--Required Minimum Initial SO2
Emission Reduction Efficiency (Zi)
Table 4 to Subpart OOOOb of Part 60--Required Minimum SO2 Emission
Reduction Efficiency (Zc)
Table 5 to Subpart OOOOb of Part 60--Applicability of General
Provisions to Subpart OOOOb
Sec. 60.5360b What is the purpose of this subpart?
(a) Scope. This subpart establishes emission standards and
compliance schedules for the control of the pollutant greenhouse gases
(GHG). The greenhouse gas standard in this subpart is in the form of a
limitation on emissions of methane from affected facilities in the
crude oil and natural gas source category that commence construction,
modification, or reconstruction after December 6, 2022. This subpart
also establishes emission standards and compliance schedules for the
control of volatile organic compounds (VOC) and sulfur dioxide
(SO2) emissions from affected facilities in the crude oil
and natural gas source category that commence construction,
modification, or reconstruction after December 6, 2022.
(b) Prevention of Significant Deterioration (PSD) and title V
thresholds for Greenhouse Gases. (1) For the purposes of 40 CFR
51.166(b)(49)(ii), with respect to GHG emissions from affected
facilities, the ``pollutant that is subject to the standard promulgated
under section 111 of the Act'' shall be considered the pollutant that
otherwise is subject to regulation under the Act as defined in 40 CFR
51.166(b)(48) and in any State Implementation Plan (SIP) approved by
the EPA that is interpreted to incorporate, or specifically
incorporates, 40 CFR 51.166(b)(48).
(2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to
GHG emissions from affected facilities, the ``pollutant that is subject
to the standard promulgated under section 111 of the Act'' shall be
considered the pollutant that otherwise is subject to regulation under
the Clean Air Act as defined in 40 CFR 52.21(b)(49).
(3) For the purposes of 40 CFR 70.2, with respect to GHG emissions
from affected facilities, the ``pollutant that is subject to any
standard promulgated under section 111 of the Act'' shall be considered
the pollutant that otherwise is ``subject to regulation'' as defined in
40 CFR 70.2.
(4) For the purposes of 40 CFR 71.2, with respect to GHG emissions
from affected facilities, the ``pollutant that is subject to any
standard promulgated under section 111 of the Act'' shall be considered
the pollutant that otherwise is ``subject to regulation'' as defined in
40 CFR 71.2.
(c) Exemption. You are exempt from the obligation to obtain a
permit under 40 CFR part 70 or 40 CFR part 71, provided you are not
otherwise required by law to obtain a permit under 40 CFR 70.3(a) or 40
CFR 71.3(a). Notwithstanding the previous sentence, you must continue
to comply with the provisions of this subpart.
Sec. 60.5365b Am I subject to this subpart?
You are subject to the applicable provisions of this subpart if you
are the owner or operator of one or more of the onshore affected
facilities listed in paragraphs (a) through (i) of this section, that
is located within the Crude Oil and Natural Gas source category, as
defined in Sec. 60.5430b, for which you commence construction,
modification, or reconstruction after December 6, 2022. Facilities
located inside and including the Local Distribution Company (LDC)
custody transfer station are not subject to this subpart.
(a) Each well affected facility, which is a single well drilled for
the purpose of producing oil or natural gas.
(1) In addition to Sec. 60.14, a ``modification'' of an existing
well occurs when:
(i) An existing well is hydraulically fractured, or
(ii) An existing well is hydraulically refractured.
(2) For the purposes of a well affected facility, a liquids
unloading event is not considered to be a modification.
(3) Except as provided in Sec. 60.5365b(e)(3)(ii)(C) and
(i)(3)(ii), any action described by paragraphs (a)(1)(i) and (ii) of
this section, by itself, does not affect the modification status of
process unit equipment, centrifugal or reciprocating compressors,
pumps, or process controllers.
(b) Each centrifugal compressor affected facility, which is a
single centrifugal compressor. A centrifugal compressor located at a
well site is not an affected facility under this subpart. A centrifugal
compressor located at a centralized production facility is an affected
facility under this subpart.
(c) Each reciprocating compressor affected facility, which is a
single reciprocating compressor. A reciprocating compressor located at
a well site is not an affected facility under this subpart. A
reciprocating compressor located at a centralized production facility
is an affected facility under this subpart.
(d) Each process controller affected facility, which is the
collection of natural gas-driven process controllers at a well site,
centralized production facility, onshore natural gas processing plant,
or a compressor station. Natural gas-driven process controllers that
function as emergency shutdown devices and process controllers that are
not driven by natural gas are not included in the affected facility.
(1) For the purposes of Sec. 60.5390b, in addition to the
definition in Sec. 60.14, a modification occurs when the number of
natural gas-driven process controllers in the affected facility is
increased by one or more.
(2) For the purposes of Sec. 60.5390b, owners and operators may
choose to apply reconstruction as defined in Sec. 60.15(b) based on
the fixed capital cost of the new process controllers in accordance
with paragraph (d)(2)(i) of this section, or the definition of
reconstruction based on the number of natural gas-driven process
controllers in
[[Page 17045]]
the affected facility in accordance with paragraph (d)(2)(ii) of this
section. Owners and operators may choose which definition of
reconstruction to apply and whether to comply with paragraph (d)(2)(i)
or (ii) of this section; they do not need to apply both. If owners and
operators choose to comply with paragraph (d)(2)(ii) of this section
they may demonstrate compliance with Sec. 60.15(b)(1) by showing that
more than 50 percent of the number of natural gas-driven process
controllers in the affected facility is replaced. That is, if an owner
or operator meets the definition of reconstruction through the ``number
of controllers'' criterion in (d)(2)(ii) of this section, they will
have shown that the ``fixed capital cost of the new components exceeds
50 percent of the fixed capital cost that would be required to
construct a comparable entirely new facility,'' as required in Sec.
60.15(b)(1). Therefore, an owner or operator may comply with the
remaining provisions of Sec. 60.15 that reference ``fixed capital
cost'' through an initial showing that the number of natural gas-driven
process controllers replaced exceeds 50 percent. For purposes of
paragraphs (d)(2)(i) and (ii), ``commenced'' means that an owner or
operator has undertaken a continuous program of natural gas-driven
process controller replacement or that an owner or operator has entered
into a contractual obligation to undertake and complete, within a
reasonable time, a continuous program of natural gas-driven process
controller replacement.
(i) If the owner or operator applies the definition of
reconstruction in Sec. 60.15(b)(1), reconstruction occurs when the
fixed capital cost of the new process controllers exceeds 50 percent of
the fixed capital cost that would be required to replace all the
natural gas-driven process controllers in the affected facility. The
``fixed capital cost of the new process controllers'' includes the
fixed capital cost of all natural gas-driven process controllers which
are or will be replaced pursuant to all continuous programs of
component replacement which are commenced within any 24-month rolling
period following December 6, 2022.
(ii) If the owner or operator applies the definition of
reconstruction based on the percentage of natural gas-driven process
controllers replaced, reconstruction occurs when greater than 50
percent of the natural gas-driven process controllers at a site are
replaced. The percentage includes all natural gas-driven process
controllers which are or will be replaced pursuant to all continuous
programs of natural gas-driven process controller replacement which are
commenced within any 24-month rolling period following December 6,
2022. If an owner or operator determines reconstruction based on the
percentage of natural gas-driven process controllers that are replaced,
the owner or operator must also comply with Sec. 60.15(a).
(e) Each storage vessel affected facility, which is a tank battery
that has the potential for emissions as specified in either paragraph
(e)(1)(i) or (ii) of this section. A tank battery with the potential
for emissions below both of the thresholds specified in paragraphs
(e)(1)(i) and (ii) of this section is not a storage vessel affected
facility provided the owner/operator keeps records of the potential for
emissions calculation for the life of the storage vessel or until such
time the tank battery becomes a storage vessel affected facility
because the potential for emissions meets or exceeds either threshold
specified in either paragraph (e)(1)(i) or (ii) of this section.
(1)(i) Potential for VOC emissions equal to or greater than 6 tons
per year (tpy) as determined in paragraph (e)(2) of this section.
(ii) Potential for methane emissions equal to or greater than 20
tpy as determined in paragraph (e)(2) of this section.
(2) The potential for VOC and methane emissions must be calculated
as the cumulative emissions from all storage vessels within the tank
battery as specified by the applicable requirements in paragraphs
(e)(2)(i) through (iii) of this section. The determination may take
into account requirements under a legally and practicably enforceable
limit in an operating permit or other requirement established under a
Federal, state, local, or Tribal authority.
(i) For purposes of determining the applicability of a storage
vessel tank battery as an affected facility, a legally and practicably
enforceable limit must include the elements provided in paragraphs
(e)(2)(i)(A) through (F) of this section.
(A) A quantitative production limit and quantitative operational
limit(s) for the equipment, or quantitative operational limits for the
equipment;
(B) An averaging time period for the production limit in
(e)(2)(i)(A) of this section, if a production-based limit is used, that
is equal to or less than 30 days;
(C) Established parametric limits for the production and/or
operational limit(s) in (e)(1)(i)(A) of this section, and where a
control device is used to achieve an operational limit, an initial
compliance demonstration (i.e., performance test) for the control
device that establishes the parametric limits;
(D) Ongoing monitoring of the parametric limits in (e)(2)(i)(C) of
this section that demonstrates continuous compliance with the
production and/or operational limit(s) in (e)(2)(i)(A) of this section;
(E) Recordkeeping by the owner or operator that demonstrates
continuous compliance with the limit(s) in (e)(2)(i)(A) through (D) of
this section; and
(F) Periodic reporting that demonstrates continuous compliance.
(ii) For each tank battery located at a well site or centralized
production facility, you must determine the potential for VOC and
methane emissions within 30 days after startup of production, or within
30 days after an action specified in paragraphs (e)(3)(i) and (ii) of
this section, except as provided in paragraph (e)(5)(iv) of this
section. The potential for VOC and methane emissions must be calculated
using a generally accepted model or calculation methodology that
accounts for flashing, working, and breathing losses, based on the
maximum average daily throughput to the tank battery determined for a
30-day period of production.
(iii) For each tank battery not located at a well site or
centralized production facility, including each tank battery located at
a compressor station or onshore natural gas processing plant, you must
determine the potential for VOC and methane emissions prior to startup
of the compressor station, onshore natural gas processing plant, or
other facility within 30 days after an action specified in paragraphs
(e)(3)(i) and (ii) of this section, using either method described in
paragraph (e)(2)(iii)(A) or (B) of this section.
(A) Determine the potential for VOC and methane emissions using a
generally accepted model or calculation methodology that accounts for
flashing, working and breathing losses and based on the throughput to
the tank battery established in a legally and practicably enforceable
limit in an operating permit or other requirement established under a
Federal, state, local, or Tribal authority; or
(B) Determine the potential for VOC and methane emissions using a
generally accepted model or calculation methodology that accounts for
flashing, working and breathing losses and based on projected maximum
average daily throughput. Maximum average daily throughput is
determined using a generally accepted engineering model (e.g.,
volumetric condensate rates from the tank battery based on the maximum
[[Page 17046]]
gas throughput capacity of each producing facility) to project the
maximum average daily throughput for the tank battery.
(3) For the purposes of Sec. 60.5395b, the following definitions
of ``reconstruction'' and ``modification'' apply for determining when
an existing tank battery becomes a storage vessel affected facility
under this subpart.
(i) ``Reconstruction'' of a tank battery occurs when the potential
for VOC or methane emissions to meet or exceed either of the thresholds
specified in paragraphs (e)(1)(i) or (ii) of this section and
(A) at least half of the storage vessels are replaced in the
existing tank battery that consists of more than one storage vessel; or
(B) the provisions of Sec. 60.15 are met for the existing tank
battery.
(ii) ``Modification'' of a tank battery occurs when any of the
actions in paragraphs (e)(3)(ii)(A) through (D) of this section occurs
and the potential for VOC or methane emissions meet or exceed either of
the thresholds specified in paragraphs (e)(1)(i) or (ii) of this
section.
(A) A storage vessel is added to an existing tank battery;
(B) One or more storage vessels are replaced such that the
cumulative storage capacity of the existing tank battery increases;
(C) For tank batteries at well sites or centralized production
facilities, an existing tank battery receives additional crude oil,
condensate, intermediate hydrocarbons, or produced water throughput
from actions, including but not limited to, the addition of operations
or a production well, or changes to operations or a production well
(including hydraulic fracturing or refracturing of the well).
(D) For tank batteries not located at a well site or centralized
production facility, including each tank battery at compressor stations
or onshore natural gas processing plants, an existing tank battery
receives additional fluids which cumulatively exceed the throughput
used in the most recent (i.e., prior to an action in paragraphs
(e)(3)(ii)(A), (B) or (D) of this section) determination of the
potential for VOC or methane emissions.
(4) A storage vessel affected facility that subsequently has its
potential for VOC emissions decrease to less than 6 tpy shall remain an
affected facility under this subpart.
(5) For storage vessels not subject to a legally and practicably
enforceable limit in an operating permit or other requirement
established under Federal, state, local, or Tribal authority, any vapor
from the storage vessel that is recovered and routed to a process
through a vapor recovery unit designed and operated as specified in
this section is not required to be included in the determination of
potential for VOC or methane emissions for purposes of determining
affected facility status, provided you comply with the requirements of
paragraphs (e)(5)(i) through (iv) of this section.
(i) You meet the cover requirements specified in Sec. 60.5411b(b).
(ii) You meet the closed vent system requirements specified in
Sec. 60.5411b(a)(2) through (4) and (c).
(iii) You must maintain records that document compliance with
paragraphs (e)(5)(i) and (ii) of this section.
(iv) In the event of removal of apparatus that recovers and routes
vapor to a process, or operation that is inconsistent with the
conditions specified in paragraphs (e)(5)(i) and (ii) of this section,
you must determine the storage vessel's potential for VOC emissions
according to this section within 30 days of such removal or operation.
(6) The requirements of this paragraph (e)(6) apply to each storage
vessel affected facility immediately upon startup, startup of
production, or return to service. A storage vessel affected facility or
portion of a storage vessel affected facility that is reconnected to
the original source of liquids remains a storage vessel affected
facility subject to the same requirements that applied before being
removed from service. Any storage vessel that is used to replace a
storage vessel affected facility, or portion of a storage vessel
affected facility, or used to expand a storage vessel affected facility
assumes the affected facility status of the storage vessel affected
facility being replaced or expanded.
(7) A storage vessel with a capacity greater than 100,000 gallons
used to recycle water that has been passed through two stage separation
is not a storage vessel affected facility.
(f) Each process unit equipment affected facility, which is the
group of all equipment within a process unit at an onshore natural gas
processing plant is an affected facility.
(1) Addition or replacement of equipment for the purpose of process
improvement that is accomplished without a capital expenditure shall
not by itself be considered a modification under this subpart.
(2) Equipment associated with a compressor station, dehydration
unit, sweetening unit, underground storage vessel, field gas gathering
system, or liquefied natural gas unit is covered by Sec. Sec.
60.5400b, 60.5401b, 60.5402b, 60.5421b, and 60.5422b if it is located
at an onshore natural gas processing plant. Equipment not located at
the onshore natural gas processing plant site is exempt from the
provisions of Sec. Sec. 60.5400b, 60.5401b, 60.5402b, 60.5421b, and
60.5422b.
(g) Each sweetening unit affected facility as defined by paragraphs
(g)(1) and (2) of this section.
(1) Each sweetening unit that processes natural gas produced from
either onshore or offshore wells is an affected facility; and
(2) Each sweetening unit that processes natural gas followed by a
sulfur recovery unit is an affected facility.
(3) Facilities that have a design capacity less than 2 long tons
per day (LT/D) of hydrogen sulfide (H2S) in the acid gas
(expressed as sulfur) are required to comply with recordkeeping and
reporting requirements specified in Sec. 60.5423b(c) but are not
required to comply with Sec. Sec. 60.5405b through 60.5407b and
Sec. Sec. 60.5410b(i) and 60.5415b(i).
(4) Sweetening facilities producing acid gas that is completely re-
injected into oil-or-gas-bearing geologic strata or that is otherwise
not released to the atmosphere are not subject to Sec. Sec. 60.5405b
through 60.5407b, 60.5410b(i), 60.5415b(i), and 60.5423b.
(h) Each pump affected facility, which is the collection of natural
gas-driven pumps at a well site, centralized production facility,
onshore natural gas processing plant, or a compressor station. Pumps
that are not driven by natural gas are not included in the pump
affected facility.
(1) For the purposes of Sec. 60.5393b, in addition to the
definition in Sec. 60.14, a modification occurs when the number of
natural gas-driven pumps in the affected facility is increased by one
or more.
(2) For the purposes of Sec. 60.5390b, owners and operators may
choose to apply reconstruction as defined in Sec. 60.15(b) based on
the fixed capital cost of the new pumps in accordance with paragraph
(h)(2)(i) of this section, or the definition of reconstruction based on
the number of natural gas-driven pumps in the affected facility in
accordance with paragraph (h)(2)(ii) of this section. Owners and
operators may choose which definition of reconstruction to apply and
whether to comply with paragraph (h)(2)(i) or (ii) of this section;
they do not need to apply both. If owners and operators choose to
comply with paragraph (h)(2)(ii) of this section they may demonstrate
compliance with Sec. 60.15(b)(1) by showing that more than 50 percent
of the number of natural gas-
[[Page 17047]]
driven pumps is replaced. That is, if an owner or operator meets the
definition of reconstruction through the ``number of pumps'' criterion
in (h)(2)(ii) of this section, they will have shown that the ``fixed
capital cost of the new components exceeds 50 percent of the fixed
capital cost that would be required to construct a comparable entirely
new facility,'' as required in Sec. 60.15(b)(1). Therefore, an owner
or operator may comply with the remaining provisions of Sec. 60.15
that reference ``fixed capital cost'' through an initial showing that
the number of natural gas-driven pumps replaced exceeds 50 percent. For
purposes of paragraphs (h)(2)(i) and (ii) of this section,
``commenced'' means that an owner or operator has undertaken a
continuous program of component replacement or that an owner or
operator has entered into a contractual obligation to undertake and
complete, within a reasonable time, a continuous program of natural
gas-driven pump replacement.
(i) If the owner or operator applies the definition of
reconstruction in Sec. 60.15, reconstruction occurs when the fixed
capital cost of the new pumps exceeds 50 percent of the fixed capital
cost that would be required to replace all the natural gas-driven pumps
in the affected facility. The ``fixed capital cost of the new pumps''
includes the fixed capital cost of all natural gas-driven pumps which
are or will be replaced pursuant to all continuous programs of
component replacement which are commenced within any 24-month rolling
period following December 6, 2022.
(ii) If the owner or operator applies the definition of
reconstruction based on the percentage of natural gas-driven pumps
replaced, reconstruction occurs when greater than 50 percent of the
natural gas-driven pumps in the affected facility are replaced. The
percentage includes all natural gas-driven pumps which are or will be
replaced pursuant to all continuous programs of component replacement
which are commenced within any 24-month rolling period following
December 6, 2022. If an owner or operator determines reconstruction
based on the percentage of natural gas-driven pumps that are replaced,
the owner or operator must comply with Sec. 60.15(a).
(3) A natural gas-driven pump that is in operation less than 90
days per calendar year is not part of an affected facility under this
subpart. For the purposes of this section, any period of operation
during a calendar day counts toward the 90-calendar day threshold.
(i) Each fugitive emissions components affected facility, which is
the collection of fugitive emissions components at a well site,
centralized production facility, or a compressor station.
(1) For purposes of Sec. 60.5397b and Sec. 60.5398b, a
``modification'' to a well site occurs when:
(i) A new well is drilled at an existing well site;
(ii) A well at an existing well site is hydraulically fractured; or
(iii) A well at an existing well site is hydraulically refractured.
(2) For purposes of Sec. 60.5397b and Sec. 60.5398b, a
``modification'' to centralized production facility occurs when:
(i) Any of the actions in paragraphs (i)(1)(i) through (iii) of
this section occurs at an existing centralized production facility;
(ii) A well sending production to an existing centralized
production facility is modified, as defined in paragraphs (i)(1)(i)
through (iii) of this section; or
(iii) A well site subject to the requirements of Sec. 60.5397b or
Sec. 60.5398b removes all major production and processing equipment,
such that it becomes a wellhead only well site and sends production to
an existing centralized production facility.
(3) For purposes of Sec. 60.5397b, a ``modification'' to a
compressor station occurs when:
(i) An additional compressor is installed at a compressor station;
or
(ii) One or more compressors at a compressor station is replaced by
one or more compressors of greater total horsepower than the
compressor(s) being replaced. When one or more compressors is replaced
by one or more compressors of an equal or smaller total horsepower than
the compressor(s) being replaced, installation of the replacement
compressor(s) does not trigger a modification of the compressor station
for purposes of Sec. 60.5397b.
Sec. 60.5370b When must I comply with this subpart?
(a) You must be in compliance with the standards of this subpart no
later than May 7, 2024 or upon initial startup, whichever date is
later, except as specified in paragraph (a)(1) of this section for
reciprocating compressor affected facilities, paragraphs (a)(2) and (3)
of this section for storage vessel affected facilities, paragraph
(a)(4) of this section for process unit equipment affected facilities
at onshore natural gas processing plants, paragraph (a)(5) of this
section for process controllers, paragraph (a)(6) of this section for
pumps, paragraph (a)(7) of this section for centrifugal compressor
affected facilities, and paragraphs Sec. 60.5377b(b) or (c) for
associated gas wells.
(1) You must comply with the requirements of Sec. 60.5385b(a) for
your reciprocating compressor affected facility as specified in
paragraph (a)(1)(i), (ii), or (iii) of this section, as applicable.
(i) You must comply with the requirements of Sec. 60.5385b(a)(1)
and (d)(3) on or before 8,760 hours of operation after May 7, 2024, on
or before 8,760 hours of operation after last rod packing replacement,
or on or before 8,760 hours of operation after startup, whichever date
is later; and
(ii) You must comply with the requirements of Sec. 60.5385b(a)(2)
within 8,760 hours after compliance with Sec. 60.5385b(a)(1) and
(d)(3).
(iii) You must comply with the requirements of Sec. 60.5385b(d)(1)
and (2) for your reciprocating compressor upon initial startup.
(2) You must comply with the requirements of paragraphs Sec.
60.5395b(a)(1) for your storage vessel affected facility as specified
in paragraphs (a)(2)(i) or (ii) of this section, as applicable.
(i) Within 30 days after startup of production, or within 30 days
after reconstruction or modification of the storage vessel affected
facility, for each storage vessel affected facility located at a well
site or centralized production facility.
(ii) Prior to startup of the compressor station or onshore natural
gas processing plant, or within 30 days after reconstruction or
modification of the storage vessel affected facility, for each storage
vessel affected facility located at a compressor station or onshore
natural gas processing plant.
(3) You must comply with the requirements of paragraph Sec.
60.5395b(a)(2) as specified in paragraph (a)(3)(i) or (ii) of this
section, as applicable:
(i) For each storage vessel affected facility located at a well
site or centralized production facility, you must achieve the required
emissions reductions within 30 days after the determination in
paragraph (a)(2)(i) of this section.
(ii) For storage vessel affected facilities located at a compressor
station or onshore natural gas processing plant, you must achieve the
required emissions reductions within 30 days after the determination in
paragraph (a)(2)(ii) of this section.
(4) You must comply with the requirements of Sec. 60.5400b for all
process unit equipment affected facilities at a natural gas processing
plant, as soon as practicable but no later than 180 days after the
initial startup of the process unit.
[[Page 17048]]
(5) For process controller affected facilities, you must comply
with the requirements of paragraph (a)(5)(i) or (ii) of this section,
as applicable.
(i) Any process controller affected facilities may comply with
Sec. 60.5390b(b)(1) and (2) or (3) as an alternative to compliance
with Sec. 60.5390b(a) until [May 7, 2025.
(ii) On or after May 7, 2025, process controller affected
facilities must comply with Sec. 60.5390b(a) or (b), as specified in
those paragraphs.
(6) For pump affected facilities, you must comply with the
requirements of paragraph (a)(6)(i) or (ii) of this section, as
applicable.
(i) Any pump affected facility may comply with Sec. 60.5393b(b)(2)
through (8), as applicable, as an alternative to compliance with Sec.
60.5393b(a) until May 7, 2025.
(ii) On or after May 7, 2025, pump affected facilities must comply
with Sec. 60.5393b(a) or (b), as specified in those paragraphs.
(7) For centrifugal compressor affected facilities, you must comply
with the requirements of paragraph (a)(7)(i) or (ii) of this section,
as applicable.
(i) You must comply with the requirements of Sec. 60.5380b(a)(1)
and (2), or (a)(3) for your reciprocating compressor upon initial
startup.
(ii) Each centrifugal compressor affected facility that uses dry
seals, each self-contained wet seal compressor, and each centrifugal
compressor on the Alaska North Slope equipped with sour seal oil
separator and capture system, complying with one of the alternatives in
Sec. 60.5380b(a)(4), (5), or (6), must comply with the specified
performance-based volumetric flow rate work practice standards on or
before 8,760 hours of operation after May 7, 2024, on or before 8,760
hours of operation after last seal replacement, or on or before 8,760
hours of operation after startup, whichever date is later.
(b) At all times, including periods of startup, shutdown, and
malfunction, owners and operators shall maintain and operate any
affected facility including associated air pollution control equipment
in a manner consistent with good air pollution control practice for
minimizing emissions. Determination of whether acceptable operating and
maintenance procedures are being used will be based on information
available to the Administrator which may include, but is not limited
to, monitoring results, opacity observations, review of operating and
maintenance procedures, and inspection of the source. The provisions
for exemption from compliance during periods of startup, shutdown and
malfunctions provided for in 40 CFR 60.8(c) do not apply to this
subpart.
(c) You are exempt from the obligation to obtain a permit under 40
CFR part 70 or 40 CFR part 71, provided you are not otherwise required
by law to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a).
Notwithstanding the previous sentence, you must continue to comply with
the provisions of this subpart.
Sec. 60.5371b What GHG and VOC standards apply to super-emitter
events?
This section applies to super-emitter events. For purposes of this
section, a super-emitter event is defined as any emissions event that
is located at or near an oil and natural gas facility (e.g., individual
well site, centralized production facility, natural gas processing
plant, or compressor station) and that is detected using remote
detection methods and has quantified emission rate of 100 kg/hr of
methane or greater. Paragraph (a) of this section describes the
qualifications one must meet to apply to be a third-party notifier of
super-emitter events. Paragraph (b) of this section describes the
procedures for certifying third-party notifiers, as well as the
procedures for petitioning the Agency for removal of a third-party
notifier from the list of certified notifiers. Paragraph (c) of this
section contains the required information that must be included in any
notification submitted to the EPA from a certified third-party notifier
and a timetable for notifications. The EPA shall review these
notifications and if the EPA determines the notification is complete
and does not contain information that the EPA finds to be erroneous or
inaccurate to a reasonable degree of certainty, the EPA shall assign
the notification a unique notification identification number, provide
the notification to the owner or operator of the oil and natural gas
facility identified in the notification, and post the notification,
except for the owner/operator attribution, at www.epa.gov/super-emitter. Upon receiving such notification, owners or operators must
take the actions listed in paragraphs (d) and (e) of this section. The
EPA shall post the reports submitted under paragraph (e) of this
section, Sec. 60.5371(b) and Sec. 60.5371a(b) of subparts OOOO and
OOOOa of this part, and applicable State or Federal plan implementing
Sec. 60.5388c(b) of subpart OOOOc of this part, including owner/
operator attributions that have been confirmed by the reports; where
the reporting deadlines have passed but no reports have been received,
the EPA intends to post owner/operator attributions that the EPA
reasonably believes to be accurate. The reports will be publicly
available at www.epa.gov/super-emitter.
(a) Qualifications for third-party notifiers. An entity may apply
to the Administrator under paragraph (b) of this section for approval
as a third-party notifier if it meets the qualifications in this
paragraph (a). The entity must be a person, as defined in 42 U.S.C.
7602(e), excluding the owner or operator of the site where the super-
emitter event is detected, the Administrator, or the delegated
authority. The entity must use a method that has been approved under
Sec. 60.5398b(d) for one of the technologies specified in paragraphs
(a)(1) through (3) of this section.
(1) Satellite detection of methane emissions.
(2) Remote-sensing equipment on aircraft.
(3) Mobile monitoring platforms.
(b) Third-party notifier certification. An entity meeting the
qualifications in paragraph (a) of this section may apply to be
certified as a third-party notifier. Only entities certified as third-
party notifiers may submit information on super-emitter events to the
EPA under paragraph (c) of this section. An entity seeking
certification as a third-party notifier must submit a request to the
Administrator as described in paragraph (b)(1) of this section.
Certified third-party notifiers must follow the recordkeeping
requirements in paragraph (b)(2) of this section; failure to maintain
the required records may result in loss of certification status. The
Administrator will determine whether the request for certification is
adequate and issue an approval or disapproval of the request as
described in paragraph (b)(3) of this section. A certified third-party
notifier must re-apply when material changes are made, as described in
paragraph (b)(4) of this section. A third-party notifier may be removed
from the list of certified notifiers as detailed in paragraph (b)(5) of
this section.
(1) A request to be certified as a third-party notifier must be
submitted to: U.S. EPA, Attn: Leader, Measurement Technology Group,
Mail Drop: E143-02, 109 T.W. Alexander Drive, P.O. Box 12055, RTP, NC
27711. The request must include the supporting information in
paragraphs (b)(1)(i) through (vi) of this section. If your submittal
includes information claimed to be CBI, submit the portion of the
information claimed as CBI to the OAQPS CBI office. The preferred
method to receive CBI is for it to be
[[Page 17049]]
transmitted electronically using email attachments, File Transfer
Protocol, or other online file sharing services. Electronic submissions
must be transmitted directly to the OAQPS CBI Office at the email
address [email protected] and should include clear CBI markings and be
flagged to the attention of the Leader, Measurement Technology Group.
If assistance is needed with submitting large electronic files that
exceed the file size limit for email attachments, and if you do not
have your own file sharing service, please email [email protected] to
request a file transfer link. If you cannot transmit the file
electronically, you may send CBI information through the postal service
to the following address: U.S. EPA, Attn: OAQPS Document Control
Officer and Measurement Technology Group Leader, Mail Drop: C404-02,
109 T.W. Alexander Drive, P.O. Box 12055, RTP, NC 27711. The mailed CBI
material should be double wrapped and clearly marked. Any CBI markings
should not show through the outer envelope.
(i) General identification information for the candidate third-
party notifier requesting certification as a third-party notifier
including the mailing address, the physical address, the name of a
principal officer and an email address for the principal officer, and
name of the certifying official(s) and the certifying official(s)'s
email address.
(ii) Description of the technologies the entity will use to
identify emissions that are 100 kg/hr of methane or greater. At a
minimum, the description must include the following:
(A) Reference to the approval of the method to be used under Sec.
60.5398b(d).
(B) Memorandum of Understanding (MOU) or contracting agreements
with the technology provider(s) that will be used to identify super-
emitter events (if applicable).
(iii) Curriculum vitae of the certifying official(s) detailing
their work history, education, skill set, and training for evaluating
the results of the technologies that will be used to identify super-
emitter events.
(iv) The candidate third-party notifier's standard operating
procedure(s) detailing the procedures and processes for data review. At
a minimum, this must include the following:
(A) Procedures for evaluating the emission data provided by the
technology, including the accuracy of the data and whether the data was
collected in compliance with the method requirements approved under
Sec. 60.5398b(d).
(B) Process for verifying the accuracy of the locality of
emissions.
(C) Process for identifying and verifying the owner or operator of
a site where a super-emitter event occurs, including the source of
information that will be used to make the identification.
(D) Procedures for handling potentially erroneous data.
(v) Description of the systems used for maintaining essential
records identified in paragraph (b)(2) of this section.
(vi) A Quality Management Plan consistent with EPA's Quality
Management Plan Standard (Directive No: CIO 2015-S-01.0, January 17,
2023) for Non-EPA organizations.
(2) Certified third-party notifiers must maintain the records
identified in paragraphs (b)(2)(i) through (iii) of this section. Upon
request, the certified third-party notifier must make these records
available to the Administrator for review.
(i) Records for all surveys conducted by or sponsored by the
certified third-party notifier, including outputs (e.g., emission
rates, locations) and associated data needed to confirm the accuracy of
the outputs and the performance of the method used.
(ii) Records of all notifications of super-emitter events provided
to the EPA. Retain any information collected that is used to evaluate
the validity of a super-emitter event but which is not required to be
submitted as part of the notification.
(iii) A copy of any records and/or identification of any databases
used in the identification of the potential owner or operator of the
site where a super-emitter event occurred.
(3) Based upon the Administrator's judgment of the completeness,
reasonableness, and accuracy of the entity's request, the Administrator
will approve or disapprove the entity for certification as a third-
party notifier. For those third parties that receive approval, the
Administrator will provide you a unique notifier ID. Starting 15
calendar days after being approved as a certified third-party notifier,
the notifier may submit notifications of super-emitter events to the
EPA as outlined in paragraph (c) of this section. All approved third-
party notifiers shall be posted on the EPA website at www.epa.gov/emc-third-party-certifications.
(4) If a third-party notifier intends to make any significant
changes to their procedures for identifying super-emitter events,
meaning a change to the technology used to identify super-emitter
events or a change to the certifying official(s), you must request an
amendment to your certification and be recertified under paragraph
(b)(1) of this section.
(5) A certified third-party notifier may be removed from the list
of approved third-party notifiers in any of the circumstances listed in
paragraphs (b)(5)(i) through (iii) of this section. Entities removed
from the list of approved third-party notifiers cannot submit
notifications to the EPA under paragraph (c) of this section. Entities
may be added back to the list of approved third-party notifiers by
receiving approval of a new certification request submitted under
paragraph (b)(1) of this section.
(i) If a certified third-party notifier has made material changes
to their procedures for identifying super-emitter events, meaning a
change to the technology used to identify super-emitter events or a
change to the certifying official, without seeking recertification.
(ii) If the Administrator finds that the certified third-party
notifier has persistently submitted data with significant errors (e.g.,
misidentification of the owner or operator) or if the third-party
notifier has engaged in illegal activity during the during the
assessment of a super-emitter event (e.g., trespassing).
(iii) If the Administrator receives a petition from an owner or
operator to remove a certified third-party notifier from the list of
approved notifiers, as set forth below, and the Administrator makes the
finding noted below. Any owner or operator that has received more than
three notices with meaningful and/or demonstrable errors of a super-
emitter event at the same oil and natural gas facility (e.g., a well
site, centralized production facility, natural gas processing plant, or
compressor station) from the EPA that were submitted to the EPA by the
same third party may petition the Administrator to remove that third
party from the list of approved notifiers, by providing evidence that
the claimed super-emitter events did not occur. Such petitions may not
be used to dispute the methodology that were approved through the
process described in Sec. 60.5398b(d). The third party will be given
the opportunity to respond to the petition. If, in the Administrator's
discretion, the Administrator determines that the three notifications
contain meaningful and/or demonstrable errors, including that the third
party did not use the methane detection technology identified in their
submittal, the emissions event did not exceed the threshold of 100 kg/
hr of methane, the third-party knowingly misidentified the date of a
super-emitter event, the third party may be removed by the
Administrator from the list of
[[Page 17050]]
approved notifiers. The failure of the owner or operator to find the
source of the super-emitter event upon subsequent inspection shall not
be proof, by itself, of demonstrable error.
(c) Notification of super-emitter events. Notifications must be
submitted to the EPA using the Super-Emitter Program Portal (available
at http://www.epa.gov/super-emitter). Notifications must contain the
information specified in paragraphs (c)(1) through (8) of this section.
The EPA will review the submitted notifications of super-emitter events
for completeness and accuracy. If the EPA determines that the
notification is complete and does not contain information that the EPA
finds to be inaccurate to a reasonable degree of certainty, the EPA
will assign the notification a unique notification report
identification number, make the notification publicly available at
www.epa.gov/super-emitter, and provide the super-emitter event
notification to the owner or operator identified in the notification.
The EPA will not review and provide the notification to an owner or
operator if the notification is submitted after the date specified in
paragraph (c)(9) of this section.
(1) Unique Third-Party Notifier ID.
(2) Date of detection of the super-emitter event. If multiple
surveys were required to detect and quantify the super-emitter event,
the date of detection is the date of the final survey.
(3) Location of super-emitter event in latitude and longitude
coordinates in decimal degrees to an accuracy and precision of four (4)
decimals of a degree using the North American Datum of 1983.
(4) Owner(s) or operator(s) of any oil and natural gas facility
(e.g., individual well site, centralized production facility, natural
gas processing plant, or compressor station) within 50 meters of the
latitude and longitude coordinates of the super-emitter event.
(5) Identification of the detection technology and reference to the
approval of the technology used under Sec. 60.5398b(d).
(6) Documentation (e.g., imagery) depicting the detected super-
emitter event and the site from which the super-emitter event was
detected.
(7) Quantified emission rate of the super-emitter event in kg/hr
and associated uncertainty bounds (e.g., 1-[sigma]) of the measurement.
(8) Attestation statement, signed and dated by the third-party
notifier certifying official submitting the data collected. The
attestation must state: ``I certify that I have been approved to be a
notifier under 40 CFR 60.5371b(b) and that the emission detection
information included in this notification was collected and interpreted
as described in this notification. Based on my professional knowledge
and experience, and inquiry of personnel involved in the collection and
analysis of the data, the certification submitted herein is true,
accurate, and complete.''
(9) The third-party notifier must submit the notification within 15
calendar days of the date of detection of the super-emitter event.
(d) Identification of super-emitter events. Within 5 calendar days
of receiving a notification from the EPA of a super-emitter event, the
owner or operator of an oil and natural gas facility (e.g., a well
site, centralized production facility, natural gas processing plant, or
compressor station) must initiate a super-emitter event investigation.
The investigation must be conducted in accordance with this paragraph
(d) and completed within 15 days of receiving the notification from the
EPA. The owner or operator must maintain records of its super-emitter
event investigations and report the findings from the investigation
according to the requirements in paragraph (e) of this section.
(1) If you do not own or operate an oil and natural gas facility
within 50 meters from the latitude and longitude provided in the
notification, report this result to the EPA under paragraph (e) of this
section. Your super-emitter event investigation is deemed complete.
(2) If you own or operate an oil and natural gas facility within 50
meters from the latitude and longitude provided in the notification,
you must investigate to determine the source of super-emitter event.
The investigation may include but is not limited to the actions
specified below in paragraphs (d)(6)(i) through (v) of this section.
(i) Review any maintenance activities (e.g., liquids unloading) or
process activities from the affected facilities subject to regulation
under this subpart, starting from the date of detection of the super-
emitter event as identified in the notification, until the date of
investigation, to determine if the activities indicate any potential
source(s) of the super-emitter event emissions.
(ii) Review all monitoring data from control devices (e.g., flares)
from the affected facilities subject to regulation under this subpart
from the initial date of detection of the super-emitter event as
identified in the notification until the date of receiving the
notification from the EPA. Identify any malfunctions of control devices
or periods when the control devices were not in compliance with
applicable requirements and that indicate a potential source of the
super-emitter event emissions.
(iii) If you conducted a fugitive emissions survey or periodic
screening event in accordance with Sec. 60.5397b or Sec. 60.5398b(b)
between the initial date of detection of the super-emitter event as
identified in the notification and the date the notification from the
EPA was received, review the results of the survey to identify any
potential source(s) of the super-emitter event emissions.
(iv) If you conduct continuous monitoring with advanced methane
detection technology in accordance with Sec. 60.5398b(c), review the
monitoring data collected on or after the initial date of detection of
the super-emitter event as identified in the notification, until the
date of receiving the notification from the EPA.
(v) Screen the entire oil and natural gas facility with OGI, Method
21 of appendix A-7 to this part, or an alternative test method(s)
approved per Sec. 60.5398b(d), to determine if a super-emitter event
is present.
(3) If the source of the super-emitter event was found to be from
fugitive emission components at a well site, centralized production
facility, or compressor station subject to this subpart, you must
comply with the repair requirements under Sec. 60.5397b and the
associated recordkeeping and reporting requirements under Sec.
60.5420b(b)(9) and (c)(14).
(e) Super-emitter event report. You must submit the results of the
super-emitter event investigation conducted under paragraph (d) of this
section to the EPA in accordance with paragraph (e)(1) of this section.
If the super-emitter event (i.e., emission at 100 kg/hr of methane or
more) is ongoing at the time of the initial report, submit the
additional information in accordance with paragraph (e)(2) of this
section. You must attest to the information included in the report as
specified in paragraph (e)(3) of this section.
(1) Within 15 days of receiving a notification from the EPA under
paragraph (c) of this section, you must submit a report of the super-
emitter event investigation conducted under paragraph (d) of this
section through the Super-Emitter Program Portal. You must include the
applicable information in paragraphs (e)(1)(i) through (viii) of this
section in the report. If you have identified a demonstrable error in
the notification, the report may include a statement of the
demonstrable error.
(i) Notification Report ID of the super-emitter event notification.
[[Page 17051]]
(ii) Identification of whether you are the owner or operator of an
oil and natural gas facility within 50 meters from the latitude and
longitude provided in the EPA notification. If you do not own or
operate an oil and natural gas facility within 50 meters from the
latitude and longitude provided in the EPA notification, you are not
required to report the information in paragraphs (e)(1)(iii) through
(viii) of this section.
(iii) General identification information for the facility,
including, facility name, the physical address, applicable ID Number
(e.g., EPA ID Number, API Well ID Number), the owner or operator or
responsible official (where applicable) and their email address.
(iv) Identification of whether there is an affected facility or
associated equipment subject to regulation under this subpart at this
oil and natural gas facility.
(v) Indication of whether you were able to identify the source of
the super-emitter event. If you indicate you were unable to identify
the source of the super-emitter event, you must certify that all
applicable investigations specified in paragraph (d)(6)(i) through(v)
of this section have been conducted for all affected facilities and
associated equipment subject to this subpart that are at this oil and
natural gas facility, and you have determined that the affected
facilities and associated equipment are not the source of the super-
emitter event. If you indicate that you were not able to identify the
source of the super-emitter event, you are not required to report the
information in paragraphs (e)(1)(vi) through (viii) of this section.
(vi) The source(s) of the super-emitter event.
(vii) Identification of whether the source of the super-emitter
event is equipment subject to regulation under this subpart. If the
source of the super-emitter event is equipment subject to regulation
under this subpart, identify the applicable regulation(s) under this
subpart.
(viii) Indication of whether the super-emitter event is ongoing at
the time of the initial report submittal (i.e., emissions at 100 kg/hr
of methane or more).
(A) If the super-emitter event is not ongoing at the time of the
initial report submittal, provide the actual (or if unknown) estimated
date and time the super-emitter event ended.
(B) If the super-emitter event is ongoing at the time of the
initial report submittal, provide a short narrative of your plan to end
the super-emitter event, including the targeted end date for the
efforts to be completed and the super-emitter event ended.
(2) If the super-emitter event is ongoing at the time of the
initial report submittal, within 5 business days of the date the super-
emitter event ends, you must update your initial report through the
Super-Emitter Program Portal to provide the end date and time of the
super-emitter event.
(3) You must sign the following attestation when submitting data
into the Super-Emitter Program Portal: ``I certify that the information
provided in this report regarding the specified super-emitter event was
prepared under my direction or supervision. I further certify that the
investigations were conducted, and this report was prepared pursuant to
the requirements of Sec. 60.5371b(d) and (e). Based on my professional
knowledge and experience, and inquiry of personnel involved in the
assessment, the certification submitted herein is true, accurate, and
complete. I am aware that knowingly false statements may be punishable
by fine or imprisonment.''
Sec. 60.5375b What GHG and VOC standards apply to well completions
at well affected facilities?
(a) You must comply with the requirements of paragraphs (a)(1)
through (3) of this section for each well completion operation with
hydraulic fracturing and refracturing at a well affected facility,
except as provided in paragraphs (f), (g) and (h) of this section. You
must maintain a log as specified in paragraph (b) of this section.
(1) For each stage of the well completion operation, follow the
requirements specified in paragraphs (a)(1)(i) through (iii) of this
section.
(i) During the initial flowback stage, route the flowback into one
or more well completion vessels or storage vessels and commence
operation of a separator unless it is technically infeasible for a
separator to function. The separator may be a production separator, but
the production separator also must be designed to accommodate flowback.
Any gas present in the initial flowback stage is not subject to control
under this section.
(ii) During the separation flowback stage, route all recovered
liquids from the separator to one or more well completion vessels or
storage vessels, re-inject the recovered liquids into the well or
another well, or route the recovered liquids to a collection system.
Route the recovered gas from the separator into a gas flow line or
collection system, re-inject the recovered gas into the well or another
well, use the recovered gas as an onsite fuel source, or use the
recovered gas for another useful purpose that a purchased fuel or raw
material would serve. If it is technically infeasible to route the
recovered gas as required above, follow the requirements of paragraph
(a)(2) of this section. If, at any time during the separation flowback
stage, it is technically infeasible for a separator to function, you
must comply with paragraph (a)(1)(i) of this section.
(iii) You must have the separator onsite or otherwise available for
use at a centralized production facility or well pad that services the
well completion affected facility during well completions. The
separator must be available and ready for use to comply with paragraph
(a)(1)(ii) of this section during the entirety of the flowback period,
except as provided in paragraphs (a)(1)(iii)(A) through (C) of this
section.
(A) A well that is not hydraulically fractured or refractured with
liquids, or that does not generate condensate, intermediate hydrocarbon
liquids, or produced water such that there is no liquid collection
system at the well site is not required to have a separator onsite.
(B) If conditions allow for liquid collection, then the operator
must immediately stop the well completion operation, install a
separator, and restart the well completion operation in accordance with
paragraph (a)(1) of this section.
(C) The owner or operator of a well that meets the criteria of
paragraph (a)(1)(iii)(A) or (B) of this section must submit the report
in Sec. 60.5420b(b)(2) and maintain the records in Sec.
60.5420b(c)(1)(iii).
(2) If it is technically infeasible to route the recovered gas as
required in Sec. 60.5375b(a)(1)(ii), then you must capture and direct
recovered gas to a completion combustion device, except in conditions
that may result in a fire hazard or explosion, or where high heat
emissions from a completion combustion device may negatively impact
tundra, permafrost or waterways. Completion combustion devices must be
equipped with a reliable continuous pilot flame.
(3) You have a general duty to safely maximize resource recovery
and minimize releases to the atmosphere during flowback and subsequent
recovery.
(b) You must maintain a log for each well completion operation at
each well affected facility. The log must be completed on a daily basis
for the duration of the well completion operation and must contain the
records specified in Sec. 60.5420b(c)(1)(iii).
[[Page 17052]]
(c) You must demonstrate initial compliance with the well
completion operation standards that apply to well affected facilities
as required by Sec. 60.5410b(a).
(d) You must demonstrate continuous compliance with the well
completion operation standards that apply to well affected facilities
as required by Sec. 60.5415b(a).
(e) You must perform the required notification, reporting and
recordkeeping as required by Sec. 60.5420b(a)(2), (b)(1) and (2), and
(c)(1).
(f) For each well affected facility specified in paragraphs (f)(1)
and (2) of this section, you must comply with the requirements of
paragraphs (f)(3) and (4) of this section.
(1) Each well completion operation with hydraulic fracturing at a
wildcat or delineation well.
(2) Each well completion operation with hydraulic fracturing at a
non-wildcat low pressure well or non-delineation low pressure well.
(3) You must comply with paragraph (f)(3)(i) of this section. You
must also comply with paragraph (b) of this section. As an alternative,
if you are able to operate a separator, you may comply with paragraph
(b) and (f)(3)(ii) of this section. Compliance with paragraphs
(f)(3)(i) or (ii) of this section is not required if you meet the
requirements of paragraph (g) of this section.
(i) Route all flowback to a completion combustion device, except in
conditions that may result in a fire hazard or explosion, or where high
heat emissions from a completion combustion device may negatively
impact tundra, permafrost or waterways. Completion combustion devices
must be equipped with a reliable continuous pilot flame.
(ii) Route all flowback into one or more well completion vessels
and commence operation of a separator unless it is technically
infeasible for a separator to function. You must have the separator
onsite or otherwise available for use at the wildcat well, delineation
well, or low pressure well. The separator must be available and ready
for use to comply with paragraph (f)(3)(ii) of this section during the
entirety of the flowback period. Any gas present in the flowback before
the separator can function is not subject to control under this
section. Capture and direct recovered gas to a completion combustion
device, except in conditions that may result in a fire hazard or
explosion, or where high heat emissions from a completion combustion
device may negatively impact tundra, permafrost, or waterways.
Completion combustion devices must be equipped with a reliable
continuous pilot flame.
(4) You must submit the notification as specified in Sec.
60.5420b(a)(2), submit annual reports as specified in Sec.
60.5420b(b)(1) and (2) and maintain records specified in Sec.
60.5420b(c)(1)(i) through (iii) and (vii) for each wildcat well, each
delineation well, and each low pressure well.
(g) For each well completion affected facility with less than 300
scf of gas per stock tank barrel of oil produced, you must comply with
paragraphs (g)(1) and (2) of this section.
(1) You must maintain records specified in Sec.
60.5420b(c)(1)(vi).
(2) You must submit reports specified in Sec. 60.5420b(b)(1) and
(2).
(h) A well modified in accordance with Sec. 60.5365b(a)(1)(ii)
(i.e., an existing well that is hydraulically refractured) is exempt
from the well completion operation standards in paragraphs (b) through
(d) of this section, when the requirements of paragraphs (a)(1) through
(3) of this section are met.
Sec. 60.5376b What GHG and VOC standards apply to gas well liquids
unloading operations at well affected facilities?
(a) General requirements. You must comply with the requirements of
this section for each gas well liquids unloading operation at your gas
well affected facility as specified by paragraphs (a)(1) and (2) of
this section. You have a general duty to safely maximize resource
recovery and minimize releases to the atmosphere during gas well
liquids unloading operations.
(1) If a gas well liquids unloading operation technology or
technique employed does not result in venting of methane and VOC
emissions to the atmosphere, you must comply with the requirements
specified in paragraphs (a)(1)(A) and (B). If an unplanned venting
event occurs, you must meet the requirements specified in paragraphs
(c) through (f) of this section.
(A) Comply with the recordkeeping requirements specified in Sec.
60.5420b(c)(2)(i).
(B) Submit the information specified in Sec. 60.5420b(b)(1) and
(b)(3)(i) in the annual report.
(2) If a gas well liquids unloading operation technology or
technique vents methane and VOC emissions to the atmosphere, you must
comply with the requirements specified in paragraphs (b) and (c), or
paragraph (g) of this section.
(b) Work Practice Standards. If a gas well liquids unloading
operation employs a technology or technique that vents methane and VOC
emissions to the atmosphere, you must comply with the requirements in
paragraphs (b)(1) through (3) and paragraphs (c) through (f) of this
section.
(1) Employ best management practices to minimize venting of methane
and VOC emissions as specified in paragraph (c) of this section for
each gas well liquids unloading operation.
(2) Comply with the recordkeeping requirements specified in Sec.
60.5420b(c)(2)(ii).
(3) Submit the information specified in Sec. 60.5420b(b)(1) and
(b)(3)(ii) in the annual report.
(c) Best management practice requirements. For each gas well
liquids unloading operation complying with paragraphs (a)(2) and (b) of
this section, you must develop, maintain, and follow a best management
practice plan to minimize venting of methane and VOC emissions to the
maximum extent possible from each gas well liquids unloading operation.
This best management practice plan must meet the minimum criteria
specified in paragraphs (c)(1) through (4) of this section.
(1) Include steps that create a differential pressure to minimize
the need to vent a well to unload liquids,
(2) Include steps to reduce wellbore pressure as much as possible
prior to opening the well to the atmosphere,
(3) Unload liquids through the separator where feasible, and
(4) Close all wellhead vents to the atmosphere and return the well
to production as soon as practicable.
(d) Initial compliance. You must demonstrate initial compliance
with the standards that apply to well liquids unloading operations at
your well affected facilities as required by Sec. 60.5410b(b).
(e) Continuous compliance. You must demonstrate continuous
compliance with the standards that apply to well liquids unloading
operations at your well affected facilities as required by Sec.
60.5415b(b).
(f) Recordkeeping and reporting. You must perform the required
notification, recordkeeping and reporting requirements as specified in
Sec. 60.5420b(b)(3) and (c)(2).
(g) Other compliance options. Reduce methane and VOC emissions from
well affected facility gas wells that unload liquids by 95.0 percent by
complying with the requirements specified in paragraphs (g)(1) and (2)
of this section and meeting the initial and continuous compliance and
recordkeeping and reporting requirements specified in paragraphs (g)(3)
through (5) of this section.
(1) You must route emissions through a closed vent system to a
control device
[[Page 17053]]
that meets the conditions specified in Sec. 60.5412b.
(2) You must route emissions through a closed vent system that
meets the requirements of Sec. 60.5411b(a) and (c).
(3) You must demonstrate initial compliance with standards that
apply to well affected facility gas well liquids unloading as required
by Sec. 60.5410b(b).
(4) You must demonstrate continuous compliance with standards that
apply to well affected facility gas well liquids unloading as required
by Sec. 60.5415b(f).
(5) You must perform the reporting as required by Sec.
60.5420b(b)(1), (3), and (11) through (13), as applicable, and the
recordkeeping as required by Sec. 60.5420b(c)(2), (8), and (10)
through (13), as applicable.
Sec. 60.5377b What GHG and VOC standards apply to associated gas
wells at well affected facilities?
(a) You must comply with either paragraph (a)(1), (2), (3), or (4)
of this section for each associated gas well upon startup and at all
times, except as provided in paragraphs (b) through (f) of this
section. You must also comply with paragraphs (h), (i), and (j) of this
section.
(1) Recover the associated gas from the separator and route the
recovered gas into a gas gathering flow line or collection system to a
sales line.
(2) Recover the associated gas from the separator and use the
recovered gas as an onsite fuel source.
(3) Recover the associated gas from the separator and use the
recovered gas for another useful purpose that a purchased fuel or raw
material would serve.
(4) Recover the associated gas from the separator and reinject the
recovered gas into the well or inject the recovered gas into another
well.
(b) For associated gas wells that commenced construction between
May 7, 2024 and May 7, 2026, you can comply with the requirements in
paragraph (f) of this section continually upon startup instead of
paragraph (a) of this section until May 7, 2026 if you demonstrate and
certify that it is not feasible to comply with paragraphs (a)(1), (2),
(3), and (4) of this section due to technical reasons in accordance
with paragraph (g) of this section. After May 7, 2026 you must
continually comply with paragraph (a) of this section at all times.
(c) For associated gas wells that commenced construction between
December 6, 2022, and May 7, 2024, and for associated gas wells that
undergo reconstruction or modification after December 6, 2022, you can
comply with the requirements in paragraph (f) of this section instead
of paragraph (a) of this section if you demonstrate and certify that it
is not feasible to comply with paragraph (a)(1), (2), (3), and (4) of
this section due to technical reasons in accordance with paragraph (g)
of this section. Associated gas wells that are modified or
reconstructed must comply with paragraph (a) or (f) of this section
upon startup and at all times thereafter.
(d) If you are complying with paragraph (a) of this section, you
may temporarily route the associated gas to a flare or control device
that achieves a 95.0 percent reduction in VOC and methane emissions in
the situations and for the durations identified in paragraphs (d)(1),
(2), (3), or (4) of this section. The associated gas must be routed
through a closed vent system that meets the requirements of Sec.
60.5411b(a) and (c) and the control device must meet the conditions
specified in Sec. 60.5412b during the period when the associated gas
is routed to the flare. Records must be kept of all instances in which
associated gas is temporarily routed to a flare or to a control device
in accordance with Sec. 60.5420b(c)(3)(i)(B) and reported in the
annual report in accordance with Sec. 60.5420b(b)(4)(i)(B).
(1) During a malfunction or incident that endangers the safety of
operator personnel or the public you are allowed to route to a flare or
control device for 24 hours or less per incident.
(2) During repair, maintenance including blow downs, a production
test, or commissioning, you are allowed to route to a flare or control
device for 24 hours or less per incident.
(3) For wells complying with paragraph (a)(1) of this section,
during a temporary interruption in service from the gathering or
pipeline system you are allowed to route to a flare or route to a
control device for the duration of the temporary interruption not to
exceed 30 days per incident.
(4) During periods when the composition of the associated gas does
not meet pipeline specifications for sources complying with paragraph
(a)(1) of this section, or when the composition of the associated gas
does not meet the quality requirements for use as a fuel for sources
complying with paragraph (a)(2) of this section, or when the
composition of the associated gas does not meet the quality
requirements for another useful purpose for sources complying with
paragraph (a)(3) of this section, you are allowed to route to a flare
or control device until the associated gas meets the required
specifications or for 72 hours per incident, whichever is less.
(e) If you are complying with paragraph (a), (d), or (f) of this
section, you may vent the associated gas in the situations and for the
durations identified in paragraphs (e)(1), (2), or (3) of this section
per incident. The cumulative period of venting must not exceed 24 hours
for any calendar year. Records must be kept of all venting instances in
accordance with Sec. 60.5420b(c)(3)(ii) and reported in the annual
report in accordance with Sec. 60.5420b(b)(4)(ii).
(1) For up to 12 hours per incident to protect the safety of
personnel.
(2) For up to 30 minutes per incident during bradenhead monitoring.
(3) For up to 30 minutes per incident during a packer leakage test.
(f) You must route the associated gas to a control device that
reduces methane and VOC emissions by at least 95.0 percent. The
associated gas must be routed through a closed vent system that meets
the requirements of Sec. 60.5411b(a) and (c) and the control device
must meet the conditions specified in Sec. 60.5412b.
(1) For associated gas wells identified in paragraph (b) of this
section, you can comply with the requirements in paragraph (f) of this
section for up to a one year period if you demonstrate and certify that
it is not feasible to comply with paragraph (a)(1), (2), (3), and (4)
of this section due to technical reasons in accordance with paragraph
(g) of this section. This allowance is renewable each year with an
updated technical infeasibility demonstration and certification in
accordance with paragraph (g) of this section. Associated gas wells
identified in paragraph (b) of this section are not allowed to comply
with the requirements in paragraph (f) of this section after May 7,
2026.
(2) For associated gas wells identified in paragraph (c) of this
section, you can comply with the requirements in paragraph (f) of this
section for up to a one year period if you demonstrate and certify that
it is not feasible to comply with paragraph (a)(1), (2), (3), and (4)
of this section due to technical reasons in accordance with paragraph
(g) of this section. This allowance is renewable each year with an
updated technical infeasibility demonstration and certification in
accordance with paragraph (g) of this section.
(g) For affected sources identified in paragraphs (b) and (c) of
this section that are complying with the requirements in paragraph (f)
of this section, you must demonstrate that it is not feasible to comply
with paragraph (a)(1), (2), (3), and (4) of this section due to
technical reasons by providing a detailed analysis documenting and
certifying the technical reasons for this infeasibility.
(1) The demonstration must address the technical infeasibility for
all options
[[Page 17054]]
identified in (a)(1), (2), (3), and (4) of this section.
(2) This demonstration must be certified by a professional engineer
or another qualified individual with expertise in the uses of
associated gas. The following certification, signed and dated by the
qualified professional engineer or other qualified individual shall
state: ``I certify that the assessment of technical and safety
infeasibility was prepared under my direction or supervision. I further
certify that the assessment was conducted, and this report was prepared
pursuant to the requirements of Sec. 60.5377b(b)(1). Based on my
professional knowledge and experience, and inquiry of personnel
involved in the assessment, the certification submitted herein is true,
accurate, and complete.''
(3) This demonstration and certification are valid for no more than
12 months. You must re-analyze the feasibility of complying with
paragraphs (a)(1), (2), (3), and (4) of this section and finalize a new
demonstration and certification each year.
(4) Documentation of these demonstrations, along with the
certifications, must be maintained in accordance with Sec.
60.5420b(c)(3)(iii) and submitted in annual reports in accordance with
Sec. 60.5420b(b)(4)(iii)(C) and (D).
(h) You must demonstrate initial compliance with the standards that
apply to associated gas wells as required by Sec. 60.5410b(c).
(i) You must demonstrate continuous compliance with the standards
that apply to associated gas wells as required by Sec. 60.5415b(c).
(j) You must perform the reporting as required by Sec.
60.5420b(b)(1) and (4), and (b)(11) and (12), as applicable; and the
recordkeeping as required by Sec. 60.5420b(c)(3) and (8), and (c)(10)
through (13), as applicable.
Sec. 60.5380b What GHG and VOC standards apply to centrifugal
compressor affected facilities?
Each centrifugal compressor affected facility must comply with the
GHG and VOC standards in paragraphs (a) through (d) of this section.
(a) Each centrifugal compressor affected facility that uses wet
seals must comply with the GHG and VOC standards in paragraphs (a)(1),
(2), or (3) of this section. Each self-contained wet seal compressor,
and each centrifugal compressor on the Alaska North Slope equipped with
sour seal oil separator and capture system, must comply with the GHG
and VOC standards in paragraphs (a)(1) and (2) of this section, or one
of the alternatives in (a)(3) through (5) of this section, as
applicable, and (a)(8) of this section. Each centrifugal compressor
affected facility that uses dry seals must comply with paragraphs
(a)(6) through (8) of this section, or with of the alternatives in
paragraph (a)(9) of this section.
(1) You must reduce methane and VOC emissions from each centrifugal
compressor wet seal fluid degassing system by 95.0 percent.
(2) If you use a control device to reduce emissions, you must equip
the wet seal fluid degassing system with a cover that meets the
requirements of Sec. 60.5411b(b). The cover must be connected through
a closed vent system that meets the requirements of Sec. 60.5411b(a)
and (c) and the closed vent system must be routed to a control device
that meets the conditions specified in Sec. 60.5412b.
(3) As an alternative to routing the closed vent system to a
control device, you may route the closed vent system to a process. If
you route the emissions to a process, you must equip the wet seal fluid
degassing system with a cover that meets the requirements of Sec.
60.5411b(b). The cover must be connected through a closed vent system
that meets the requirements of Sec. 60.5411b(a) and (c).
(4) If you own or operate a self-contained wet seal centrifugal
compressor you may comply with the GHG and VOC requirements as
specified in paragraph (a)(4)(i) through (iii) of this section, using
volumetric flow rate as a surrogate, in lieu of meeting the
requirements specified in paragraphs (a)(1) and (2) of this section.
You must determine the volumetric flow rate in accordance with
paragraph (a)(7)(i) of this section.
(i) The volumetric flow rate must not exceed 3 standard cubic feet
per minute (scfm) per seal. If the individual seals are manifolded to a
single open-ended vent line, the volumetric flow rate must not exceed
the sum of the individual seals multiplied by 3 scfm. If the volumetric
flow rate, measured in accordance with paragraph (a)(7)(i) of this
section exceeds 3 scfm multiplied by the number of wet seals connected
to the vent, the seals connected to the measured vent must be repaired
as provided in paragraph (a)(8) of this section.
(ii) You must conduct your first volumetric flow rate measurement
from your self-contained wet seal compressor on or before 8,760 hours
of operation after May 7, 2024 or on or before 8,760 hours of operation
after startup, whichever date is later.
(iii) You must conduct subsequent volumetric flow rate measurements
from your self-contained wet seal centrifugal compressor on or before
8,760 hours of operation after the previous measurement which
demonstrates compliance with the 3 scfm volumetric flow rate per seal.
If the individual seals are manifolded to a single open-ended vent
line, the volumetric flow rate must not exceed the sum of the
individual seals multiplied by 3 scfm.
(5) If you own or operate a centrifugal compressor on the Alaska
North Slope equipped with seal oil separator and capture system, you
may comply with the GHG and VOC requirements specified in paragraphs
(a)(5)(i) through (iii) of this section using volumetric flow rate as a
surrogate, in lieu of meeting the requirements specified in paragraphs
(a)(1) and (2). You must determine the volumetric flow rate in
accordance with paragraph (a)(7)(ii) of this section.
(i) The volumetric flow rate per seal must not exceed 9 scfm per
seal. If the individual seals are manifolded to a single open-ended
vent line, the volumetric flow rate must not exceed the sum of the
individual seals multiplied by 9 scfm. If the volumetric flow rate,
measured in accordance with paragraph (a)(7)(ii) of this section
exceeds 9 scfm multiplied by the number of wet seals connected to the
vent, the seals connected to the measured vent must be repaired as
provided in paragraph (a)(8) of this section.
(ii) You must conduct your first volumetric flow rate measurement
from your Alaska North Slope centrifugal compressor equipped with a
sour seal oil separator and capture system on or before 8,760 hours of
operation after May 7, 2024 or on or before 8,760 hours of operation
after startup, whichever date is later.
(iii) You must conduct subsequent volumetric flow rate measurements
from your Alaska North Slope centrifugal compressor equipped with sour
seal separator and capture system on or before 8,760 hours of operation
after the previous measurement which demonstrates compliance with the 9
scfm volumetric flow rate per seal. If the individual seals are
manifolded to a single open-ended vent line, the volumetric flow rate
must not exceed the sum of the individual seals multiplied by 9 scfm.
(6) If you own or operate a centrifugal compressor equipped with
dry seals, you must comply with the GHG and VOC requirements as
specified in paragraphs (a)(6)(i) through (iii), using volumetric flow
rate as a surrogate. You must determine the volumetric flow rate in
accordance with paragraph (a)(7)(iii) of this section.
[[Page 17055]]
(i) The volumetric flow rate per seal must not exceed 10 standard
cubic feet per minute (scfm) per seal. If the individual seals are
manifolded to a single open-ended vent line, the volumetric flow rate
must not exceed the sum of the individual seals multiplied by 10 scfm.
If the volumetric flow rate, measured in accordance with paragraph
(a)(7)(iii) of this section exceeds 10 scfm multiplied by the number of
dry seals connected to the vent, the seals connected to the measured
vent must be repaired as provided in paragraph (a)(8) of this section.
(ii) You must conduct your first volumetric flow rate measurement
from your centrifugal compressor equipped with a dry seal on or before
8,760 hours of operation after May 7, 2024 or on or before 8,760 hours
of operation after startup, whichever date is later.
(iii) You must conduct subsequent volumetric flow rate measurements
from your centrifugal compressor equipped with dry seals on or before
8,760 hours of operation after the previous measurement which
demonstrates compliance with the 10 scfm volumetric flow rate per seal.
If the individual seals are manifolded to a single open-ended vent
line, the volumetric flow rate must not exceed the sum of the
individual seals multiplied by 10 scfm.
(7) You must determine the volumetric flow rate for your
centrifugal compressor, as specified in paragraphs (a)(7)(i) through
(iii) of this section.
(i) You must determine the volumetric flow rate from your self-
contained wet seal centrifugal compressor wet seal as specified in
paragraph (a)(7)(i)(A) or (B) of this section. If the volumetric flow
rate exceeds 3 scfm multiplied by the number of wet seals connected to
the vent, the wet seals connected to the measured vent must be repaired
as provided in paragraph (a)(8) of this section.
(A) For self-contained wet seal centrifugal compressors in
operating-mode or in standby-pressurized-mode, determine volumetric
flow rate at standard conditions from each self-contained wet seal
centrifugal compressor wet seal using one of the methods specified in
paragraphs (a)(7)(i)(A)(1) through (3) of this section.
(1) You may choose to use any of the methods set forth in Sec.
60.5386b(a) to screen for leaks/emissions. For the purposes of this
paragraph, when using any of the methods in Sec. 60.5386b(a),
emissions are detected whenever a leak is detected according to the
method. If emissions are detected using the methods set forth in Sec.
60.5386b(a), then you must use one of the methods specified in
paragraph (a)(7)(i)(A)(2) or (3) of this section to determine the
volumetric flow rate. If emissions are not detected using the methods
in Sec. 60.5386b(a), then you may assume that the volumetric emissions
are zero.
(2) Use a temporary or permanent flow meter according to methods
set forth in Sec. 60.5386b(b).
(3) Use a high-volume sampler according to the method set forth in
Sec. 60.5386b(c).
(B) For conducting measurements on manifolded groups of self-
contained wet seal centrifugal compressor seals, you must determine the
volumetric flow rate from the self-contained wet seal centrifugal
compressor seal as specified in paragraph (a)(7)(i)(B)(1) or (2) of
this section.
(1) Measure at a single point in the manifold downstream of all
self-contained wet seal centrifugal compressor seal inputs and, if
practical, prior to comingling with other non-compressor emission
sources.
(2) Determine the volumetric flow rate at standard conditions from
the common stack using one of the methods specified in paragraph
(a)(7)(i)(A)(1) through (3) of this section.
(ii) You must determine the volumetric flow rate from your
centrifugal compressor on the Alaska North Slope equipped with sour
seal oil separator and capture system as specified in paragraph
(a)(7)(ii)(A) or (B) of this section. If the volumetric flow rate
exceeds 9 scfm multiplied by the number of wet seals connected to the
vent, the wet seals connected to the measured vent must be repaired as
provided in paragraph (a)(8) of this section.
(A) For centrifugal compressors in operating-mode or in standby-
pressurized-mode, determine volumetric flow rate at standard conditions
from each centrifugal compressor on the Alaska North Slope equipped
with a sour seal oil separator and capture system using one of the
methods specified in paragraphs (a)(7)(ii)(A)(1) through (3) of this
section.
(1) You may choose to use any of the methods set forth in Sec.
60.5386b(a) to screen for leaks/emissions. For the purposes of this
paragraph, when using any of the methods in Sec. 60.5386b(a),
emissions are detected whenever a leak is detected according to the
method. If emissions are detected using the methods set forth in Sec.
60.5386b(a), then you must use one of the methods specified in
paragraph (a)(7)(ii)(A)(2) or (3) of this section to determine the
volumetric flow rate. If emissions are not detected using the methods
in Sec. 60.5386b(a), then you may assume that the volumetric emissions
are zero.
(2) Use a temporary or permanent flow meter according to methods
set forth in Sec. 60.5386b(b).
(3) Use a high-volume sampler according to the method set forth in
Sec. 60.5386b(c).
(B) For conducting measurements on manifolded groups of centrifugal
compressors on the Alaska North Slope equipped with sour seal oil
separators and capture systems, you must determine the volumetric flow
rate from the centrifugal compressors equipped with sour seal oil
separators and capture systems as specified in paragraph
(a)(7)(ii)(B)(1) or (2) of this section.
(1) Measure at a single point in the manifold downstream of all
centrifugal compressors on the Alaska North Slope equipped with sour
seal oil separator and capture system wet seal inputs and, if
practical, prior to comingling with other non-compressor emission
sources.
(2) Determine the volumetric flow rate at standard conditions from
the common stack using one of the methods specified in paragraph
(a)(7)(ii)(A)(1) through (3) of this section.
(iii) You must determine the volumetric flow rate from your
centrifugal compressor equipped with dry seals as specified in
paragraph (a)(7)(iii)(A) or (B) of this section. If the volumetric flow
rate exceeds 10 scfm multiplied by the number of dry seals connected to
the vent, the dry seals connected to the measured vent must be repaired
as provided in paragraph (a)(8) of this section.
(A) For centrifugal compressors equipped with dry seals in
operating-mode or in standby-pressurized-mode, determine volumetric
flow rate at standard conditions from each centrifugal compressor
equipped with dry seals using one of the methods specified in
paragraphs (a)(7)(iii)(A)(1) through (3) of this section.
(1) You may choose to use any of the methods set forth in Sec.
60.5386b(a) to screen for leaks/emissions. For the purposes of this
paragraph, when using any of the methods in Sec. 60.5386b(a),
emissions are detected whenever a leak is detected according to the
method. If emissions are detected using the methods set forth in Sec.
60.5386b(a), then you must use one of the methods specified in
paragraph (a)(7)(iii)(A)(2) or (3) of this section to determine the
volumetric flow rate. If emissions are not detected using the methods
in Sec. 60.5386b(a), then you may assume that the volumetric emissions
are zero.
(2) Use a temporary or permanent flow meter according to methods
set forth in Sec. 60.5386b(b).
[[Page 17056]]
(3) Use a high-volume sampler according to the method set forth in
Sec. 60.5386b(c).
(B) For conducting measurements on manifolded groups of centrifugal
compressors equipped with dry seals, you must determine the volumetric
flow rate from the dry seal centrifugal compressors as specified in
paragraph (a)(7)(iii)(B)(1) or (2) of this section.
(1) Measure at a single point in the manifold downstream of all
centrifugal compressors equipped with dry seals inputs and, if
practical, prior to comingling with other non-compressor emission
sources.
(2) Determine the volumetric flow rate at standard conditions from
the common stack using one of the methods specified in paragraph
(a)(7)(iii)(A)(1) through (3) of this section.
(8) The seal must be repaired within 90 calendar days after the
date of the volumetric emissions measurement that exceeds the
applicable required flow rate per seal. You must conduct follow-up
volumetric flow rate measurements from seal vents using the methods
specified in paragraph (a)(7) of this section within 15 days after the
repair to document that the rate has been reduced to less than the
applicable required flow rate per seal. If the individual seals are
manifolded to a single open-ended vent line or vent, the volumetric
flow rate must be reduced to less than the sum of the individual seals
multiplied by the applicable required flow rate per seal specified in
paragraph (a)(4) through (6) of this section, as applicable. Delay of
repair will be allowed if the conditions in paragraphs (a)(8)(i) or
(ii) of this section are met.
(i) If the repair of the wet or dry seal is technically infeasible,
would require a vent blowdown, a compressor station shutdown, or would
be unsafe to repair during operation of the unit, the repair must be
completed during the next scheduled compressor station shutdown for
maintenance, after a scheduled vent blowdown, or within 2 years of the
date of the volumetric emissions measurement that exceeds the
applicable required flow rate per seal, whichever is earliest. A vent
blowdown is the opening of one or more blowdown valves to depressurize
major production and processing equipment, other than a storage vessel.
(ii) If the repair requires replacement of the compressor seal or a
part thereof, but the replacement cannot be acquired and installed
within the repair timelines specified under this section due to the
condition specified in paragraph (a)(8)(ii)(A) of this section, the
repair must be completed in accordance with paragraph (a)(8)(ii)(B) of
this section and documented in accordance with Sec.
60.5420b(c)(4)(iii)(F) through (H).
(A) Seal or part thereof supplies had been sufficiently stocked but
are depleted at the time of the required repair.
(B) The required replacement must be ordered no later than 10
calendar days after the centrifugal compressor seal is added to the
delay of repair list due to parts unavailability. The repair must be
completed as soon as practicable, but no later than 30 calendar days
after receipt of the replacement seal or part, unless the repair
requires a compressor station shutdown. If the repair requires a
compressor station shutdown, the repair must be completed in accordance
with the timeframe specified in paragraph (a)(8)(i) of this section.
(9) As an alternative to meeting the requirements for centrifugal
compressors with dry seals specified in paragraphs (a)(6) through (8)
of this section, owners or operators are allowed to comply with the
standard by meeting the requirements specified in paragraphs (a)(9)(i)
and (ii), or (a)(9)(iii) of this section.
(i) You must reduce methane and VOC emissions from each centrifugal
compressor dry seal system by 95.0 percent.
(ii) If you use a control device to reduce emissions, you must
equip the dry seal system with a cover that meets the requirements of
Sec. 60.5411b(b). The cover must be connected through a closed vent
system that meets the requirements of Sec. 60.5411b(a) and (c) and the
closed vent system must be routed to a control device that meets the
conditions specified in Sec. 60.5412b.
(iii) As an alternative to routing the closed vent system to a
control device, you may route the closed vent system to a process. If
you route the emissions to a process, you must equip the dry seal
system with a cover that meets the requirements of Sec. 60.5411b(b).
The cover must be connected through a closed vent system that meets the
requirements of Sec. 60.5411b(a) and (c).
(b) You must demonstrate initial compliance with the standards that
apply to centrifugal compressor affected facilities as required by
Sec. 60.5410b(d).
(c) You must demonstrate continuous compliance with the standards
that apply to centrifugal compressor affected facilities as required by
Sec. 60.5415b(d).
(d) You must perform the reporting as required by Sec.
60.5420b(b)(1) and (5), and (b)(11) through (13), as applicable; and
the recordkeeping as required by Sec. 60.5420b(c)(4), and (8) through
(13), as applicable.
Sec. 60.5385b What GHG and VOC standards apply to reciprocating
compressor affected facilities?
Each reciprocating compressor affected facility must comply with
the GHG and VOC standards, using volumetric flow rate as a surrogate,
in paragraphs (a) through (c) of this section, or the GHG and VOC
standards in paragraph (d) of this section. You must also comply with
the requirements in paragraphs (e) through (g) of this section.
(a) The volumetric flow rate of each cylinder, measured in
accordance with paragraph (b) or (c) of this section, must not exceed 2
scfm per individual cylinder. If the individual cylinders are
manifolded to a single open-ended vent line, the volumetric flow rate
must not exceed the sum of the individual cylinders multiplied by 2
scfm. You must conduct measurements of the volumetric flow rate in
accordance with the schedule specified in paragraphs (a)(1) and (2) of
this section and determine the volumetric flow rate per cylinder in
accordance with paragraph (b) or (c) of this section. If the volumetric
flow rate, measured in accordance with paragraph (b) or (c) of this
section, for a cylinder exceeds 2 scfm per cylinder (or a combined
volumetric flow rate greater than the number of compression cylinders
multiplied by 2 scfm), the rod packing or packings must be repaired or
replaced as provided in paragraph (a)(3) of this section.
(1) You must conduct your first volumetric flow rate measurements
from your reciprocating compressor rod packing vent on or before 8,760
hours of operation after May 7, 2024, or on or before 8,760 hours of
operation after last rod packing replacement, or on or before 8,760
hours of operation after startup, whichever date is later.
(2) You must conduct subsequent volumetric flow rate measurements
from your reciprocating compressor rod packing vent on or before 8,760
hours of operation after the previous measurement which demonstrates
compliance with the applicable volumetric flow rate of 2 scfm per
cylinder (or a combined volumetric flow rate greater than the number of
compression cylinders multiplied by 2 scfm), or on or before 8,760
hours of operation after last rod packing replacement, whichever date
is later.
(3) The rod packing must be repaired or replaced within 90 calendar
days after the date of the volumetric emissions measurement that
exceeded 2 scfm per cylinder. You must conduct follow-up volumetric
flow rate measurements from compressor vents
[[Page 17057]]
using the methods specified in paragraph (b) of this section within 15
days after the repair (or rod packing replacement) to document that the
rate has been reduced to less than 2 scfm per cylinder. Delay of repair
will be allowed if the conditions in paragraphs (a)(3)(i) or (ii) of
this section are met.
(i) If the repair (or rod packing replacement) is technically
infeasible, would require a vent blowdown, a compressor station
shutdown, or would be unsafe to repair during operation of the unit,
the repair (or rod packing replacement) must be completed during the
next scheduled compressor station shutdown for maintenance, after a
scheduled vent blowdown, or within 2 years of the date of the
volumetric emissions measurement that exceeds the applicable required
flow rate per cylinder, whichever is earliest. A vent blowdown is the
opening of one or more blowdown valves to depressurize major production
and processing equipment, other than a storage vessel.
(ii) If the repair requires replacement of the rod packing or a
part, but the replacement cannot be acquired and installed within the
repair timelines specified under this section due to the condition
specified in paragraph (a)(3)(ii)(A) of this section, the repair must
be completed in accordance with paragraph (a)(3)(ii)(B) of this section
and documented in accordance with Sec. 60.5420b(c)(5)(viii) through
(x).
(A) Rod packing or part supplies had been sufficiently stocked but
are depleted at the time of the required repair.
(B) The required rod packing or part replacement must be ordered no
later than 10 calendar days after the reciprocating compressor is added
to the delay of repair list due to parts unavailability. The repair
must be completed as soon as practicable, but no later than 30 calendar
days after receipt of the replacement rod packing or part, unless the
repair requires a compressor station shutdown. If the repair requires a
compressor station shutdown, the repair must be completed in accordance
with the timeframe specified in paragraph (a)(3)(i) of this section.
(b) You must determine the volumetric flow rate per cylinder from
your reciprocating compressor as specified in paragraph (b)(1) or (2)
of this section.
(1) For reciprocating compressor rod packing equipped with an open-
ended vent line on compressors in operating or standby pressurized
mode, determine the volumetric flow rate of the rod packing using one
of the methods specified in paragraphs (b)(1)(i) through (iii) of this
section.
(i) Determine the volumetric flow rate at standard conditions from
the open-ended vent line using a high-volume sampler according to
methods set forth in Sec. 60.5386b(c).
(ii) Determine the volumetric flow rate at standard conditions from
the open-ended vent line using a temporary or permanent meter,
according to methods set forth in Sec. 60.5386b(b).
(iii) Any of the methods set forth in Sec. 60.5386b(a) to screen
for leaks and emissions. For the purposes of this paragraph, emissions
are detected whenever a leak is detected according to any of the
methods in Sec. 60.5386b(a). If emissions are detected using the
methods set forth in Sec. 60.5386b(a), then you must use one of the
methods specified in paragraph (b)(1)(i) and (ii) of this section to
determine the volumetric flow rate per cylinder. If emissions are not
detected using the methods in Sec. 60.5386b(a), then you may assume
that the volumetric flow rate is zero.
(2) For reciprocating compressor rod packing not equipped with an
open-ended vent line on compressors in operating or standby pressurized
mode, you must determine the volumetric flow rate of the rod packing
using the methods specified in paragraphs (b)(2)(i) and (ii) of this
section.
(i) You must use the methods described in Sec. 60.5386b(a) to
conduct leak detection of emissions from the rod packing case into an
open distance piece, or, for compressors with a closed distance piece,
you must conduct annual leak detection of emissions from the rod
packing vent, distance piece vent, compressor crank case breather cap,
or other vent emitting gas from the rod packing.
(ii) You must measure emissions found in paragraph (b)(2)(i) of
this section using a meter or high-volume sampler according to methods
set forth in Sec. 60.5386b(b) or (c).
(c) For conducting measurements on manifolded groups of
reciprocating compressor affected facilities, you must determine the
volumetric flow rate from reciprocating compressor rod packing vent as
specified in paragraph (c)(1) and (2) of this section.
(1) Measure at a single point in the manifold downstream of all
compressor vent inputs and, if practical, prior to comingling with
other non-compressor emission sources.
(2) Determine the volumetric flow rate per cylinder at standard
conditions from the common stack using one of the methods specified in
paragraph (c)(2)(i) through (iv) of this section.
(i) A temporary or permanent flow meter according to the methods
set forth in Sec. 60.5386b(b).
(ii) A high-volume sampler according to methods set forth Sec.
60.5386b(c).
(iii) An alternative method, as set forth in Sec. 60.5386b(d).
(iv) Any of the methods set forth in Sec. 60.5386b(a) to screen
for emissions. For the purposes of this paragraph, emissions are
detected whenever a leak is detected when using any of the methods in
Sec. 60.5386b(a). If emissions are detected using the methods set
forth in Sec. 60.5386b(a), then you must use one of the methods
specified in paragraph (c)(2)(i) through (iii) of this section to
determine the volumetric flow rate per cylinder. If emissions are not
detected using the methods in Sec. 60.5386b(a), then you may assume
that the volumetric flow rate is zero.
(d) As an alternative to complying with the GHG and VOC standards
in paragraphs (a) through (c) of this section, owners or operators can
meet the requirements specified in paragraph (d)(1), (2), or (3) of
this section.
(1) Collect the methane and VOC emissions from your reciprocating
compressor rod packing using a rod packing emissions collection system
that is operated to route the rod packing emissions to a process. In
order to comply with this option, you must equip the reciprocating
compressor with a cover that meets the requirements of Sec.
60.5411b(b). The cover must be connected through a closed vent system
that meets the requirements of Sec. 60.5411b(a) and (c).
(2) Reduce methane and VOC emissions from each rod packing
emissions collection system by using a control device that reduces
methane and VOC emissions by 95.0 percent. In order to comply with this
option, you must equip the reciprocating compressor with a cover that
meets the requirements of Sec. 60.5411b(b). The cover must be
connected through a closed vent system that meets the requirements of
Sec. 60.5411b(a) and (c) and the closed vent system must be routed to
a control device that meets the conditions specified in Sec. 60.5412b.
(3) As an alternative to conducting the required volumetric flow
rate measurements under paragraph (a) of this section, an owner or
operator can choose to comply by replacing the rod packing on or before
8,760 hours of operation after initial startup, on or before 8,760
hours of operation after May 7, 2024, on or before 8,760 hours of
operation after the previous flow rate measurement, or on or before
8,760 hours of operation after the date of the
[[Page 17058]]
most recent compressor rod packing replacement, whichever date is
later.
(e) You must demonstrate initial compliance with standards that
apply to reciprocating compressor affected facilities as required by
Sec. 60.5410b(e).
(f) You must demonstrate continuous compliance with standards that
apply to reciprocating compressor affected facilities as required by
Sec. 60.5415b(g).
(g) You must perform the reporting requirements as specified in
Sec. 60.5420b(b)(1), (6), (11), and (12), as applicable; and the
recordkeeping requirements as specified in Sec. 60.5420b(c)(5) and (8)
through (13), as applicable.
Sec. 60.5386b What test methods and procedures must I use for my
centrifugal compressor and reciprocating compressor affected
facilities?
(a) You must use one of the methods described in paragraph (a)(1)
and (2) of this section to screen for emissions or leaks from the
reciprocating compressor rod packing when complying with Sec.
60.5385b(b)(1)(iii) and from applicable wet seal centrifugal compressor
and dry seal centrifugal compressor vents when complying with Sec.
60.5380b(a)(3) through (6).
(1) OGI instrument. Use an OGI instrument for equipment leak
detection as specified in either paragraph (a)(1)(i) or (ii) of this
section. For the purposes of paragraphs (a)(1)(i) and (ii) of this
section, any visible emissions observed by the OGI instrument from
reciprocating rod packing or compressor dry seal vent is a leak.
(i) OGI instrument as specified in appendix K of this part. For
reciprocating compressor, applicable wet seal centrifugal compressor,
and dry seal centrifugal compressor affected facilities located at
onshore natural gas processing plants, use an OGI instrument to screen
for emissions from reciprocating rod packing or centrifugal compressor
dry seal vent in accordance with the protocol specified in appendix K
of this part.
(ii) OGI instrument as specified in Sec. 60.5397b of this subpart.
For reciprocating compressor, applicable wet seal centrifugal
compressor, and dry seal centrifugal compressor affected facilities
located at centralized production facilities, compressor stations, or
other location that is not an onshore natural gas processing plant, use
an OGI instrument to screen for emissions from reciprocating rod
packing or compressor dry seals in accordance with the elements of
Sec. 60.5397b(c)(7).
(2) Method 21. Use Method 21 in appendix A-7 to this part according
to Sec. 60.5403b(b)(1) and (2). For the purposes of this section, an
instrument reading of 500 parts per million by volume (ppmv) above
background or greater is a leak.
(b) You must determine natural gas volumetric flow rate using a
rate meter which meets the requirement in Method 2D in appendix A-1 of
this part. Rate meters must be calibrated on an annual basis according
to the requirements in Method 2D.
(c) You must use a high-volume sampler to measure emissions of the
reciprocating compressor rod packing. applicable centrifugal compressor
wet seal vent, or centrifugal compressor dry seal vent in accordance
with paragraphs (c)(1) through (7) of this section.
(1) You must use a high-volume sampler designed to capture the
entirety of the emissions from the applicable vent and measure the
entire range of methane concentrations being emitted as well as the
total volumetric flow at standard conditions. You must develop a
standard operating procedure for this device and document these
procedures in the appropriate monitoring plan. In order to get reliable
results, persons using this device should be knowledgeable in its
operation and the requirements in this section.
(2) This procedure may involve hazardous materials, operations, and
equipment. This procedure may not address all of the safety problems
associated with its use. It is the responsibility of the user of this
procedure to establish appropriate safety and health practices and
determine the applicability of regulatory limitations prior to
performing this procedure.
(3) The high-volume sampler must include a methane gas sensor(s)
which meets the requirements in paragraphs (c)(3)(i) through (iii) of
this section.
(i) The methane sensor(s) must be selective to methane with minimal
interference, less than 2.5 percent for the sum of responses to other
compounds in the gas matrix. You must document the minimal interference
though empirical testing or through data provided by the manufacturer
of the sensor.
(ii) The methane sensor(s) must have a measurement range over the
entire expected range of concentrations.
(iii) The methane sensor(s) must be capable of taking a measurement
once every second, and the data system must be capable of recording
these results for each sensor at all times during operation of the
sampler.
(4) The high-volume sampler must be designed such that it is
capable of sampling sufficient volume in order to capture all emissions
from the applicable vent. Your high-volume sampler must include a flow
measurement sensor(s) which meets the requirements of paragraphs
(c)(4)(i) and (ii) of this section.
(i) The flow measurement sensor must have a measurement range over
the entire expected range of flow rates sampled. If needed multiple
sensors may be used to capture the entire range of expected flow rates.
(ii) The flow measurement sensor(s) must be capable of taking a
measurement once every second, and the data system must be capable of
recording these results for each sensor at all times during operation
of the sampler.
(5) You must calibrate your methane sensor(s) according to the
procedures in paragraphs (c)(5)(i)(A) and (B) of this section, and flow
measurement sensors must be calibrated according to the procedures in
paragraph (c)(5)(ii) of this section.
(i) For Methane Sensor Calibration:
(A) Initially and on a semi-annual basis, determine the linearity
at four points through the measurement range for each methane sensor
using methane gaseous calibration cylinder standards. At each point,
the difference between the cylinder value and the sensor reading must
be less than 5 percent of the respective calibration gas value. If the
sensor does not meet this requirement, perform corrective action on the
sensor, and do not use the sampler until these criteria can be met.
(B) Prior to and at the end of each testing day, challenge each
sensor at two points, a low point, and a mid-point, using methane
gaseous calibration cylinder standards. At each point, the difference
between the cylinder value and the sensor reading must be less than 5
percent of the respective calibration gas value. If the sensor does not
meet this requirement, perform corrective action on the sensor and do
not use the sampler again until these criteria can be met. If the post-
test calibration check fails at either point, invalidate the data from
all tests performed subsequent to the last passing calibration check.
(ii) Flow measurement sensors must meet the requirements in Method
2D in appendix A-1 of this part. Rate meters must be calibrated on an
annual basis according to the requirements in Method 2D. If your flow
sensor relies on ancillary temperature and pressure measurements to
correct the flow rate to standard conditions, the temperature and
pressure sensors must also be calibrated on an annual basis. Standard
conditions are defined as 20 [deg]C (68 [deg]F) and 760 mm Hg (29.92
in. Hg).
[[Page 17059]]
(6) You must conduct sampling of the reciprocating compressor rod
packing, applicable wet seal centrifugal compressor, or dry seal
centrifugal compressor vent in accordance with the procedures in
paragraphs (c)(6)(i) through (v) of this section.
(i) The instrument must be operated consistent with manufacturer
recommendations; users are encouraged to develop a standard operating
procedure to document the exact procedures used for sampling.
(ii) Identify the rod packing, applicable wet seal centrifugal
compressor, or dry seal centrifugal compressor vent to be measured and
record the signal to noise ratio (S/N) of the engine. Collect a
background methane sample in ppmv for a minimum of one minute and
record the result along with the date and time.
(iii) Approach the vent with the sample hose and adjust the sampler
so that you are measuring at the full flow rate. Then, adjust the flow
rate to ensure the measured methane concentration is within the
calibrated range of the methane sensor and minimum methane
concentration is at least 2 ppmv higher than the background
concentration. Sample for a period of at least one minute and record
the average flow rate in standard cubic feet per minute and the methane
sample concentration in ppmv, along with the date and time. Standard
conditions are defined as 20 [deg]C (68 [deg]F) and 760 mm Hg (29.92
in. Hg).
(iv) Calculate the leak rate according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR08MR24.000
Where:
CH4B = background methane concentration, ppmv
CH4S = methane sample concentration, ppmv
V = Average flow rate of the sampler, scfm
Q = Methane emission rate, scfm
(v) You must collect at least three separate one-minute
measurements and determine the average leak rate. The relative percent
difference of these three separate samples should be less than 10
percent.
(7) If the measured natural gas flow determined as specified in
paragraph (c)(6) of this section exceeds 70.0 percent of the
manufacturer's reported maximum sampling flow rate you must either use
a temporary or permanent flow meter according to paragraph (b) of this
section or use another method meeting the requirements in paragraph (d)
of this section to determine the leak or flow rate.
(d) As an alternative to a high-volume sampler, you may use any
other method that has been validated in accordance with the procedures
specified in Method 301 in appendix A in 40 CFR part 63, subject to
Administrator approval, as specified in Sec. 60.8(b).
Sec. 60.5390b What GHG and VOC standards apply to process controller
affected facilities?
Each process controller affected facility must comply with the GHG
and VOC standards in this section.
(a) You must design and operate each process controller affected
facility with zero methane and VOC emissions to the atmosphere, except
as provided in paragraph (b) of this section.
(1) If you comply by routing the emissions to a process, emissions
must be routed to a process through a closed vent system.
(2) If you comply by using a self-contained natural gas-driven
process controller, you must design and operate each self-contained
natural gas-driven process controller with no identifiable emissions,
as demonstrated by Sec. 60.5416b(b).
(b) For each process controller affected facility located at a site
in Alaska that does not have access to electrical power, you may comply
with either paragraphs (b)(1) and (2) of this section or with paragraph
(b)(3) of this section, instead of complying with paragraph (a) of this
section.
(1) With the exception of natural gas-driven continuous bleed
controllers that meet the condition in paragraph (b)(1)(i) of this
section and that comply with paragraph (b)(1)(ii) of this section, each
natural gas-driven continuous bleed process controller in the process
controller affected facility must have a bleed rate less than or equal
to 6 standard cubic feet per hour (scfh).
(i) A natural gas-driven continuous bleed process controller with a
bleed rate higher than 6 scfh may be used if the requirements of
paragraph (b)(1)(ii) of this section are met.
(ii) You demonstrate that a natural gas-driven continuous bleed
controller with a bleed rate higher than 6 scfh is required. The
demonstration must be based on the specific functional need, including
but not limited to response time, safety, or positive actuation.
(2) Each natural gas-driven intermittent vent process controller in
the process controller affected facility must comply with the
requirements in paragraphs (b)(2)(i) and (ii) of this section.
(i) Each natural gas-driven intermittent vent process controller
must not emit to the atmosphere during idle periods.
(ii) You must monitor each natural gas-driven intermittent vent
process controller to ensure that it is not emitting to the atmosphere
during idle periods, as specified in paragraphs (b)(2)(ii)(A) through
(C) of this section.
(A) Monitoring must be conducted at the same frequency as specified
for fugitive emissions components affected facilities located at the
same type of site, as specified in Sec. 60.5397b(g).
(B) You must include the monitoring of each natural gas-driven
intermittent vent process controller in the monitoring plan required in
Sec. 60.5397b(b).
(C) When monitoring identifies emissions to the atmosphere from a
natural gas-driven intermittent vent controller during idle periods,
you must take corrective action by repairing or replacing the natural
gas-driven intermittent vent process controller within 5 calendar days
of the date the emissions to the atmosphere were detected. After the
repair or replacement of a natural gas-driven intermittent vent process
controller, you must re-survey the natural gas-driven intermittent vent
process controller within five days to verify that it is not venting
emissions during idle periods.
(3) You must reduce methane and VOC emissions from all controllers
in the process controller affected facility by 95.0 percent. You must
route emissions through a closed vent system to a control device that
meets the conditions specified in Sec. 60.5412b.
(c) If you route process controller emissions to a process or a
control device, you must route the process controller affected facility
emissions through a closed vent system that meets
[[Page 17060]]
the requirements of Sec. 60.5411b(a) and (c).
(d) You must demonstrate initial compliance with standards that
apply to process controller affected facilities as required by Sec.
60.5410b(f).
(e) You must demonstrate continuous compliance with standards that
apply to process controller affected facilities as required by Sec.
60.5415b(h).
(f) You must perform the reporting as required by Sec.
60.5420b(b)(1), (7), and (11) through (13), as applicable, and the
recordkeeping as required by Sec. 60.5420b(c)(6), (8), and (10)
through (13), as applicable.
Sec. 60.5393b What GHG and VOC standards apply to pump affected
facilities?
Each pump affected facility must comply with the GHG and VOC
standards in this section.
(a) For each pump affected facility meeting the criteria specified
in paragraphs (a)(1) or (2) of this section, you must design and
operate the pump affected facility with zero methane and VOC emissions
to the atmosphere. If you comply by routing the pump affected facility
emissions to a process, the emissions must be routed to the process
through a closed vent system.
(1) The pump affected facility is located at a site that has access
to electrical power.
(2) The pump affected facility is located at a site that does not
have access to electrical power and has three or more natural gas-
driven diaphragm pumps.
(b)(1) For each pump affected facility located at a site that does
not have access to electrical power and that also has fewer than three
natural gas-driven diaphragm pumps, you must comply with paragraph
(b)(2) or (3) of this section, except as provided in paragraphs (b)(4)
through (8) of this section.
(2) Emissions from the pump affected facility must be routed
through a closed vent system to a process if a vapor recovery unit is
onsite.
(3) If a vapor recovery unit is not onsite, you must reduce methane
and VOC emissions from the pump affected facility by 95.0 percent. You
must route affected pump facility emissions through a closed vent
system to a control device meeting the conditions specified in Sec.
60.5412b.
(4) You are not required to install an emissions control device or
a vapor recovery unit, if such a unit is necessary to enable emissions
to be routed to a process, solely for the purpose of complying with the
requirements of paragraph (b)(2) or (3) of this section. If no control
device capable of achieving a 95.0 percent emissions reduction and no
vapor recovery unit is present on site, you must comply with paragraph
(b)(5) or (6) of this section, as applicable. For the purposes of this
section, boilers and process heaters are not considered to be control
devices.
(5) If an emissions control device is on site but is unable to
achieve a 95.0 percent emissions reduction, you must route the pump
affected facility emissions through a closed vent system to that
control device. You must certify that there is no vapor recovery unit
on site and that there is no control device capable of achieving a 95.0
percent emissions reduction on site.
(6) If there is no vapor recovery unit on site and no emission
control device is on site, you must certify that there is no vapor
recovery unit or emissions control device on site. If you subsequently
install a control device or vapor recovery unit, you must meet the
requirements of paragraphs (b)(6)(i) and (ii) of this section.
(i) You must be in compliance with the requirements of paragraphs
(b)(1) through (3) of this section, as applicable, within 30 days of
startup of the control device or vapor recovery unit.
(ii) You must maintain the records in Sec. 60.5420b(c)(15)(ii) and
(v), as applicable. You are no longer required to maintain the records
in Sec. 60.5420b(c)(15)(vi).
(7) If an owner or operator complying with paragraph (b)(1) of this
section determines, through an engineering assessment, that routing the
pump affected facility emissions to a control device or to a process is
technically infeasible, the requirements specified in paragraphs
(b)(7)(i) through (iii) of this section must be met.
(i) The owner or operator must conduct the assessment of technical
infeasibility in accordance with the criteria in paragraph (b)(7)(ii)
of this section and have it certified by either a qualified
professional engineer or an in-house engineer with expertise on the
design and operation of the pump affected facility and the control
device or processes at the site in accordance with paragraph
(b)(7)(iii) of this section.
(ii) The assessment of technical infeasibility to route emissions
from the pump affected facility to an existing control device or
process must include, but is not limited to, safety considerations,
distance from the control device or process, pressure losses and
differentials in the closed vent system, and the ability of the control
device or process to handle the pump affected facility emissions which
are routed to them. The assessment of technical infeasibility must be
prepared under the direction or supervision of the qualified
professional engineer or in-house engineer who signs the certification
in accordance with paragraph (b)(7)(iii) of this section.
(iii) The following certification, signed and dated by the
qualified professional engineer or in-house engineer, must state: ``I
certify that the assessment of technical infeasibility was prepared
under my direction or supervision. I further certify that the
assessment was conducted and this report was prepared pursuant to the
requirements of Sec. 60.5393b(b)(5)(ii). Based on my professional
knowledge and experience, and inquiry of personnel involved in the
assessment, the certification submitted herein is true, accurate, and
complete.''
(8) If the pump affected facility emissions are routed to a control
device or process and the control device or process is subsequently
removed from the location or is no longer available, such that there is
no option to route to a control device or process, you are no longer
required to be in compliance with the requirements of paragraphs (b)(2)
or (3) of this section, and instead must comply with paragraph (b)(6)
of this section.
(c) If you use a control device or route to a process to reduce
emissions, you must route the pump affected facility emissions through
a closed vent system that meets the requirements of Sec. 60.5411b(a)
and (c).
(d) You must demonstrate initial compliance with standards that
apply to pump affected facilities as required by Sec. 60.5410b(g).
(e) You must demonstrate continuous compliance with the standards
that apply to pump affected facilities as required by Sec.
60.5415b(e).
(f) You must perform the reporting as required by Sec.
60.5420b(b)(1), (10), and (11) through (13), as applicable; and the
recordkeeping as required by Sec. 60.5420b(c)(8), (10) through (13),
and (15), as applicable.
Sec. 60.5395b What GHG and VOC standards apply to storage vessel
affected facilities?
Each storage vessel affected facility must comply with the GHG and
VOC standards in this section, except as provided in paragraph (e) of
this section.
(a) General requirements. You must comply with the requirements of
paragraphs (a)(1) and (2) of this section. After 12 consecutive months
of compliance with paragraph (a)(2) of this section, you may continue
to comply with paragraph (a)(2) of this section, or you may comply with
paragraph (a)(3) of this section, if applicable. If you
[[Page 17061]]
choose to meet the requirements of paragraph (a)(3) of this section,
you are not required to comply with the requirements of paragraph
(a)(2) of this section except as provided in paragraphs (a)(3)(i) and
(ii) of this section.
(1) Determine the potential for methane and VOC emissions in
accordance with Sec. 60.5365b(e)(2).
(2) Reduce methane and VOC emissions by 95.0 percent.
(3) Maintain the uncontrolled actual VOC emissions at less than 4
tpy and the actual methane emissions at less than 14 tpy from the
storage vessel affected facility without considering control. Prior to
using the uncontrolled actual VOC and methane emission rates for
compliance purposes, you must demonstrate that the uncontrolled actual
VOC emissions have remained less than 4 tpy and the uncontrolled actual
methane emissions have remained less than 14 tpy as determined monthly
for 12 consecutive months. After such demonstration, you must determine
the uncontrolled actual rolling 12-month determination VOC and methane
emissions rates each month. The uncontrolled actual VOC and methane
emissions must be calculated using a generally accepted model or
calculation methodology which account for flashing, working and
breathing losses, and the calculations must be based on the actual
average throughput, temperature, and separator pressure for the month.
You may no longer comply with this paragraph and must instead comply
with paragraph (a)(2) of this section if your storage vessel affected
facility meets the conditions specified in paragraphs (a)(3)(i) or (ii)
of this section.
(i) If a well feeding the storage vessel affected facility
undergoes fracturing or refracturing, you must comply with paragraph
(a)(2) of this section as soon as liquids from the well following
fracturing or refracturing are routed to the storage vessel affected
facility.
(ii) If the rolling 12-month emissions determination required in
this section indicates that VOC emissions increase to 4 tpy or greater
or the methane emissions increase to 14 tpy or greater from your
storage vessel affected facility and the increase is not associated
with fracturing or refracturing of a well feeding the storage vessel
affected facility, you must comply with paragraph (a)(2) of this
section within 30 days of the monthly determination.
(b) Control requirements. (1) Except as required in paragraph
(b)(2) of this section, if you use a control device to reduce methane
and VOC emissions from your storage vessel affected facility, you must
meet all of the design and operational criteria specified in paragraphs
(b)(1)(i) through (iii) of this section.
(i) Each storage vessel in the tank battery must be equipped with a
cover that meets the requirements of Sec. 60.5411b(b);
(ii) The tank battery must be equipped with one or more closed vent
system that meets the requirements of Sec. 60.5411b(a) and (c); and
(iii) The vapors collected in paragraphs (b)(1)(ii) of this section
must be routed to a control device that meets the conditions specified
in Sec. 60.5412b. As an alternative to routing the closed vent system
to a control device, you may route the closed vent system to a process.
(2) For storage vessel affected facilities that do not have
flashing emissions and that are not located at well sites or
centralized production facilities, you may use a floating roof to
reduce emissions. If you use a floating roof to reduce emissions, you
must meet the requirements of Sec. 60.112b(a)(1) or (2) and the
relevant monitoring, inspection, recordkeeping, and reporting
requirements in subpart Kb of this part. You must submit a statement
that you are complying with Sec. 60.112b(a)(1) or (2) with the initial
annual report specified in Sec. 60.5420b(b)(1) and (8).
(c) Requirements for storage vessel affected facilities that are
removed from service or returned to service. If you remove a storage
vessel affected facility from service or remove a portion of a storage
vessel affected facility from service, you must comply with the
applicable paragraphs (c)(1) through (4) of this section. A storage
vessel is not an affected facility under this subpart for the period
that it is removed from service.
(1) For a storage vessel affected facility to be removed from
service, you must comply with the requirements of paragraphs (c)(1)(i)
and (ii) of this section.
(i) You must completely empty and degas each storage vessel, such
that each storage vessel no longer contains crude oil, condensate,
produced water or intermediate hydrocarbon liquids. A storage vessel
where liquid is left on walls, as bottom clingage or in pools due to
floor irregularity is considered to be completely empty.
(ii) You must submit a notification as required in Sec.
60.5420b(b)(6)(viii) in your next annual report, identifying each
storage vessel affected facility removed from service during the
reporting period and the date of its removal from service.
(2) For a portion of a storage vessel affected facility to be
removed from service, you must comply with the requirements of
paragraphs (c)(2)(i) through (iv) of this section.
(i) You must completely empty and degas the storage vessel(s), such
that the storage vessel(s) no longer contains crude oil, condensate,
produced water or intermediate hydrocarbon liquids. A storage vessel
where liquid is left on walls, as bottom clingage or in pools due to
floor irregularity is considered to be completely empty.
(ii) You must disconnect the storage vessel(s) from the tank
battery by isolating the storage vessel(s) from the tank battery such
that the storage vessel(s) is no longer manifolded to the tank battery
by liquid or vapor transfer.
(iii) You must submit a notification as required in Sec.
60.5420b(b)(8)(viii) in your next annual report, identifying each
storage vessel removed from service during the reporting period, the
impacted storage vessel affected facility, and the date of its removal
from service.
(iv) The remaining storage vessel(s) in the tank battery remain a
storage vessel affected facility and must continue to comply with the
applicable requirements of paragraphs (a) and (b) of this section.
(3) If a storage vessel identified in paragraph (c)(1)(ii) or
(c)(2)(iii) of this section is returned to service, you must determine
its affected facility status as provided in Sec. 60.5365b(e)(6).
(4) For each storage vessel affected facility or portion of a
storage vessel affected facility returned to service during the
reporting period, you must submit a notification in your next annual
report as required in Sec. 60.5420b(b)(8)(ix), identifying each
storage vessel affected facility or portion of a storage vessel
affected facility and the date of its return to service.
(d) Compliance, notification, recordkeeping, and reporting. You
must comply with paragraphs (d)(1) through (3) of this section.
(1) You must demonstrate initial compliance with standards as
required by Sec. 60.5410b(j).
(2) You must demonstrate continuous compliance with standards as
required by Sec. 60.5415b(i).
(3) You must perform the required reporting as required by Sec.
60.5420b(b)(1) and (8) and (b)(11) through (13), as applicable; and the
recordkeeping as required by Sec. 60.5420b(c)(7) and (c)(8) through
(13), as applicable.
(e) Exemptions. This subpart does not apply to storage vessels
subject to and controlled in accordance with the requirements for
storage vessels in subpart Kb of this part, and 40 CFR part 63,
subparts G, CC, HH, or WW.
[[Page 17062]]
Sec. 60.5397b What GHG and VOC standards apply to fugitive emissions
components affected facilities?
This section applies to fugitive emissions components affected
facilities. You must comply with the requirements of paragraphs (a)
through (l) of this section to reduce fugitive emissions of methane and
VOC. The requirements of this section are independent of the cover and
closed vent system requirements of Sec. 60.5411b.
(a) General requirements. You must monitor all fugitive emissions
components affected facilities in accordance with paragraphs (b)
through (g) of this section. You must repair all sources of fugitive
emissions in accordance with paragraph (h) of this section. You must
demonstrate initial compliance in accordance with paragraph (i) of this
section. You must keep records in accordance with paragraph (j) of this
section and report in accordance with paragraph (k) of this section.
You must meet the requirements for well closures in accordance with
paragraph (l) of this section.
(b) Develop fugitive emissions monitoring plan. You must develop a
fugitive emissions monitoring plan that covers all fugitive emissions
components affected facilities within each company-defined area in
accordance with paragraphs (c) and (d) of this section.
(c) Elements of fugitive emissions monitoring plan. Your fugitive
emissions monitoring plan must include the elements specified in
paragraphs (c)(1) through (8) of this section, at a minimum.
(1) Frequency for conducting surveys. Surveys must be conducted at
least as frequently as required by paragraphs (f) and (g) of this
section.
(2) Technique for determining fugitive emissions (i.e., AVO or
other detection methods, Method 21 of appendix A-7 to this part, and/or
OGI and meeting the requirements of paragraphs (c)(7)(i) through (vii)
of this section).
(3) Manufacturer and model number of fugitive emissions detection
equipment to be used, if applicable.
(4) Procedures and timeframes for identifying and repairing
fugitive emissions components from which fugitive emissions are
detected, including timeframes for fugitive emission components that
are unsafe to repair. Your repair schedule must meet the requirements
of paragraph (h) of this section at a minimum.
(5) Procedures and timeframes for verifying fugitive emission
component repairs.
(6) Records that will be kept and the length of time records will
be kept.
(7) If you are using OGI, your plan must also include the elements
specified in paragraphs (c)(7)(i) through (vii) of this section.
(i) Verification that your OGI equipment meets the specifications
of paragraphs (c)(7)(i)(A) and (B) of this section. This verification
is an initial verification, and may either be performed by the
facility, by the manufacturer, or by a third party. For the purposes of
complying with the fugitive emissions monitoring program with OGI,
fugitive emissions are defined as any visible emissions observed using
OGI.
(A) Your OGI equipment must be capable of imaging gases in the
spectral range for the compound of highest concentration in the
potential fugitive emissions.
(B) Your OGI equipment must be capable of imaging a gas that is
half methane, half propane at a concentration of 10,000 ppm at a flow
rate of <=60 g/hr from a quarter inch diameter orifice.
(ii) Procedure for a daily verification check.
(iii) Procedure for determining the operator's maximum viewing
distance from the equipment and how the operator will ensure that this
distance is maintained.
(iv) Procedure for determining maximum wind speed during which
monitoring can be performed and how the operator will ensure monitoring
occurs only at wind speeds below this threshold.
(v) Procedures for conducting surveys, including the items
specified in paragraphs (c)(7)(v)(A) through (C) of this section.
(A) How the operator will ensure an adequate thermal background is
present in order to view potential fugitive emissions.
(B) How the operator will deal with adverse monitoring conditions,
such as wind.
(C) How the operator will deal with interferences (e.g., steam).
(vi) Training and experience needed prior to performing surveys.
(vii) Procedures for calibration and maintenance. At a minimum,
procedures must comply with those recommended by the manufacturer.
(8) If you are using Method 21 of appendix A-7 to this part, your
plan must also include the elements specified in paragraphs (c)(8)(i)
through (iv) of this section. For the purposes of complying with the
fugitive emissions monitoring program using Method 21 of appendix A-7
to this part a fugitive emission is defined as an instrument reading of
500 ppmv or greater.
(i) Verification that your monitoring equipment meets the
requirements specified in Section 6.0 of Method 21 of appendix A-7 to
this part. For purposes of instrument capability, the fugitive
emissions definition shall be 500 ppmv or greater methane using a FID-
based instrument. If you wish to use an analyzer other than an FID-
based instrument, you must develop a site-specific fugitive emission
definition that would be equivalent to 500 ppmv methane using a FID-
based instrument (e.g., 10.6 eV PID with a specified isobutylene
concentration as the fugitive emission definition would provide
equivalent response to your compound of interest).
(ii) Procedures for conducting surveys. At a minimum, the
procedures shall ensure that the surveys comply with the relevant
sections of Method 21 of appendix A-7 to this part, including Section
8.3.1.
(iii) Procedures for calibration. The instrument must be calibrated
before use each day of its use by the procedures specified in Method 21
of appendix A-7 to this part. At a minimum, you must also conduct
precision tests at the interval specified in Method 21 of appendix A-7
to this part, Section 8.1.2, and a calibration drift assessment at the
end of each monitoring day. The calibration drift assessment must be
conducted as specified in paragraph (c)(8)(iii)(A) of this section.
Corrective action for drift assessments is specified in paragraphs
(c)(8)(iii)(B) and (C) of this section.
(A) Check the instrument using the same calibration gas that was
used to calibrate the instrument before use. Follow the procedures
specified in Method 21 of appendix A-7 to this part, Section 10.1,
except do not adjust the meter readout to correspond to the calibration
gas value. If multiple scales are used, record the instrument reading
for each scale used. Divide the arithmetic difference of the initial
and post-test calibration response by the corresponding calibration gas
value for each scale and multiply by 100 to express the calibration
drift as a percentage.
(B) If a calibration drift assessment shows a negative drift of
more than 10 percent, then all equipment with instrument readings
between the fugitive emission definition multiplied by (100 minus the
percent of negative drift) divided by 100 and the fugitive emission
definition that was monitored since the last calibration must be re-
monitored.
[[Page 17063]]
(C) If any calibration drift assessment shows a positive drift of
more than 10 percent from the initial calibration value, then, at the
owner/operator's discretion, all equipment with instrument readings
above the fugitive emission definition and below the fugitive emission
definition multiplied by (100 plus the percent of positive drift)
divided by 100 monitored since the last calibration may be re-
monitored.
(iv) Procedures for monitoring yard piping (other than buried yard
piping). At a minimum, place the probe inlet at the surface of the yard
piping and run the probe down the length of the piping. Connection
points on the piping must be monitored following the procedures
specified in Method 21 of appendix A-7 to this part.
(d) Additional elements of fugitive emissions monitoring plan. Each
fugitive emissions monitoring plan must include the elements specified
in paragraphs (d)(1) through (3) of this section, at a minimum, as
applicable.
(1) If you are using OGI, your plan must include procedures to
ensure that all fugitive emissions components, except buried yard
piping and associated components (e.g., connectors), are monitored
during each survey. Example procedures include, but are not limited to,
a sitemap with an observation path, a written narrative of where the
fugitive emissions components are located and how they will be
monitored, or an inventory of fugitive emissions components.
(2) If you are using Method 21 of appendix A-7 to this part, your
plan must include a list of fugitive emissions components to be
monitored and method for determining the location of fugitive emissions
components to be monitored in the field (e.g., tagging, identification
on a process and instrumentation diagram, etc.). Your fugitive
emissions monitoring plan must include the written plan developed for
all of the fugitive emissions components designated as difficult-to-
monitor in accordance with paragraph (g)(2) of this section, and the
written plan for fugitive emissions components designated as unsafe-to-
monitor in accordance with paragraph (g)(3) of this section.
(e) Monitoring of fugitive emissions components. Each fugitive
emissions component, except buried yard piping and associated
components (e.g., connectors), shall be observed or monitored for
fugitive emissions during each monitoring survey.
(f) Initial monitoring survey. You must conduct initial monitoring
surveys according to the requirements specified in paragraphs (f)(1)
through (4) of this section.
(1) At single wellhead only sites and small sites, you must conduct
an initial monitoring survey using audible, visual, and olfactory
(AVO), or any other detection methods (e.g., OGI), within 90 days of
the startup of production, for each fugitive emissions components
affected facility or by June 6, 2024 whichever date is later.
(2) For multi-wellhead only well sites, well sites or centralized
production facilities that contain the major production and processing
equipment specified in paragraphs (g)(1)(iv)(A), (B), (C), or (D) of
this section, and compressor station sites, you must conduct an initial
monitoring survey using OGI or Method 21 of appendix A-7 to this part
within 90 days of the startup of production, for each fugitive
emissions components affected facility or by June 6, 2024 whichever
date is later.
(3) For a modified or reconstructed fugitive emissions components
affected facility, the initial monitoring survey must be conducted
within 90 days of the startup of production for each fugitive emissions
components affected facility after the modification or reconstruction
or by June 6, 2024, whichever date is later.
(4) Notwithstanding the deadlines specified in paragraphs (f)(1)
through (3) of this section, for each fugitive emissions components
affected facility located on the Alaskan North Slope that starts up
production between September and March, you must conduct an initial
monitoring survey within 6 months of the startup of production for a
new well site, within 6 months of the first day of production after a
modification of the fugitive emissions components affected facility, or
by the following June 30, whichever date is latest.
(g) Monitoring frequency. A monitoring survey of each fugitive
emissions components affected facility must be performed as specified
in paragraph (g)(1) of this section, with the exceptions noted in
paragraphs (g)(2) through (4) of this section. Monitoring for fugitive
emissions components affected facilities located at well sites and
centralized production facilities that have wells located onsite must
continue at the specified frequencies in paragraphs (g)(1)(i), (ii),
(iii), (iv) and (vi) of this section until the well closure
requirements of paragraph (l) of this section are completed.
(1) A monitoring survey of the fugitive emissions components
affected facilities must be conducted using the methods and at the
frequencies specified in paragraphs (g)(1)(i) through (vi) of this
section.
(i) A monitoring survey of the fugitive emissions component
affected facilities located at single wellhead only well sites must be
conducted at least quarterly using AVO, or any other detection method,
after the initial survey except as specified in paragraph (g)(1)(vi) of
this section. Any indications of fugitive emissions using these methods
are considered fugitive emissions that must be repaired in accordance
with paragraph (h) of this section.
(ii) A monitoring survey of the fugitive emissions component
affected facilities located at small well sites must be conducted at
least quarterly using AVO, or any other detection method, after the
initial survey except as specified in paragraph (g)(1)(vi) of this
section. Any indications of fugitive emissions using these methods are
considered fugitive emissions that must be repaired in accordance with
paragraph (h) of this section. At small well sites with an uncontrolled
storage vessel, a visual inspection of all thief hatches and other
openings on the storage vessel that are fugitive emissions components
must be conducted in conjunction with the monitoring survey to ensure
that they are kept closed and sealed at all times except during times
of adding or removing material, inspecting or sampling material, or
during required maintenance operations. If evidence of a deviation from
this requirement is found, you must take corrective action. At small
well sites with a separator, a visual inspection of all separator dump
valves to ensure the dump valve is free of debris and not stuck in an
open position must be conducted in conjunction with the monitoring
survey. Any dump valve not operating as designed must be repaired.
(iii) A monitoring survey of the fugitive emissions components
affected facilities located at multi-wellhead only well sites must be
conducted in accordance with paragraphs (g)(1)(iii)(A) and (B) of this
section, except as specified in paragraph (g)(1)(vi) of this section.
(A) A monitoring survey must be conducted at least quarterly using
AVO, or any other detection method, after the initial survey. Any
indications of fugitive emissions using these methods are considered
fugitive emissions that must be repaired in accordance with paragraph
(h) of this section.
(B) A monitoring survey must be conducted at least semiannually
using OGI or Method 21 of appendix A-7 to this part after the initial
survey. Consecutive semiannual surveys must
[[Page 17064]]
be conducted at least 4 months apart and no more than 7 months apart.
(iv) A monitoring survey of the fugitive emissions components
affected facilities located at well sites or centralized production
facilities that contain the major production and processing equipment
specified in paragraphs (g)(1)(iv)(A), (B), (C), or (D) must be
conducted at the frequencies in paragraphs (g)(1)(iv)(E) and (F) of
this section, except as specified in paragraph (g)(1)(vi) of this
section.
(A) One or more controlled storage vessels or tank batteries.
(B) One or more control devices.
(C) One or more natural gas-driven process controllers or pumps.
(D) Two or more pieces of major production and processing equipment
not specified in paragraphs (g)(1)(iv)(A) through (C) of this section.
(E) A monitoring survey must be conducted at least bimonthly using
AVO, or any other detection method, after the initial survey. Any
indications of fugitive emissions using these methods are considered
fugitive emissions that must be repaired in accordance with paragraph
(h) of this section. A visual inspection of all thief hatches and other
openings on storage vessels (or tank batteries) that are fugitive
emissions components must be conducted in conjunction with the
monitoring survey to ensure that they are kept closed and sealed at all
times except during times of adding or removing material, inspecting or
sampling material, or during required maintenance operations. If
evidence of a deviation from this requirement is found, you must take
corrective action. A visual inspection must be conducted of all
separator dump valves to ensure the dump valve is free of debris and
not stuck in an open position must be conducted in conjunction with the
monitoring survey. Any dump valve not operating as designed must be
repaired.
(F) A monitoring survey must be conducted at least quarterly using
OGI or Method 21 of appendix A-7 to this part after the initial survey.
Consecutive quarterly monitoring surveys must be conducted at least 60
calendar days apart.
(v) A monitoring survey of the fugitive emissions components
affected facility located at a compressor station must be conducted at
the frequencies in paragraphs (g)(1)(v)(A) and (B) of this section,
except as specified in paragraph (g)(1)(vi) of this section,
(A) A monitoring survey must be conducted at least monthly using
AVO, or any other detection method, after the initial survey. Any
indications of fugitive emissions using these methods are considered
fugitive emissions that must be repaired in accordance with paragraph
(h) of this section.
(B) A monitoring survey must be conducted at least quarterly using
OGI or Method 21 of appendix A-7 to this part after the initial survey.
Consecutive quarterly monitoring surveys must be conducted at least 60
calendar days apart.
(vi) A monitoring survey of the fugitive emissions components
affected facility located on the Alaska North Slope must be conducted
using OGI of this part or Method 21 of appendix A-7 to this part at
least annually. Consecutive annual monitoring surveys must be conducted
at least 9 months apart and no more than 13 months apart.
(2) If you are using Method 21 of appendix A-7 to this part,
fugitive emissions components that cannot be monitored without
elevating the monitoring personnel more than 2 meters above the surface
may be designated as difficult-to-monitor. Fugitive emissions
components that are designated difficult-to-monitor must meet the
specifications of paragraphs (g)(2)(i) through (iv) of this section.
(i) A written plan must be developed for all the fugitive emissions
components designated difficult-to-monitor. This written plan must be
incorporated into the fugitive emissions monitoring plan required by
paragraphs (b), (c), and (d) of this section.
(ii) The plan must include the identification and location of each
fugitive emissions component designated as difficult-to-monitor.
(iii) The plan must include an explanation of why each fugitive
emissions component designated as difficult-to-monitor is difficult-to-
monitor.
(iv) The plan must include a schedule for monitoring the difficult-
to-monitor fugitive emissions components at least once per calendar
year.
(3) If you are using Method 21 of appendix A-7 to this part,
fugitive emissions components that cannot be monitored because
monitoring personnel would be exposed to immediate danger while
conducting a monitoring survey may be designated as unsafe-to-monitor.
Fugitive emissions components that are designated unsafe-to-monitor
must meet the specifications of paragraphs (g)(3)(i) through (iv) of
this section.
(i) A written plan must be developed for all the fugitive emissions
components designated unsafe-to-monitor. This written plan must be
incorporated into the fugitive emissions monitoring plan required by
paragraphs (b), (c), and (d) of this section.
(ii) The plan must include the identification and location of each
fugitive emissions component designated as unsafe-to-monitor.
(iii) The plan must include an explanation of why each fugitive
emissions component designated as unsafe-to-monitor is unsafe-to-
monitor.
(iv) The plan must include a schedule for monitoring the fugitive
emissions components designated as unsafe-to-monitor.
(4) The requirements of paragraphs (g)(1)(iv)(F) and (g)(1)(v)(B)
of this section are waived during a quarterly monitoring period for any
fugitive emissions components affected facility located within an area
that has an average calendar month temperature below 0 degrees
Fahrenheit for two of three consecutive calendar months of a quarterly
monitoring period. The calendar month temperature average for each
month within the quarterly monitoring period must be determined using
historical monthly average temperatures over the previous three years
as reported by a National Oceanic and Atmospheric Administration source
or other source approved by the Administrator. The requirements of
paragraph (g)(1)(iv) and (v) of this section shall not be waived for
two consecutive quarterly monitoring periods.
(h) Repairs. Each identified source of fugitive emissions shall be
repaired in accordance with paragraphs (h)(1) and (2) of this section.
(1) A first attempt at repair shall be made in accordance with
paragraphs (h)(1)(i) and (ii) of this section.
(i) A first attempt at repair shall be made no later than 15
calendar days after detection of fugitive emissions that were
identified using AVO.
(ii) If you are complying with paragraph (g)(1)(i) through (vi) of
this section using OGI or Method 21 of appendix A-7 to this part, a
first attempt at repair shall be made no later than 30 calendar days
after detection of the fugitive emissions.
(2) Repair shall be completed as soon as practicable, but no later
than 15 calendar days after the first attempt at repair as required in
paragraph (h)(1)(i) of this section, and 30 calendar days after the
first attempt at repair as required in paragraph (h)(1)(ii) of this
section.
(3) Delay of repair will be allowed if the conditions in paragraphs
(h)(3)(i) or (ii) of this section are met.
(i) If the repair is technically infeasible, would require a vent
blowdown, a compressor station
[[Page 17065]]
shutdown, a well shutdown or well shut-in, or would be unsafe to repair
during operation of the unit, the repair must be completed during the
next scheduled compressor station shutdown for maintenance, scheduled
well shutdown, scheduled well shut-in, after a scheduled vent blowdown,
or within 2 years of detecting the fugitive emissions, whichever is
earliest. A vent blowdown is the opening of one or more blowdown valves
to depressurize major production and processing equipment, other than a
storage vessel.
(ii) If the repair requires replacement of a fugitive emissions
component or a part thereof, but the replacement cannot be acquired and
installed within the repair timelines specified in paragraphs (h)(1)
and (2) of this section due to either of the conditions specified in
paragraph (h)(3)(ii)(A) or (B) of this section, the repair must be
completed in accordance with paragraph (h)(3)(ii)(C) of this section
and documented in accordance with Sec. 60.5420b(c)(14)(v)(I).
(A) Valve assembly supplies had been sufficiently stocked but are
depleted at the time of the required repair.
(B) A replacement fugitive emissions component or a part thereof
requires custom fabrication.
(C) The required replacement must be ordered no later than 10
calendar days after the first attempt at repair. The repair must be
completed as soon as practicable, but no later than 30 calendar days
after receipt of the replacement component, unless the repair requires
a compressor station or well shutdown. If the repair requires a
compressor station or well shutdown, the repair must be completed in
accordance with the timeframe specified in paragraph (h)(3)(i) of this
section.
(4) Each identified source of fugitive emissions must be resurveyed
to complete repair according to the requirements of paragraphs
(h)(4)(i) through (v) of this section, to ensure that there are no
fugitive emissions.
(i) The operator may resurvey the fugitive emissions components to
verify repair using either Method 21 of appendix A-7 to this part or
OGI, except as specified in paragraph (h)(4)(v) of this section.
(ii) For each repair that cannot be made during the monitoring
survey when the fugitive emissions are initially found, a digital
photograph must be taken of that component, or the component must be
tagged during the monitoring survey when the fugitive emissions were
initially found for identification purposes and subsequent repair. The
digital photograph must include the date that the photograph was taken
and must clearly identify the component by location within the site
(e.g., the latitude and longitude of the component or by other
descriptive landmarks visible in the picture).
(iii) Operators that use Method 21 of appendix A-7 to this part to
resurvey the repaired fugitive emissions components are subject to the
resurvey provisions specified in paragraphs (h)(4)(iii)(A) and (B) of
this section.
(A) A fugitive emissions component is repaired when the Method 21
instrument indicates a concentration of less than 500 ppmv above
background or when no soap bubbles are observed when the alternative
screening procedures specified in section 8.3.3 of Method 21 of
appendix A-7 to this part are used.
(B) Operators must use the Method 21 monitoring requirements
specified in paragraph (c)(8)(ii) of this section or the alternative
screening procedures specified in section 8.3.3 of Method 21 of
appendix A-7 to this part.
(iv) Operators that use OGI to resurvey the repaired fugitive
emissions components are subject to the resurvey provisions specified
in paragraphs (h)(4)(iv)(A) and (B) of this section.
(A) A fugitive emissions component is repaired when the OGI
instrument shows no indication of visible emissions.
(B) Operators must use the OGI monitoring requirements specified in
paragraph (c)(7) of this section.
(v) For fugitive emissions identified using AVO detection methods,
the operator may resurvey using those same methods, Method 21 of
appendix A-7 to this part, or OGI. For operators that use AVO detection
methods, a fugitive emissions component is repaired when there are no
indications of fugitive emissions using these methods.
(i) Initial compliance. You must demonstrate initial compliance
with the standards that apply to fugitive emissions components affected
facilities as required by Sec. 60.5410b(k).
(j) Continuous compliance. You must demonstrate continuous
compliance with the standards that apply to fugitive emissions
components affected facilities as required by Sec. 60.5415b(l).
(k) Reporting and recordkeeping. You must comply with the reporting
requirements as specified in Sec. 60.5420b(b)(1) and (9), and the
recordkeeping requirements as specified in Sec. 60.5420b(c)(16).
(l) Well closure requirements. You must complete the requirements
specified in paragraphs (l)(1) through (4) of this section.
(1) You must submit a well closure plan to the Administrator within
30 days of the cessation of production from all wells located at the
well site as specified in Sec. 60.5420b(a)(4)(i). The well closure
plan must include, at a minimum, the information specified in
paragraphs (l)(1)(i) through (iii) of this section.
(i) Description of the steps necessary to close all wells at the
well site, including permanent plugging of all wells;
(ii) Description of the financial requirements and disclosure of
financial assurance to complete closure; and
(iii) Description of the schedule for completing all activities in
the well closure plan.
(2) You must submit a notification as specified in Sec.
60.5420b(a)(4)(ii) of intent to close the well site to the
Administrator 60 days before you begin well closure activities.
(3) You must conduct a survey of the well site using OGI, including
each closed well, after completing all well closure activities outlined
in the well closure plan specified in paragraph (l)(1) of this section.
If any emissions are imaged by the OGI instrument, then you must take
steps to eliminate those emissions and you must resurvey the source of
emissions. You must repeat steps to eliminate emissions and resurvey
the source of emissions until no emissions are imaged by the OGI
instrument. You must update the well closure plan specified in
paragraph (l)(1) of this section to include the video of the OGI survey
demonstrating closure of all wells at the site.
(4) You must maintain the records specified in Sec.
60.5420b(c)(14) and submit the reports specified in Sec.
60.5420b(b)(9).
Sec. 60.5398b What alternative GHG and VOC standards apply to
fugitive emissions components affected facilities and what inspection
and monitoring requirements apply to covers and closed vent systems
when using an alternative technology?
This section provides alternative GHG and VOC standards for
fugitive emissions components affected facilities in Sec. 60.5397b and
alternative continuous inspection and monitoring requirements for
covers and closed vent systems in Sec. 60.5416b(a)(1)(ii) and (iii),
(2)(ii) through (iv), and (3)(iii) and (iv). If you choose to use an
alternative standard under this section, you must submit the
notification under paragraph (a) of this section. If you choose to
demonstrate compliance with the alternative GHG and VOC standards
through periodic screening, you are subject to the requirements in
paragraph (b) of this section. If you choose to demonstrate compliance
through a continuous monitoring system, you are
[[Page 17066]]
subject to the requirements in paragraph (c) of this section. The
technology used for periodic screenings under paragraph (b) of this
section or continuous monitoring under paragraph (c) of this section
must be approved in accordance with paragraph (d) of this section.
(a) Notification. If you choose to demonstrate compliance with the
alternative GHG and VOC standards in either paragraph (b) or (c) of
this section, you must notify the Administrator of adoption of the
alternative standards in the first annual report following
implementation of the alternative standards, as specified in Sec.
60.5424b(a). Once you have implemented the alternative standards, you
must continue to comply with the alternative standards.
(b) Periodic Screening. You may choose to demonstrate compliance
for your fugitive emissions components affected facility and compliance
with continuous inspection and monitoring requirements for your covers
and closed vent systems through periodic screenings using any methane
measurement technology approved in accordance with paragraph (d) of
this section. If you choose to demonstrate compliance using periodic
screenings, you must comply with the requirements in paragraphs (b)(1)
through (5) of this section and comply with the recordkeeping and
reporting requirements in Sec. 60.5424b.
(1) You must use one or more alternative test method(s) approved
per paragraph (d) of this section to conduct periodic screenings.
(i) The required frequencies for conducting periodic screenings are
listed in tables 1 and 2 to this subpart. You must choose the
appropriate frequency for conducting periodic screenings based on the
minimum aggregate detection threshold of the method used to conduct the
periodic screenings. You must also use tables 1 and 2 to this subpart
to determine whether you must conduct an annual fugitive emissions
survey using OGI, except as provided in paragraph (b)(1)(ii) of this
section.
(ii) For well sites, centralized production facilities, and
compressor stations subject to quarterly OGI monitoring surveys in
Sec. 60.5397b(g)(1)(iv) and/or (v), prior to March 9, 2026, if you use
an alternative test method approved per paragraph (d) of this section
with a minimum aggregated detection threshold less than or equal to 3
kg/hr, in lieu of conducting periodic screening events at the frequency
specified in paragraph (b)(1)(i) of this section, you may conduct
periodic screening events quarterly. After March 9, 2026, you must
conduct periodic screening events at the frequency specified in
paragraph (b)(1)(i) of this section.
(iii) Use of table 1 or 2 to this subpart is based on the required
frequency for conducting monitoring surveys in Sec. 60.5397b(g)(1)(i)
through (v).
(iv) You may replace one or more individual periodic screening
events required by table 1 or 2 to this subpart with an OGI survey. The
OGI survey must be conducted according to the requirements outlined in
Sec. 60.5397b.
(v) If you use multiple methods to conduct periodic screenings, you
must conduct all periodic screenings, regardless of the method used for
the individual periodic screening event, at the frequency required for
the alternative test method with the highest aggregate detection
threshold (e.g., if you use methods with aggregate detection thresholds
of 15 kg/hr, your periodic screenings must be conducted monthly). You
must also conduct an annual OGI survey if an annual OGI survey is
required for the alternative test method with the highest aggregate
detection threshold.
(2) You must develop a monitoring plan that covers the collection
of fugitive emissions components, covers, and closed vent systems at
each site where you will use periodic screenings to demonstrate
compliance. You may develop a site-specific monitoring plan, or you may
include multiple sites that you own or operate in one plan. At a
minimum, the monitoring plan must contain the information specified in
paragraphs (b)(2)(i) through (ix) of this section.
(i) Identification of each site that will be monitored through
periodic screening, including latitude and longitude coordinates of the
site in decimal degrees to an accuracy and precision of at least four
decimals of a degree using the North American Datum of 1983.
(ii) Identification of the alternative test method(s) approved per
paragraph (d) of this section that will be used for periodic screenings
and the spatial resolution (i.e., component-level, area-level, or
facility-level) of the technology used for each method.
(iii) Identification of and contact information for the entities
that will be performing the periodic screenings.
(iv) Required frequency for conducting periodic screenings, based
on the criteria outlined in paragraph (b)(1) of this section.
(v) If you are required to conduct an annual OGI survey by
paragraph (b)(1)(i) or (iii) of this section or you choose to replace
any individual screening event with an OGI survey, your monitoring plan
must also include the information required by Sec. 60.5397b(b).
(vi) Procedures for conducting monitoring surveys required by
paragraphs (b)(5)(ii)(A), (b)(5)(iii)(A), and (b)(5)(iv)(A) of this
section. At a minimum, your monitoring plan must include the
information required by Sec. 60.5397b(c)(2), (3), (7), and (8), and
(d), as applicable. The provisions of Sec. 60.5397b(d)(3) do not apply
for purposes of conducting monitoring surveys required by paragraphs
(b)(5)(ii) through (iv) of this section.
(vii) Procedures and timeframes for identifying and repairing
fugitive emissions components, covers, and closed vent systems from
which emissions are detected.
(viii) Procedures and timeframes for verifying repairs for fugitive
emissions components, covers, and closed vent systems.
(ix) Records that will be kept and the length of time records will
be kept.
(3) You must conduct the initial screening of your site according
to the timeframes specified in (b)(3)(i) through (v) of this section.
(i) Within 90 days of the startup of production for each fugitive
emissions components affected facility and storage vessel affected
facility located at a new well site or centralized production facility.
(ii) Within 90 days of the startup of a new compressor station for
each fugitive emissions components affected facility and storage vessel
affected facility located at a new compressor station.
(iii) Within 90 days of the startup of production after
modification for each modified fugitive emissions components affected
facility and storage vessel affected facility at a well site or
centralized production facility.
(iv) Within 90 days of modification for each modified fugitive
emissions components affected facility and storage vessel affected
facility at a compressor station.
(v) No later than the final date by which the next monitoring
survey required by Sec. 60.5397b(g)(1)(i) through (v) would have been
required to be conducted if you were previously complying with the
requirements in Sec. 60.5397b and Sec. 60.5416b(a)(1)(ii) and (iii),
(2)(ii) through (iv), and (3)(iii) and (iv).
(4) If you are required to conduct an annual OGI survey by
paragraph (b)(1)(i) or (iii) of this section, you must conduct OGI
surveys according to the schedule in paragraphs (b)(4)(i) through (iv)
of this section.
(i) You must conduct the initial OGI survey no later than 12
calendar months
[[Page 17067]]
after conducting the initial screening event in paragraph (b)(3) of
this section.
(ii) Each subsequent OGI survey must be conducted no later than 12
calendar months after the previous OGI survey was conducted. Each
identified source of fugitive emissions during the OGI survey shall be
repaired in accordance with Sec. 60.5397b(h).
(iii) If you replace a periodic screening event with an OGI survey
or you are required to conduct a monitoring survey in accordance with
paragraph (b)(5)(ii)(A) of this section prior to the date that your
next OGI survey under paragraph (b)(4)(ii) of this section is due, the
OGI survey conducted in lieu of the periodic screening event or the
monitoring survey under paragraph (b)(5)(ii)(A) of this section can be
used to fulfill the requirements of paragraph (b)(4)(ii) of this
section. The next OGI survey is required to be conducted no later than
12 calendar months after the date of the survey conducted under
paragraph (b)(1)(iv) or (b)(5)(ii)(A) of this section.
(iv) You cannot use a monitoring survey conducted under paragraph
(b)(5)(iii)(A) or (b)(5)(iv)(A) of this section to fulfill the
requirements of paragraph (b)(4)(ii) of this section unless the
monitoring survey included all fugitive emission components at the
site.
(5) You must investigate confirmed detections of emissions from
periodic screening events and repair each identified source of
emissions in accordance with paragraphs (b)(5)(i) through (vii) of this
section.
(i) You must receive the results of the periodic screening no later
than 5 calendar days after the screening event occurs.
(ii) If you use an alternative test method with a facility-level
spatial resolution to conduct a periodic screening event and the
results of the periodic screening event indicate a confirmed detection
of emissions from an affected facility, you must take the actions
listed in paragraphs (b)(5)(ii)(A) through (C) of this section.
(A) You must conduct a monitoring survey of the entire fugitive
emissions components affected facility following the procedures in your
monitoring plan. During the survey, you must observe each fugitive
emissions component for fugitive emissions.
(B) You must inspect all covers and closed vent system(s) with OGI
or Method 21 to appendix A-7 to this part in accordance with the
requirements in Sec. 60.5416b(b)(1) through (4), as applicable.
(C) You must conduct a visual inspection of all covers and closed
vent systems to identify if there are any defects, as defined in Sec.
60.5416b(a)(1)(ii), (a)(2)(iii), or (a)(3)(i), as applicable.
(iii) If you use an alternative test method with an area-level
spatial resolution to conduct a periodic screening event and the
results of the periodic screening event indicate a confirmed detection
of emissions from an affected facility, you must take the actions
listed in paragraphs (b)(5)(iii)(A) and (B) of this section, as
applicable.
(A) You must conduct a monitoring survey of all your fugitive
emissions components located within a 4-meter radius of the location of
the periodic screening's confirmed detection. You must follow the
procedures in your monitoring plan when conducting the survey.
(B) If the confirmed detection occurred in the portion of a site
that contains a storage vessel or a closed vent system, you must
inspect all covers and all closed vent systems that are connected to
all storage vessels and closed vent systems that are within a 2-meter
radius of the location of the periodic screening's confirmed detection
(i.e., you must inspect the whole system that is connected to the
portion of the system in the radius of the detected event, not just the
portion of the system that falls within the radius of the detected
event).
(1) You must inspect the cover(s) and closed vent system(s) with
OGI or Method 21 to appendix A-7 to this part in accordance with the
requirements in Sec. 60.5416b(b)(1) through (4), as applicable.
(2) You must conduct a visual inspection of the closed vent
system(s) and cover(s) to identify if there are any defects, as defined
in Sec. 60.5416b(a)(1)(ii), (a)(2)(iii), or (a)(3)(i), as applicable.
(iv) If you use an alternative test method with a component-level
spatial resolution to conduct a periodic screening event and the
results of the periodic screening event indicate a confirmed detection
of emissions from an affected facility, you must take the actions
listed in paragraphs (b)(5)(iv)(A) and (B) of this section, as
applicable.
(A) You must conduct a monitoring survey of the all the fugitive
emissions components located within a 1-meter radius of the location of
the periodic screening's confirmed detection. You must follow the
procedures in your monitoring plan when conducting the survey.
(B) If the confirmed detection occurred in the portion of a site
that contains a storage vessel or a closed vent system, you must
inspect all covers and all closed vent systems that are connected to
all storage vessels and closed vent systems that are within a 0.5-meter
radius of the location of the periodic screening's confirmed detection
(i.e., you must inspect the whole system that is connected to the
portion of the system in the radius of the detected event, not just the
portion of the system that falls within the radius of the detected
event).
(1) You must inspect the cover(s) and closed vent system(s) with
OGI or Method 21 to appendix A-7 to this part in accordance with the
requirements in Sec. 60.5416b(b)(1) through (4), as applicable.
(2) You must conduct a visual inspection of the closed vent
system(s) and cover(s) to identify if there are any defects, as defined
in Sec. 60.5416b(a)(1)(ii), (a)(2)(iii), or (a)(3)(i), as applicable.
(v) You must repair all sources of fugitive emissions in accordance
with Sec. 60.5397b(h) and all emissions or defects of covers and
closed vent systems in accordance with Sec. 60.5416b(b)(5), except as
specified in this paragraph (b)(5)(v). Except as allowed by Sec.
60.5397b(h)(3) and Sec. 60.5416b(b)(6), all repairs must be completed,
including the resurvey verifying the repair, within 30 days of
receiving the results of the periodic screening in paragraph (b)(5)(i)
of this section.
(vi) If the results of the periodic screening event in paragraph
(b)(5)(i) of this section indicate a confirmed detection at an affected
facility, and the ground-based monitoring survey and inspections
required by paragraphs (b)(5)(ii) through (iv) of this section
demonstrate the confirmed detection was caused by a failure of a
control device used to demonstrate continuous compliance under this
subpart, you must initiate an investigative analysis to determine the
underlying primary and other contributing cause(s) of such failure
within 24 hours of receiving the results of the monitoring survey and/
or inspection. As part of the investigation, you must determine if the
control device is operating in compliance with the applicable
requirements of Sec. 60.5415b and Sec. 60.5417b, and if not, what
actions are necessary to bring the control device into compliance with
those requirements as soon as possible and prevent future failures of
the control device from the same underlying cause(s).
(vii) If the results of the inspections required in paragraphs
(b)(5)(ii) through (iv) of this section indicate that there is an
emission or defect in your cover or closed vent system, you must
perform
[[Page 17068]]
an investigative analysis to determine the underlying primary and other
contributing cause(s) of emissions from your cover or closed vent
system within 5 days of completing the inspection required by
paragraphs (b)(5)(ii) through (iv) of this section. The investigative
analysis must include a determination as to whether the system was
operated outside of the engineering design analysis and whether updates
are necessary for the cover or closed vent system to prevent future
emissions from the cover and closed vent system.
(6) You must maintain records as specified in Sec. 60.5420b(c)(4)
through (7), (14), and (15), and Sec. 60.5424b(c).
(7) You must submit reports as specified in Sec. 60.5424b.
(c) Continuous monitoring. You may choose to demonstrate compliance
for your fugitive emissions components affected facility and compliance
with continuous inspection and monitoring requirements for your covers
and closed vent systems through continuous monitoring using a
technology approved in accordance with paragraph (d) of this section.
If you choose to demonstrate compliance using continuous monitoring,
you must comply and develop a monitoring plan consistent with the
requirements in paragraphs (c)(1) through (9) of this section and
comply with the recordkeeping and reporting requirements in Sec.
60.5424b.
(1) For the purpose of this section, continuous monitoring means
the ability of a methane monitoring system to determine and record a
valid methane mass emissions rate or equivalent of affected facilities
at least once for every 12-hour block.
(i) The detection threshold of the system must be such that it can
detect at least 0.40 kg/hr (0.88 lb/hr) of methane.
(ii) The health of the devices used within the continuous
monitoring system must be confirmed for power and function at least
twice every six-hour block.
(iii) The continuous monitoring system must transmit all applicable
valid data at least once every 24-hours. The continuous monitoring
system must transmit all valid data collected, including health checks
required in paragraph (c)(1)(ii) of this section.
(iv) The continuous monitoring system must continuously collect
data as specified in paragraph (c)(1) of this section, except as
specified in paragraphs (c)(1)(iv)(A) through (D) of this section:
(A) The rolling 12-month average operational downtime of the
continuous monitoring system must be less than or equal to 10 percent.
(B) Operational downtime of the continuous monitoring system is
defined as a period of time for which any monitor fails to collect or
transmit data as specified in paragraph (c)(1) of this section or any
monitor is out-of-control as specified in paragraph (c)(1)(iv)(C) of
this section.
(C) A monitor is out-of-control if it fails ongoing quality
assurance checks, as specified in the alternative test method approved
under paragraph (d) of this section, or if the monitor output is
outside of range. The beginning of the out-of-control period is defined
as the time of the failure of the quality assurance check. The end of
the out-of-control period is defined as the time when either the
monitor passes a subsequent quality assurance check, or a new monitor
is installed. The out-of-control period for a monitor outside of range
starts at the time when the monitor first reads outside of range and
ends when the monitor reads within range again.
(D) The downtime for the continuous monitoring system must be
calculated each calendar month. Once 12 months of data are available,
at the end of each calendar month, you must calculate the 12-month
average by averaging that month with the previous 11 calendar months.
You must determine the rolling 12-month average by recalculating the
12-month average at the end of each month.
(2) You must develop a monitoring plan that covers the collection
of fugitive emissions components, covers, and closed vent systems for
each site where continuous monitoring will be used to demonstrate
compliance. At a minimum, the monitoring plan must contain the
information specified in paragraphs (c)(2)(i) through (xii) of this
section.
(i) Identification of each site to be monitored through continuous
monitoring, including latitude and longitude coordinates of the site in
decimal degrees to an accuracy and precision of at least four decimals
of a degree using the North American Datum of 1983.
(ii) Identification of the alternative test method(s) approved
under paragraph (d) of this section used for the continuous monitoring,
including the detection principle; the manufacturer, make, and model;
instrument manual, if applicable; and the manufacturer's recommended
maintenance schedule.
(iii) If the continuous monitoring system is administered through a
third-party provider, contact information where the provider can be
reached 24 hours a day.
(iv) Number and location of monitors. If the continuous monitoring
system uses open path technology, you must identify the location of any
reflectors used. These locations should be identified by latitude and
longitude coordinates in decimal degrees to an accuracy and precision
of at least five decimals of a degree using the North American Datum of
1983.
(v) Discussion of system calibration requirements, including but
not limited to, the calibration procedures and calibration schedule for
the detection systems and meteorology systems.
(vi) Identification of critical components and infrastructure
(e.g., power, data systems) and procedures for their repairs.
(vii) Procedures for out-of-control periods.
(viii) Procedures for establishing baseline emissions, including
the identification of any sources with methane emissions not subject to
this subpart. The procedures for establishing the baseline emissions
must account for variability in the operation of the site. Operation of
the site during the development of the baseline emissions must
represent the site's expected annual production or throughput.
(ix) Procedures for determining when a fugitive emissions event is
detected by the continuous monitoring technology.
(x) Procedures and timeframes for identifying and repairing
fugitive emissions components, covers, and closed vent systems from
which emissions are detected.
(xi) Procedures and timeframes for verifying repairs for fugitive
emissions components, covers, and closed vent systems.
(xii) Records that will be kept and the length of time records will
be kept.
(3) You must install and begin conducting monitoring with your
continuous monitoring system according to the timeframes specified in
paragraphs (c)(3)(i) through (v) of this section.
(i) Within 120 days of the startup of production for each fugitive
emissions components affected facility and storage vessel affected
facility located at a new well site or centralized production facility.
(ii) Within 120 days of the startup of a new compressor station for
each fugitive emissions components affected facility and storage vessel
affected facility located at a new compressor station.
(iii) Within 120 days of the startup of production after
modification for each modified fugitive emissions components affected
facility and storage vessel
[[Page 17069]]
affected facility at a well site or centralized production facility.
(iv) Within 120 days of modification for each modified fugitive
emissions components affected facility and storage vessel affected
facility at a compressor station.
(v) No later than the final date by which the next monitoring
survey required by Sec. 60.5397b(g)(1)(i) through (v) would have been
required to be conducted if you were previously complying with the
requirements in Sec. 60.5397b and Sec. 60.5416b(a)(1)(ii) and (iii),
(2)(ii) through (iv), and (3)(iii) and (iv).
(4) You are subject to the following action-levels as specified in
paragraphs (c)(4)(i) and (ii) of this section for any affected
facilities located at a well site, centralized production facility, or
compressor station.
(i) For affected facilities located at a wellhead only well site,
the action levels are as follows:
(A) The 90-day rolling average action-level is 1.2 kg/hr (2.6 lb/
hr) of methane over the site-specific baseline emissions.
(B) The 7-day rolling average action level is 15 kg/hr (34 lb/hr)
of methane over site-specific baseline emissions.
(ii) For affected facilities located at well sites with major
production and processing equipment (including small well sites),
centralized production facilities, and compressor stations, the action
levels are as follows:
(A) The 90-day rolling average action-level is 1.6 kg/hr (3.6 lb/
hr) of methane over the site-specific baseline emissions.
(B) The 7-day rolling average action level is 21 kg/hr (46 lb/hr)
of methane over the site-specific baseline emissions.
(5) You must establish site-specific baseline emissions upon
initial installation and activation of a continuous monitoring system.
You must establish the baseline emissions under the conditions outlined
in paragraphs (c)(5)(i) through (iii) of this section. You must
determine the baseline emission rates according to paragraphs
(c)(5)(iv) and (v) of this section. The baseline must be established
initially and any time there is a major change to the processing
equipment at a well site (including small well sites), centralized
production facility, or compressor station.
(i) Inspect all fugitive emissions components according to the
requirements in Sec. 60.5397b and covers and closed vent systems
according to the requirements in Sec. 60.5416b. This includes all
fugitive emissions components, covers, and closed vent systems,
regardless of whether they are regulated by this subpart. Repairs of
any fugitive emissions, leaks, or defects found during the inspection
must be completed prior to beginning the period in paragraph
(c)(5)(iii) of this section.
(ii) Verify control devices (e.g., flares) on all affected sources
are operating in compliance with the applicable requirements of Sec.
60.5415b and Sec. 60.5417b. You must ensure that all control devices
are operating in compliance with the applicable regulations prior to
beginning the period in paragraph (b)(5)(iii) of this section. Verify
that all other methane emission sources (e.g., reciprocating engines)
located at the site are operating consistent with any applicable
regulations. You must ensure that these sources are operating in
compliance with the applicable regulations prior to beginning the
period in paragraph (b)(5)(iii) of this section.
(iii) Using the alternative test method approved under paragraph
(d) of this section, record the site-level emission rate from your
continuous monitoring system for 30 operating days. You must minimize
any activities that are not normal, day-to-day activities during this
30 operating day period. Document any maintenance activities and the
period (including the start date and time and end date and time) such
activities occurred during the 30 operating day period.
(iv) Determine the site-specific baseline by calculating the mean
emission rate (kg/hr of methane) for the 30 operating day period, less
any time periods when maintenance activities were conducted.
(v) The site-specific baseline emission rate must be no more than
10 times the applicable 90-day action-level defined in paragraphs
(c)(4)(i) and (ii) of this section.
(6) Calculate the emission rate from your site according to
paragraphs (c)(6)(i) through (iii) of this section. Compare the
emission rate calculated in this paragraph (c)(6) to the appropriate
action levels in paragraph (c)(4) of this section to determine whether
you have exceeded an action level.
(i) Each calendar day, calculate the daily average mass emission
rate in kg/hr of methane from your continuous monitoring system.
(ii) Once the system has been operating for 7 calendar days, at the
end of each calendar day calculate the 7-day average mass emission rate
by averaging the mass emission rate from that day with the mass
emission rate from the previous 6 calendar days. Subtract the site-
specific baseline mass emission rate from the 7-day average mass
emission rate when comparing the mass emission rate to the applicable
action level. Determine the 7-day rolling average by recalculating the
7-day average each calendar day, less the site-specific baseline.
(iii) Once the system has been operating for 90 calendar days, at
the end of each calendar day calculate the 90-day average mass emission
rate by averaging the mass emission rate from that day with the mass
emission rate from the previous 89 calendar days. Subtract the site-
specific baseline emission rate from the 90-day average mass emission
rate when comparing the mass emission rate to the applicable action
level. Determine the 90-day rolling average by recalculating the 90-day
average each calendar day, less the site-specific baseline.
(7) Within 5 days of determining that either of your action levels
in paragraph (c)(4) of this section has been exceeded, you must
initiate an investigative analysis to determine the underlying primary
and contributing cause(s) of such exceedance and actions to be taken to
reduce the mass emission rate below the applicable action level.
(i) You must complete the investigative analysis and take initial
steps to bring the mass emission rate below the action level no later
than 5 days after determining there is an exceedance of the action
level in paragraph (c)(4)(i)(B) or (c)(4)(ii)(B) of this section.
(ii) You must complete the investigative analysis and take initial
steps to bring the mass emission rate below the action level no later
than 30 days after determining there is an exceedance of the action
level in paragraph (c)(4)(i)(A) or (c)(4)(ii)(A) of this section.
(8) You must develop a mass emission rate reduction plan if you
meet any of the criteria in paragraphs (c)(8)(i) through (iii) of this
section. The plan must describe the action(s) completed to date to
reduce the mass emission rate below the action level, additional
measures that you propose to employ to reduce methane emissions below
the action level, and a schedule for completion of these measures. You
must submit the plan to the Administrator within 60 days of initially
determining there is an exceedance of an action level in paragraph
(c)(4) of this section.
(i) If, upon completion of the initial actions required under
paragraph (c)(7) of this section, the average mass emission rate for
the following 30-day period is not below the applicable action level in
paragraph (c)(4)(i)(A) or (c)(4)(ii)(A) of this section. The beginning
of the 30-day period starts on the calendar day following completion of
the initial actions in paragraph (c)(7) of this section.
[[Page 17070]]
(ii) If, upon completion of the initial actions required under
paragraph (c)(6) of this section, the average mass emission rate for
the following 24-hour period is not below the applicable action level
in paragraph (c)(4)(i)(B) or (c)(4)(ii)(B) of this section. The average
mass emission rate will be the mass emission rate calculated according
to paragraph (c)(6)(i) of this section for the calendar day following
completion of the initial corrective actions in paragraph (c)(7) of
this section.
(iii) All actions needed to reduce the average mass emission rate
below the action level require more than 30 days to implement.
(9) You must maintain the records as specified in Sec.
60.5420b(c)(4) through (c)(7), (c)(14) and (c)(15), and Sec.
60.5424b(e). You must submit the reports as specified in Sec.
60.5420b(b)(1), and (b)(4) through (10) and Sec. 60.5424b.
(d) Alternative Test Method for Methane Detection Technology. Any
alternative test method for methane detection technology used to meet
the requirements specified in paragraphs (b) or (c) of this section or
Sec. 60.5371b must be approved by the Administrator as specified in
this paragraph (d). Approval of an alternative test method for methane
detection technology will include consideration of the combination of
the measurement technology and the standard protocol for its operation.
Any entity meeting the requirements in paragraph (d)(2) of this section
may submit a request for an alternative test method for methane
detection technology. At a minimum, the request must follow the
requirements outlined in paragraph (d)(3) of this section. Approved
alternative test methods for methane detection technology that are
broadly applicable will be posted on the EPA's Emission Measurement
Center web page (https://www.epa.gov/emc/oil-and-gas-alternative-test-methods). Any owner or operator that meets the specific applicability
for the alternative test method, as outlined in the alternative test
method for methane detection technology, may use the alternative test
method to comply with the requirements of paragraph (b) or (c) of this
section, as applicable, in lieu of the requirements for fugitive
emissions components affected facilities in Sec. 60.5397b and covers
and closed vent systems in Sec. 60.5416b(a)(1)(ii) and (iii),
(a)(2)(ii) through (iv), and (a)(3)(iii) and (iv). Certified third-
party notifiers may use the alternative test method to identify super-
emitter events in Sec. 60.5371b(b)(1)(ii).
(1) A request for an alternative test method for methane detection
technology, along with the required supporting information, must be
submitted to the EPA through the alternative methane detection
technology portal at https://www.epa.gov/emc/oil-and-gas-alternative-test-methods. The EPA may make all the information submitted through
the portal available to the public without further notice to you. Do
not use the portal to submit information you claim as confidential
business information (CBI). If you wish to assert a CBI claim for some
of the information in your submittal, submit the portion of the
information claimed as CBI to the OAQPS CBI office. Clearly mark the
information that you claim to be CBI. Information not marked as CBI may
be authorized for public release without prior notice. Information
marked as CBI will not be disclosed except in accordance with
procedures set forth in 40 CFR part 2. All CBI claims must be asserted
at the time of submission. Anything submitted using the portal cannot
later be claimed CBI. The preferred method to receive CBI is for it to
be transmitted electronically using email attachments, File Transfer
Protocol, or other online file sharing services. Electronic submissions
must be transmitted directly to the OAQPS CBI Office at the email
address [email protected] and should include clear CBI markings and be
flagged to the attention of the Leader, Measurement Technology Group.
If assistance is needed with submitting large electronic files that
exceed the file size limit for email attachments, and if you do not
have your own file sharing service, please email [email protected] to
request a file transfer link. If you cannot transmit the file
electronically, you may send CBI information through the postal service
to the following address: U.S. EPA, Attn: OAQPS Document Control
Officer and Measurement Technology Group Leader, Mail Drop: C404-02,
109 T.W. Alexander Drive, P.O. Box 12055, RTP, North Carolina 27711.
The mailed CBI material should be double wrapped and clearly marked.
Any CBI markings should not show through the outer envelope.
(i) The Administrator will complete an initial review for
completeness within 90 days of receipt and notify the submitter of the
results of the review.
(ii) If the entity submitting the request does not meet the
requirements in paragraph (d)(2) of this section or the request does
not contain the information in paragraph (d)(3) of this section, the
submitter will be notified. The submitter may choose to revise the
information and submit a new request for an alternative test method.
(iii) Within 270 days of receipt of an alternative test method
request that was determined to be complete, the Administrator will
determine whether the requested alternative test method is adequate for
indicating compliance with the requirements for monitoring fugitive
emissions components affected facilities in Sec. 60.5397b and
continuous inspection and monitoring of covers and closed vent systems
in Sec. 60.5416b and/or for identifying super-emitter events in Sec.
60.5371b. The Administrator will issue either an approval or
disapproval in writing to the submitter. Approvals may be considered
site-specific or more broadly applicable. Broadly applicable
alternative test methods and approval letters will be posted at https://www.epa.gov/emc/oil-and-gas-approved-alternative-test-methods-approvals. If the Administrator fails to provide the submitter a
decision on approval or disapproval within 270 days, the alternative
test method will be given conditional approval status and posted on
this same web page. If the Administrator finds any deficiencies in the
request and disapproves the request in writing, the owner or operator
may choose to revise the information and submit a new request for an
alternative test method.
(iv) If the Administrator finds reasonable grounds to dispute the
results obtained by any alternative test method for the purposes of
demonstrating compliance with a relevant standard, the Administrator
may require you to demonstrate compliance according to Sec. 60.5397b
for fugitive emissions components affected facilities and Sec.
60.5416b for covers and closed vent systems.
(2) Any entity may submit an alternative test method for
consideration, so long as you meet the requirements in paragraphs
(d)(2)(i) through (iv) of this section.
(i) An entity is limited to any individual or organization located
in or that has representation in the United States.
(ii) If an entity is not considered an owner or operator of an
affected facility regulated under this subpart or subpart OOOOa of this
part or is not the owner or operator of a designated facility regulated
under subpart OOOOc of this part, the provisions of paragraphs
(d)(2)(ii)(A) and (B) of this section apply.
(A) The entity must directly represent the provider of the
measurement system using advanced methane detection technology.
(B) The measurement system must have been applied to methane
measurements or monitoring in the oil
[[Page 17071]]
and gas sector either domestically or internationally.
(iii) The underlying technology or technologies must be readily
available for use, meaning that the measurement system using these
technologies has either been:
(A) Sold, leased, or licensed, or offered for sale, lease, or
license to the general public or;
(B) Developed by an owner or operator for internal use and/or use
by external partners.
(iv) The entity must be able to provide and submit to the
Administrator the information required in paragraph (d)(3) of this
section.
(3) The request must contain the information specified in
paragraphs (d)(3)(i) through (vii) of this section.
(i) The submitter's name, mailing address, phone number and email
address.
(ii) The desired applicability of the technology (i.e., site-
specific, basin-specific, or broadly applicable across the sector,
super-emitter detection).
(iii) Description of the measurement technology, including the
physical components, the scientific theory, and the known limitations.
At a minimum, this description must contain the information in
paragraphs (d)(3)(iii)(A) through (D) of this section.
(A) Description of scientific theory and appropriate references
outlining the underlying g technology (e.g., reference material,
literature review).
(B) Description of the physical instrumentation.
(C) Type of measurement and application (e.g., remote or in-situ
measurements, mobile, airborne).
(D) Known limitation of the technology, including application
limitations and weather limitations.
(iv) Description of how the measurement technology is converted to
a methane mass emission rate (i.e., kg/hr of methane) or equivalent. At
a minimum this description must contain the information in paragraphs
(d)(3)(iv)(A) through (F) of this section.
(A) Detailed workflow and description covering all steps and
processes from measurement technology signal output to final, validated
mass emission rate or equivalent. These workflows must cover the
material in paragraph (d)(3)(v) of this section and put all technical
components into context. The workflow must also cover the technology
from data collection to generation of the final product and identify
any raw data processing procedures; identification of whether
processing steps are manual or automated, and when and what quality
assurance checks are made to the data, including raw data, processed
data, and output data.
(B) Description of how any meteorological data used are collected
or sourced, including a description how the data are used.
(C) Description of any model(s) (e.g., AERMOD) used, including how
inputs are determined or derived.
(D) All calculations used, including the defined variables for any
of these calculations and a description of their purposes.
(E) Descriptions of a-priori methods and datasets used, including
source and version numbers when applicable.
(F) Description of algorithms/machine learning procedures used in
the data processing, if applicable.
(v) Description of how all data collected and generated by the
measurement system are handled and stored. At a minimum this
description must contain the information in paragraphs (d)(3)(v)(A)
through (C) of this section.
(A) How the data, including metadata, are collected, maintained,
and stored.
(B) A description of how raw data streams are processed and
manipulated, including how the resultant data processing is documented
and how version controlled is maintained.
(C) A description of what data streams are provided to the end-user
of the data and how the data are delivered to the end-user.
(vi) Supporting information verifying that the technology meets the
aggregate detection threshold(s) defined in paragraphs (b) and/or (c)
of this section or in Sec. 60.5371b, including supporting data to
demonstrate the aggregate detection threshold of the measurement
technology as applied in the field and if applicable, how probability
of detection is determined. For the purpose of this subpart the average
aggregate detection threshold is the average of all site-level
detection thresholds from a single deployment (e.g., a singular flight
that surveys multiple well sites, centralized production facility, and/
or compressor stations) of a technology, unless this technology is to
be applied to Sec. 60.5371b. When the technology is applied to Sec.
60.5371b, then the aggregate detection threshold is the average of all
site-level detection thresholds from a single deployment in the same
basin and field. At a minimum, you provide the information identified
in paragraphs (d)(3)(vi)(A) through (D) of this section.
(A) Published reports (e.g., scientific papers) produced by either
the submitting entity or an outside entity evaluating the submitted
measurement technology that has been independently evaluated. The
published reports must identify either a site-level or aggregate
detection threshold and be accompanied with sufficient supporting data
to evaluate whether the performance metrics of the alternative testing
procedures in paragraph (d)(3)(vi)(C) of this section are adequate and
the data was collected consistent with those alternative testing
procedures. The supporting data may be included in the published report
or may be submitted separately.
(B) Standard operating procedures including safety considerations,
measurement limitations, personnel qualification/responsibilities,
equipment and supplies, data and record management, and quality
assurance/quality control (i.e., initial and ongoing calibration
procedures, data quality indicators, and data quality objectives).
(C) Detailed description of the alternative testing procedure(s),
preferably in the format described in Guideline Document 45 on the
Emission Measurement Center's website (available at https://www.epa.gov/sites/default/files/2020-08/documents/gd-045.pdf). The
detailed description must address all key elements of the requested
method(s) and must include objectives to ensure the detection
threshold(s) required in paragraph (d)(3)(vi) of this section are
maintained, including procedures for verifying the detection threshold
and/or or probability of detection is maintained under field
conditions.
(D) Any documents provided to end-users of the data generated by
the measurement system, including but not limited to client products,
manuals, and frequently asked questions documents.
(vii) If the technology will be used to monitor the collection of
fugitive emissions components, covers, and closed vent systems at a
well site, centralized production facility, or compressor station, you
must submit supporting information verifying the spatial resolution of
technology, as defined in paragraphs (d)(3)(vii)(A) through (C) of this
section. This supporting information must be in the form of a published
reports (e.g., scientific papers) produced by either the submitting
entity or an outside entity evaluating the submitted measurement
technology that has been independently evaluated. The report must
include sufficient supporting data to evaluate whether the performance
metrics of the alternative testing procedures in paragraph
(d)(3)(vi)(C) of this section are adequate and the data was collected
consistent with those alternative testing procedures.
[[Page 17072]]
(A) Facility-level spatial resolution means a technology with the
ability to identify emissions within the boundary of a well site,
centralized production facility, or compressor station.
(B) Area-level spatial resolution means a technology with the
ability to identify emissions within a radius of 2 meters of the
emission source.
(C) Component-level spatial resolution means a technology with the
ability to identify emissions within a radius of 0.5 meter of the
emission source.
Sec. 60.5399b What are the alternative means of emission limitations
for GHG and VOC emissions from well completions, liquids unloading
operations, centrifugal compressors, reciprocating compressors,
fugitive emissions components, and process unit equipment affected
facilities; and what are the alternative fugitive emissions standards
based on State, local, and Tribal programs?
This section provides procedures for the submittal and approval of
alternative means of emission limitation for GHG and VOC based on work
practices for well completions, liquids unloading operations,
centrifugal compressors, reciprocating compressors, fugitive emissions
components and process unit equipment affected facilities. This section
also provides procedures for the submittal and approval of alternative
fugitive emissions standards based on programs under state, local, or
Tribal authorities for the fugitive emissions components affected
facility. Paragraphs (a) through (d) of this section outline the
procedure for submittal and approval of alternative means of emission
limitation for methane and VOC. Paragraphs (e) through (i) of this
section outline the procedure for submittal and approval of alternative
fugitive emissions standards. The requirements for a monitoring plan
specified in Sec. 60.5397b(c) and (d) apply to the alternative
fugitive emissions standards in this section.
(a) Alternative means of emission limitation. If, in the
Administrator's judgment, an alternative means of emission limitation
will achieve a reduction in methane and VOC emissions at least
equivalent to the reduction in methane and VOC emissions achieved under
Sec. 60.5375b, Sec. 60.5376b, Sec. 60.5380b, Sec. 60.5385b, Sec.
60.5397b, Sec. 60.5400b, or Sec. 60.5401b, the Administrator will
publish, in the Federal Register, a notice permitting the use of that
alternative means for the purpose of compliance with Sec. 60.5375b,
Sec. 60.5376b, Sec. 60.5380b, Sec. 60.5385b, Sec. 60.5397b, Sec.
60.5400b, or Sec. 60.5401b. The authority to approve an alternative
means of emission limitation is retained by the Administrator and shall
not be delegated to States under section 111(c) of the CAA.
(b) Notice. Any notice under paragraph (a) of this section must be
published only after notice and an opportunity for a public hearing.
(c) Evaluation guidelines. Determination of equivalence to the
design, equipment, work practice, or operational requirements of this
section will be evaluated by the following guidelines:
(1) The applicant must provide information that is sufficient for
demonstrating the alternative means of emission limitation achieves
emission reductions that are at least equivalent to the emission
reductions that would be achieved by complying with the relevant
standards. At a minimum, the application must include the following
information:
(i) Details of the specific equipment or components that would be
included in the alternative.
(ii) A description of the alternative work practice, including, as
appropriate, the monitoring method, monitoring instrument or
measurement technology, and the data quality indicators for precision
and bias.
(iii) The method detection limit of the technology, technique, or
process and a description of the procedures used to determine the
method detection limit. At a minimum, the applicant must collect,
verify, and submit field data encompassing seasonal variations to
support the determination of the method detection limit. The field data
may be supplemented with modeling analyses, controlled test site data,
or other documentation.
(iv) Any initial and ongoing quality assurance/quality control
measures necessary for maintaining the technology, technique, or
process, and the timeframes for conducting such measures.
(v) Frequency of measurements. For continuous monitoring
techniques, the minimum data availability.
(vi) Any restrictions for using the technology, technique, or
process.
(vii) Initial and continuous compliance procedures, including
recordkeeping and reporting, if the compliance procedures are different
than those specified in this subpart.
(2) For each technology, technique, or process for which a
determination of equivalency is requested, the application must provide
a demonstration that the emission reduction achieved by the alternative
means of emission limitation is at least equivalent to the emission
reduction that would be achieved by complying with the relevant
standards in this subpart.
(d) Approval of alternative means of emission limitation. Any
alternative means of emission limitations approved under this section
shall constitute a required work practice, equipment, design, or
operational standard within the meaning of section 111(h)(1) of the
CAA.
(e) Alternative fugitive emissions standards. If, in the
Administrator's judgment, an alternative fugitive emissions standard
will achieve a reduction in methane and VOC emissions at least
equivalent to the reductions achieved under Sec. 60.5397b, the
Administrator will publish, in the Federal Register, a notice
permitting use of the alternative fugitive emissions standard for the
purpose of compliance with Sec. 60.5397b. The authority to approve
alternative fugitive emissions standards is retained by the
Administrator and shall not be delegated to States under section 111(c)
of the CAA.
(f) Notice. Any notice under paragraph (e) of this section will be
published only after notice and an opportunity for public hearing.
(g) Evaluation guidelines. Determination of alternative fugitive
emissions standards to the design, equipment, work practice, or
operational requirements of Sec. 60.5397b will be evaluated by the
following guidelines:
(1) The monitoring instrument, including the monitoring procedure;
(2) The monitoring frequency;
(3) The fugitive emissions definition;
(4) The repair requirements; and
(5) The recordkeeping and reporting requirements.
(h) Approval of alternative fugitive emissions standard. Any
alternative fugitive emissions standard approved under this section
shall:
(1) Constitute a required design, equipment, work practice, or
operational standard within the meaning of section 111(h)(1) of the
CAA; and
(2) Be made available for use by any owner or operator in meeting
the relevant standards and requirements established for affected
facilities under Sec. 60.5397b.
(i) Notification. (1) An owner or operator must notify the
Administrator of adoption of the alternative fugitive emissions
standards within the first annual report following implementation of
the alternative fugitive emissions standard, as specified in Sec.
60.5420b(a)(3).
(2) An owner or operator implementing one of the alternative
[[Page 17073]]
fugitive emissions standards must submit the reports specified in Sec.
60.5420b(b)(9)(iii). An owner or operator must also maintain the
records specified by the specific alternative fugitive emissions
standard for a period of at least 5 years.
Sec. 60.5400b What GHG and VOC standards apply to process unit
equipment affected facilities?
This section applies to process unit equipment affected facilities
located at an onshore natural gas processing plant. You must comply
with the requirements of paragraphs (a) through (l) of this section to
reduce methane and VOC emissions from equipment leaks, except as
provided in Sec. 60.5402b. As an alternative to the standards in this
section, you may comply with the requirements in Sec. 60.5401b.
(a) General standards. You must comply with the requirements in
paragraphs (b) through (d) of this section for each pump in light
liquid service, pressure relief device in gas/vapor service, valve in
gas/vapor or light liquid service, and connector in gas/vapor or light
liquid service, as applicable. You must comply with the requirements in
paragraph (e) of this section for each open-ended valve or line. You
must comply with the requirements in paragraph (f) of this section for
each closed vent system and control device used to comply with
equipment leak provisions in this section. You must comply with
paragraph (g) of this section for each pump, valve, and connector in
heavy liquid service and pressure relief device in light liquid or
heavy liquid service. You must make repairs as specified in paragraph
(h) of this section. You must demonstrate initial compliance with the
standards as specified in paragraph (i) of this section. You must
demonstrate continuous compliance with the standards as specified in
paragraph (j) of this section. You must perform the reporting as
specified in paragraph (k) of this section. You must perform the
recordkeeping as required in paragraph (l) of this section.
(1) You may apply to the Administrator for permission to use an
alternative means of emission limitation that achieves a reduction in
emissions of methane and VOC at least equivalent to that achieved by
the controls required in this subpart according to the requirements of
Sec. 60.5399b.
(2) Each piece of equipment is presumed to have the potential to
emit methane or VOC unless an owner or operator demonstrates that the
piece of equipment does not have the potential to emit methane or VOC.
For a piece of equipment to be considered not to have the potential to
emit methane or VOC, the methane and VOC content of a gaseous stream
must be below detection limits using Method 18 of appendix A-6 to this
part. Alternatively, if the piece of equipment is in wet gas service,
you may choose to determine the methane and VOC content of the stream
is below the detection limit of the methods described in ASTM E168-
16(R2023), E169-16(R2022), or E260-96 (all incorporated by reference,
see Sec. 60.17).
(b) Monitoring surveys. You must monitor for leaks using OGI in
accordance with appendix K of this part, unless otherwise specified in
paragraphs (c) or (d) of this section.
(1) Monitoring surveys must be conducted bimonthly.
(2) Any emissions observed using OGI are defined as a leak.
(c) Additional requirements for pumps in light liquid service. In
addition to the requirements in paragraph (b), you must conduct weekly
visual inspections of all pumps in light liquid service for indications
of liquids dripping from the pump seal, except as specified in
paragraphs (c)(3) and (4) of this section. If there are indications of
liquids dripping from the pump seal, you must follow the procedure
specified in either paragraph (c)(1) or (2) of this section.
(1) Monitor the pump within 5 calendar days using the methods
specified in Sec. 60.5403b. A leak is detected if any emissions are
observed using OGI or if an instrument reading of 2,000 ppmv or greater
is provided using Method 21 of appendix A-7 to this part.
(2) Designate the visual indications of liquids dripping as a leak
and repair the leak as specified in paragraph (h) of this section.
(3) If any pump is equipped with a closed vent system capable of
capturing and transporting any leakage from the seal or seals to a
process, fuel gas system, or a control device that complies with the
requirements of paragraph (f) of this section, it is exempt from the
weekly inspection requirements in paragraph (c) of this section.
(4) Any pump that is located within the boundary of an unmanned
plant site is exempt from the weekly visual inspection requirements in
paragraph (c) of this section, provided that each pump is visually
inspected as often as practicable and at least bimonthly.
(d) Additional requirements for pressure relief devices in gas/
vapor service. In addition to the requirements in paragraph (b) of this
section, you must monitor each pressure relief device as specified in
paragraph (d)(1) of this section, except as specified in paragraphs
(d)(2) and (3) of this section.
(1) You must monitor each pressure relief device within 5 calendar
days after each pressure release to detect leaks using the methods
specified in Sec. 60.5403b. A leak is detected if any emissions are
observed using OGI or if an instrument reading of 500 ppmv or greater
is provided using Method 21 of appendix A-7 to this part.
(2) Any pressure relief device that is located in a
nonfractionating plant that is monitored only by non-plant personnel
may be monitored after a pressure release the next time the monitoring
personnel are onsite or within 30 calendar days after a pressure
release, whichever is sooner, instead of within 5 calendar days as
specified in paragraph (d)(1) of this section. No pressure relief
device described in this paragraph may be allowed to operate for more
than 30 calendar days after a pressure release without monitoring.
(3) Any pressure relief device that is routed to a process or fuel
gas system or equipped with a closed vent system capable of capturing
and transporting leakage through the pressure relief device to a
control device as described in paragraph (f) of this section is exempt
from the requirements of paragraph (d)(1) of this section.
(e) Open-ended valves or lines. Each open-ended valve or line must
be equipped with a cap, blind flange, plug, or a second valve, except
as provided in paragraphs (e)(4) and (5) of this section. The cap,
blind flange, plug, or second valve must seal the open end of the valve
or line at all times except during operations requiring process fluid
flow through the open-ended valve or line.
(1) If evidence of a leak is found at any time by AVO, or any other
detection method, a leak is detected.
(2) Each open-ended valve or line equipped with a second valve must
be operated in a manner such that the valve on the process fluid end is
closed before the second valve is closed.
(3) When a double block-and-bleed system is being used, the bleed
valve or line may remain open during operations that require venting
the line between the block valves but shall remain closed at all other
times.
(4) Open-ended valves or lines in an emergency shutdown system
which are designed to open automatically in the event of a process
upset are exempt from the requirements of this section.
(5) Open-ended valves or lines containing materials which would
autocatalytically polymerize or would present an explosion, serious
overpressure, or other safety hazard if capped or equipped with a
double
[[Page 17074]]
block-and-bleed system as specified in paragraphs (e) introductory
text, (e)(2), and (3) of this section are exempt from the requirements
of this section.
(f) Closed vent systems and control devices. Closed vent systems
used to comply with the equipment leak provisions of this section must
comply with the requirements in Sec. Sec. 60.5411b and 60.5416b.
Control devices used to comply with the equipment leak provisions of
this section must comply with the requirements in Sec. Sec. 60.5412b,
60.5415b(f), and 60.5417b.
(g) Pumps, valves, and connectors in heavy liquid service and
pressure relief devices in light liquid or heavy liquid service. If
evidence of a potential leak is found at any time by AVO, or any other
detection method, a leak is detected and must be repaired in accordance
with paragraph (h) of this section.
(h) Repair requirements. When a leak is detected, you must comply
with the requirements of paragraphs (h)(1) through (5) of this section,
except as provided in paragraph (h)(6) of this section.
(1) A weatherproof and readily visible identification tag, marked
with the equipment identification number, must be attached to the
leaking equipment. The identification tag on equipment may be removed
after it has been repaired.
(2) A first attempt at repair must be made as soon as practicable,
but no later than 5 calendar days after the leak is detected. A first
attempt at repair is not required if the leak is detected using OGI and
the equipment identified as leaking would require elevating the repair
personnel more than 2 meters above a support surface.
(i) First attempts at repair for pumps in light liquid or heavy
liquid service include, but are not limited to, the practices described
in paragraphs (h)(2)(i)(A) and (B) of this section, where practicable.
(A) Tightening the packing gland nuts.
(B) Ensuring that the seal flush is operating at design pressure
and temperature.
(ii) For each valve where a leak is detected, you must comply with
(h)(2)(ii)(A), (B) or (C), and (D) of this section.
(A) Repack the existing valve with a low-e packing.
(B) Replace the existing valve with a low-e valve; or
(C) Perform a drill and tap repair with a low-e injectable packing.
(D) An owner or operator is not required to utilize a low-e valve
or low-e packing to replace or repack a valve if the owner or operator
demonstrates that a low-e valve or low-e packing is not technically
feasible. Low-e valve or low-e packing that is not suitable for its
intended use is considered to be technically infeasible. Factors that
may be considered in determining technical infeasibility include:
retrofit requirements for installation (e.g., re-piping or space
limitation), commercial unavailability for valve type, or certain
instrumentation assemblies.
(3) Repair of leaking equipment must be completed within 15
calendar days after detection of each leak, except as provided in
paragraphs (h)(4), (5) and (6) of this section.
(4) If the repair for visual indications of liquids dripping for
pumps in light liquid service can be made by eliminating visual
indications of liquids dripping, you must make the repair within 5
calendar days of detection.
(5) If the repair for AVO or other indication of a leak for open-
ended valves or lines; pumps, valves, or connectors in heavy liquid
service; or pressure relief devices in light liquid or heavy liquid
service can be made by eliminating the AVO, or other indication of a
potential leak, you must make the repair within 5 calendar days of
detection.
(6) Delay of repair of equipment for which leaks have been detected
is allowed if repair within 15 days is technically infeasible without a
process unit shutdown or as specified in paragraphs (h)(6)(i) through
(v) of this section. Repair of this equipment shall occur before the
end of the next process unit shutdown. Monitoring to verify repair must
occur within 15 days after startup of the process unit.
(i) Delay of repair of equipment is allowed for equipment which is
isolated from the process, and which does not have the potential to
emit methane or VOC.
(ii) Delay of repair for valves and connectors is allowed if the
conditions in paragraphs (h)(6)(ii)(A) and (B) of this section are met.
(A) You must demonstrate that emissions of purged material
resulting from immediate repair are greater than the fugitive emissions
likely to result from delay of repair, and
(B) When repair procedures are conducted, the purged material is
collected and destroyed or recovered in a control device complying with
paragraph (f) of this section.
(iii) Delay of repair for pumps is allowed if the conditions in
paragraphs (h)(6)(iii)(A) and (B) of this section are met.
(A) Repair requires the use of a dual mechanical seal system that
includes a barrier fluid system, and
(B) Repair is completed as soon as practicable, but not later than
6 months after the leak was detected.
(iv) If delay of repair is required to repack or replace the valve,
you may use delay of repair. Delay of repair beyond a process unit
shutdown is allowed for a valve, if valve assembly replacement is
necessary during the process unit shutdown, valve assembly supplies
have been depleted, and valve assembly supplies had been sufficiently
stocked before the supplies were depleted. Delay of repair beyond the
next process unit shutdown will not be allowed unless the next process
unit shutdown occurs sooner than 6 months after the first process unit
shutdown.
(v) When delay of repair is allowed for a leaking pump, valve, or
connector that remains in service, the pump, valve, or connector may be
considered to be repaired and no longer subject to delay of repair
requirements if two consecutive bimonthly monitoring results show no
leak remains.
(i) Initial compliance. You must demonstrate initial compliance
with the standards that apply to equipment leaks at onshore natural gas
processing plants as required by Sec. 60.5410b(h).
(j) Continuous compliance. You must demonstrate continuous
compliance with the standards that apply to equipment leaks at onshore
natural gas processing plants as required by Sec. 60.5415b(j).
(k) Reporting. You must perform the reporting requirements as
specified in Sec. 60.5420b(b)(1) and (11) and Sec. 60.5422b.
(l) Recordkeeping. You must perform the recordkeeping requirements
as specified in Sec. 60.5420b(c)(8), (10), and (12) and Sec.
60.5421b.
Sec. 60.5401b What are the alternative GHG and VOC standards for
process unit equipment affected facilities?
This section provides alternative standards for process unit
equipment affected facilities located at an onshore natural gas
processing plant. You may choose to comply with the standards in this
section instead of the requirements in Sec. 60.5400b. For purposes of
the alternative standards provided in this section, you must comply
with the requirements of paragraphs (a) through (m) of this section to
reduce methane and VOC emissions from equipment leaks, except as
provided in Sec. 60.5402b.
(a) General standards. You must comply with the requirements in
paragraphs (b) of this section for each pump in light liquid service.
You must comply with the requirements of paragraph (c) of this section
for each pressure relief device in gas/vapor
[[Page 17075]]
service. You must comply with the requirements in paragraph (d) of this
section for each open-ended valve or line. You must comply with the
requirements in paragraph (e) of this section for each closed vent
system and control device used to comply with equipment leak provisions
in this section. You must comply with paragraph (f) of this section for
each valve in gas/vapor or light liquid service. You must comply with
paragraph (g) of this section for each pump, valve, and connector in
heavy liquid service and pressure relief device in light liquid or
heavy liquid service. You must comply with paragraph (h) of this
section for each connector in gas/vapor and light liquid service. You
must make repairs as specified in paragraph (i) of this section. You
must demonstrate initial compliance with the standards as specified in
paragraph (j) of this section. You must demonstrate continuous
compliance with the standards as specified in paragraph (k) of this
section. You must perform the reporting requirements as specified in
paragraph (l) of this section. You must perform the recordkeeping
requirements as required in paragraph (m) of this section.
(1) You may apply to the Administrator for permission to use an
alternative means of emission limitation that achieves a reduction in
emissions of methane and VOC at least equivalent to that achieved by
the controls required in this subpart according to the requirements of
Sec. 60.5399b.
(2) Each piece of equipment is presumed to have the potential to
emit methane or VOC unless an owner or operator demonstrates that the
piece of equipment does not have the potential to emit methane or VOC.
For a piece of equipment to be considered not to have the potential to
emit methane or VOC, the methane and VOC content of a gaseous stream
must be below detection limits using Method 18 of appendix A-6 to this
part. Alternatively, if the piece of equipment is in wet gas service,
you may choose to determine the methane and VOC content of the stream
is below the detection limit of the methods described in ASTM E168-
16(R2023), E169-16(R2022), or E260-96 (all incorporated by reference,
see Sec. 60.17).
(b) Pumps in light liquid service. You must monitor each pump in
light liquid service monthly to detect leaks by the methods specified
in Sec. 60.5403b, except as provided in paragraphs (b)(2) through (4)
of this section. A leak is defined as an instrument reading of 2,000
ppmv or greater. A pump that begins operation in light liquid service
after the initial startup date for the process unit must be monitored
for the first time within 30 days after the end of its startup period,
except for a pump that replaces a leaking pump and except as provided
in paragraphs (b)(2) through (4) of this section.
(1) In addition to the requirements in paragraph (b) of this
section, you must conduct weekly visual inspections of all pumps in
light liquid service for indications of liquids dripping from the pump
seal. If there are indications of liquids dripping from the pump seal,
you must follow the procedure specified in either paragraph (b)(1)(i)
or (ii) of this section.
(i) Monitor the pump within 5 days using the methods specified in
Sec. 60.5403b. A leak is defined as an instrument reading of 2,000
ppmv or greater.
(ii) Designate the visual indications of liquids dripping as a
leak, and repair the leak as specified in paragraph (i) of this
section.
(2) Each pump equipped with a dual mechanical seal system that
includes a barrier fluid system is exempt from the requirements in
paragraph (b) of this section, provided the requirements specified in
paragraphs (b)(2)(i) through (vi) of this section are met.
(i) Each dual mechanical seal system meets the requirements of
paragraphs (b)(2)(i)(A), (B), or (C) of this section.
(A) Operated with the barrier fluid at a pressure that is at all
times greater than the pump stuffing box pressure; or
(B) Equipped with a barrier fluid degassing reservoir that is
routed to a process or fuel gas system or connected by a closed vent
system to a control device that complies with the requirements of
paragraph (e) of this section; or
(C) Equipped with a system that purges the barrier fluid into a
process stream with zero VOC emissions to the atmosphere.
(ii) The barrier fluid system is in heavy liquid service or does
not have the potential to emit methane or VOC.
(iii) Each barrier fluid system is equipped with a sensor that will
detect failure of the seal system, the barrier fluid system, or both.
(iv) Each pump is checked according to the requirements in
paragraph (b)(1) of this section.
(v) Each sensor meets the requirements in paragraphs (b)(2)(v)(A)
through (C) of this section.
(A) Each sensor as described in paragraph (b)(2)(iii) of this
section is checked daily or is equipped with an audible alarm.
(B) You determine, based on design considerations and operating
experience, a criterion that indicates failure of the seal system, the
barrier fluid system, or both.
(C) If the sensor indicates failure of the seal system, the barrier
fluid system, or both, based on the criterion established in paragraph
(b)(2)(v)(B) of this section, a leak is detected.
(3) Any pump that is designated, as described in Sec.
60.5421b(b)(12), for no detectable emissions, as indicated by an
instrument reading of less than 500 ppmv above background, is exempt
from the requirements of paragraphs (b) introductory text, (b)(1), and
(2) of this section if the pump:
(i) Has no externally actuated shaft penetrating the pump housing;
(ii) Is demonstrated to be operating with no detectable emissions
as indicated by an instrument reading of less than 500 ppmv above
background as measured by the methods specified in Sec. 60.5403b; and
(iii) Is tested for compliance with paragraph (b)(3)(ii) of this
section initially upon designation, annually, and at other times
requested by the Administrator.
(4) If any pump is equipped with a closed vent system capable of
capturing and transporting any leakage from the seal or seals to a
process, fuel gas system, or a control device that complies with the
requirements of paragraph (e) of this section, it is exempt from
paragraphs (b), (b)(1) through (3) of this section, and the repair
requirements of paragraph (i) of this section.
(5) Any pump that is designated, as described in Sec.
60.5421b(b)(13), as an unsafe-to-monitor pump is exempt from the
inspection and monitoring requirements of paragraphs (b), (b)(1) and
(b)(2)(iv) through (vi) of this section if the conditions in paragraph
(b)(5)(i) and (ii) of this section are met.
(i) You demonstrate that the pump is unsafe-to-monitor because
monitoring personnel would be exposed to an immediate danger as a
consequence of complying with paragraph (b) of this section; and
(ii) You have a written plan that requires monitoring of the pump
as frequently as practicable during safe-to-monitor times, but not more
frequently than the periodic monitoring schedule otherwise applicable,
and you repair the equipment according to the procedures in paragraph
(i) of this section if a leak is detected.
(6) Any pump that is located within the boundary of an unmanned
plant site is exempt from the weekly visual inspection requirements in
paragraph (b)(1) and (b)(2)(iv) of this section, and the daily
requirements of paragraph (b)(2)(v) of this section, provided that
[[Page 17076]]
each pump is visually inspected as often as practicable and at least
monthly.
(c) Pressure relief devices in gas/vapor service. You must monitor
each pressure relief device quarterly using the methods specified in
Sec. 60.5403b. A leak is defined as an instrument reading of 500 ppmv
or greater above background.
(1) In addition to the requirements in paragraph (c) introductory
text of this section, after each pressure release, you must monitor
each pressure relief device within 5 calendar days after each pressure
release to detect leaks. A leak is detected if an instrument reading of
500 ppmv or greater is provided using the methods specified in Sec.
60.5403b(b).
(2) Any pressure relief device that is located in a
nonfractionating plant that is monitored only by non-plant personnel
may be monitored after a pressure release the next time the monitoring
personnel are onsite or within 30 calendar days after a pressure
release, whichever is sooner, instead of within 5 calendar days as
specified in paragraph (c)(1) of this section.
(3) No pressure relief device described in paragraph (c)(2) of this
section may be allowed to operate for more than 30 calendar days after
a pressure release without monitoring.
(4) Any pressure relief device that is routed to a process or fuel
gas system or equipped with a closed vent system capable of capturing
and transporting leakage through the pressure relief device to a
control device as described in paragraph (e) of this section is exempt
from the requirements of paragraph (c) introductory text and (c)(1) of
this section.
(5) Pressure relief devices equipped with a rupture disk are exempt
from the requirements of paragraphs (c)(1) and (2) of this section
provided you install a new rupture disk upstream of the pressure relief
device as soon as practicable, but no later than 5 calendar days after
each pressure release, except as provided in paragraph (i)(4) of this
section.
(d) Open-ended valves or lines. Each open-ended valve or line must
be equipped with a cap, blind flange, plug, or a second valve, except
as provided in paragraphs (d)(4) and (5) of this section. The cap,
blind flange, plug, or second valve must seal the open end of the valve
or line at all times except during operations requiring process fluid
flow through the open-ended valve or line.
(1) If evidence of a leak is found at any time by AVO, or any other
detection method, a leak is detected and must be repaired in accordance
with paragraph (i) of this section. A leak is defined as an instrument
reading of 500 ppmv or greater if Method 21 of appendix A-7 to this
part is used.
(2) Each open-ended valve or line equipped with a second valve must
be operated in a manner such that the valve on the process fluid end is
closed before the second valve is closed.
(3) When a double block-and-bleed system is being used, the bleed
valve or line may remain open during operations that require venting
the line between the block valves but shall remain closed at all other
times.
(4) Open-ended valves or lines in an emergency shutdown system
which are designed to open automatically in the event of a process
upset are exempt from the requirements of paragraphs (d) introductory
text, and (d)(1) through (3) of this section.
(5) Open-ended valves or lines containing materials which would
autocatalytically polymerize or would present an explosion, serious
overpressure, or other safety hazard if capped or equipped with a
double block-and-bleed system as specified in paragraphs (d)
introductory text, (d)(2), and (3) of this section are exempt from the
requirements of this section.
(e) Closed vent systems and control devices. Closed vent systems
used to comply with the equipment leak provisions of this section must
comply with the requirements in Sec. Sec. 60.5411b and 60.5416b.
Control devices used to comply with the equipment leak provisions of
this section must comply with the requirements in Sec. Sec. 60.5412b,
60.5415b(f), and 60.5417b.
(f) Valves in gas/vapor and light liquid service. You must monitor
each valve in gas/vapor and in light liquid service quarterly to detect
leaks by the methods specified in Sec. 60.5403b, except as provided in
paragraphs (h)(3) through (5) of this section.
(1) A valve that begins operation in gas/vapor service or in light
liquid service after the initial startup date for the process unit must
be monitored for the first time within 90 days after the end of its
startup period to ensure proper installation, except for a valve that
replaces a leaking valve and except as provided in paragraphs (h)(3)
through (5) of this section.
(2) An instrument reading of 500 ppmv or greater is a leak. You
must repair each leaking valve according to the requirements in
paragraph (i) of this section.
(3) Any valve that is designated, as described in Sec.
60.5421b(b)(12), for no detectable emissions, as indicated by an
instrument reading of less than 500 ppmv above background, is exempt
from the requirements of paragraphs (f) of this section if the valve:
(i) Has no externally actuating mechanism in contact with the
process fluid;
(ii) Is operated with emissions less than 500 ppmv above background
as determined by the methods specified in Sec. 60.5403b; and
(iii) Is tested for compliance with paragraph (f)(3)(ii) of this
section initially upon designation, annually, and at other times
requested by the Administrator.
(4) Any valve that is designated, as described in Sec.
60.5421b(b)(13), as an unsafe-to-monitor pump is exempt from the
monitoring requirements of paragraph (f) introductory text of this
section if the requirements in paragraphs (f)(4)(i) and (ii) of this
section are met.
(i) You demonstrate that the valve is unsafe-to-monitor because
monitoring personnel would be exposed to an immediate danger as a
consequence of complying with paragraph (f) of this section; and
(ii) You have a written plan that requires monitoring of the valve
as frequently as practicable during safe-to-monitor times, but not more
frequently than the periodic monitoring schedule otherwise applicable,
and you repair the equipment according to the procedures in paragraph
(i) of this section if a leak is detected.
(5) Any valve that is designated, as described in Sec.
60.5421b(b)(14), as a difficult-to-monitor valve is exempt from the
monitoring requirements of paragraph (h) of this section if the
requirements in paragraph (f)(5)(i) through (iii) of this section are
met.
(i) You demonstrate that the valve cannot be monitored without
elevating the monitoring personnel more than 2 meters above a support
surface.
(ii) The process unit within which the valve is located has less
than 3.0 percent of its total number of valves designated as difficult-
to-monitor.
(iii) You have a written plan that requires monitoring of the at
least once per calendar year.
(g) Pumps, valves, and connectors in heavy liquid service and
pressure relief devices in light liquid or heavy liquid service. If
evidence of a potential leak is found at any time by AVO, or any other
detection method, you must comply with either paragraph (g)(1) or (2)
of this section.
(1) You must monitor the equipment within 5 calendar days by the
method specified in Sec. 60.5403b and repair any leaks detected
according to paragraph (i) of this section. An instrument reading of
10,000 ppmv or greater is defined as a leak.
[[Page 17077]]
(2) You must designate the AVO, or other indication of a leak as a
leak and repair the leak according to paragraph (i) of this section.
(h) Connectors in gas/vapor service and in light liquid service.
You must initially monitor all connectors in the process unit for leaks
by the later of either 12 months after the compliance date or 12 months
after initial startup. If all connectors in the process unit have been
monitored for leaks prior to the compliance date, no initial monitoring
is required provided either no process changes have been made since the
monitoring or the owner or operator can determine that the results of
the monitoring, with or without adjustments, reliably demonstrate
compliance despite process changes. If required to monitor because of a
process change, you are required to monitor only those connectors
involved in the process change.
(1) You must monitor all connectors in gas/vapor service and in
light liquid service annually, except as provided in Sec. 60.5399b,
paragraph (e) of this section or paragraph (h)(2) of this section.
(2) Any connector that is designated, as described in Sec.
60.5421b(b)(13), as an unsafe-to-monitor connector is exempt from the
requirements of paragraphs (h) introductory text and (h)(1) of this
section if the requirements of paragraphs (h)(2)(i) and (ii) of this
section are met.
(i) You demonstrate the connector is unsafe-to-monitor because
monitoring personnel would be exposed to an immediate danger as a
consequence of complying with paragraphs (h) introductory text and
(h)(1) of this section; and
(ii) You have a written plan that requires monitoring of the
connector as frequently as practicable during safe-to-monitor times,
but not more frequently than the periodic monitoring schedule otherwise
applicable, and you repair the equipment according to the procedures in
paragraph (i) of this section if a leak is detected.
(3) Inaccessible, ceramic, or ceramic-line connectors.
(i) Any connector that is inaccessible or that is ceramic or
ceramic-lined (e.g., porcelain, glass, or glass-lined), is exempt from
the monitoring requirements of paragraphs (h) and (h)(1) of this
section, from the leak repair requirements of paragraph (i) of this
section, and from the recordkeeping and reporting requirements of
Sec. Sec. 60.5421b and 60.5422b. An inaccessible connector is one that
meets any of the specifications in paragraphs (h)(3)(i)(A) through (F)
of this section, as applicable.
(A) Buried.
(B) Insulated in a manner that prevents access to the connector by
a monitor probe.
(C) Obstructed by equipment or piping that prevents access to the
connector by a monitor probe.
(D) Unable to be reached from a wheeled scissor-lift or hydraulic-
type scaffold that would allow access to connectors up to 7.6 meters
(25 feet) above the ground.
(E) Inaccessible because it would require elevating monitoring
personnel more than 2 meters (7 feet) above a permanent support surface
or would require the erection of scaffold.
(F) Not able to be accessed at any time in a safe manner to perform
monitoring. Unsafe access includes, but is not limited to, the use of a
wheeled scissor-lift on unstable or uneven terrain, the use of a
motorized man-lift basket in areas where an ignition potential exists,
or access would require near proximity to hazards such as electrical
lines or would risk damage to equipment.
(ii) If any inaccessible, ceramic, or ceramic-lined connector is
observed by AVO or other means to be leaking, the indications of a leak
to the atmosphere by AVO or other means must be eliminated as soon as
practicable.
(4) Connectors which are part of an instrumentation systems and
inaccessible, ceramic, or ceramic-lined connectors meeting the
provisions of paragraph (h)(3) of this section, are not subject to the
recordkeeping requirements of Sec. 60.5421b(b)(1).
(i) Repair requirements. When a leak is detected, comply with the
requirements of paragraphs (i)(1) through (5) of this section, except
as provided in paragraph (i)(6) of this section.
(1) A weatherproof and readily visible identification tag, marked
with the equipment identification number, must be attached to the
leaking equipment. The identification tag on the equipment may be
removed after it has been repaired.
(2) A first attempt at repair must be made as soon as practicable,
but no later than 5 calendar days after the leak is detected.
(i) First attempts at repair for pumps in light liquid or heavy
liquid service include, but are not limited to, the practices described
in paragraphs (i)(2)(i)(A) and (B) of this section, where practicable.
(A) Tightening the packing gland nuts.
(B) Ensuring that the seal flush is operating at design pressure
and temperature.
(ii) For each valve where a leak is detected, you must comply with
(h)(2)(ii)(A), (B) or (C), and (D) of this section.
(A) Repack the existing valve with a low-e packing.
(B) Replace the existing valve with a low-e valve; or
(C) Perform a drill and tap repair with a low-e injectable packing.
(D) An owner or operator is not required to utilize a low-e valve
or low-e packing to replace or repack a valve if the owner or operator
demonstrates that a low-e valve or low-e packing is not technically
feasible. Low-e valve or low-e packing that is not suitable for its
intended use is considered to be technically infeasible. Factors that
may be considered in determining technical infeasibility include:
retrofit requirements for installation (e.g., re-piping or space
limitation), commercial unavailability for valve type, or certain
instrumentation assemblies.
(3) Repair of leaking equipment must be completed within 15
calendar days after detection of each leak, except as provided in
paragraph (i)(4), (5), or (6) of this section.
(4) If the repair for visual indications of liquids dripping for
pumps in light liquid service can be made by eliminating visual
indications of liquids dripping, you must make the repair within 5
calendar days of detection.
(5) If the repair for AVO or other indication of a leak for open-
ended lines or valves; pumps, valves, or connectors in heavy liquid
service; or pressure relief devices in light liquid or heavy liquid
service can be made by eliminating the AVO, or other indication of a
potential leak, you must make the repair within 5 calendar days of
detection.
(6) Delay of repair of equipment for which leaks have been detected
will be allowed if repair within 15 calendar days is technically
infeasible without a process unit shutdown or as specified in
paragraphs (i)(6)(i) through (v) of this section. Repair of this
equipment shall occur before the end of the next process unit shutdown.
Monitoring to verify repair must occur within 15 calendar days after
startup of the process unit.
(i) Delay of repair of equipment will be allowed for equipment
which is isolated from the process, and which does not have the
potential to emit methane or VOC.
(ii) Delay of repair for valves and connectors will be allowed if
the conditions in paragraphs (i)(6)(ii)(A) and (B) are met.
(A) You demonstrate that emissions of purged material resulting
from immediate repair are greater than the
[[Page 17078]]
fugitive emissions likely to result from delay of repair, and
(B) When repair procedures are conducted, the purged material is
collected and destroyed or recovered in a control device complying with
paragraph (e) of this section.
(iii) Delay of repair for pumps will be allowed if the conditions
in paragraphs (i)(6)(iii)(A) and (B) are met.
(A) Repair requires the use of a dual mechanical seal system that
includes a barrier fluid system, and
(B) Repair is completed as soon as practicable, but not later than
6 months after the leak was detected.
(iv) If delay of repair is required to repack or replace the valve,
you may use delay of repair. Delay of repair beyond a process unit
shutdown will be allowed for a valve, if valve assembly replacement is
necessary during the process unit shutdown, valve assembly supplies
have been depleted, and valve assembly supplies had been sufficiently
stocked before the supplies were depleted. Delay of repair beyond the
next process unit shutdown will not be allowed unless the next process
unit shutdown occurs sooner than 6 months after the first process unit
shutdown.
(v) When delay of repair is allowed for a leaking pump, valve, or
connector that remains in service, the pump, valve, or connector may be
considered to be repaired and no longer subject to delay of repair
requirements if two consecutive monthly monitoring results show no leak
remains.
(j) Initial compliance. You must demonstrate initial compliance
with the standards that apply to equipment leaks at onshore natural gas
processing plants as required by Sec. 60.5410b(h).
(k) Continuous compliance. You must demonstrate continuous
compliance with the standards that apply to equipment leaks at onshore
natural gas processing plants as required by Sec. 60.5415b(j).
(l) Reporting. You must perform the reporting requirements as
specified in Sec. Sec. 60.5420b(b)(1), (b)(11), and 60.5422b.
(m) Recordkeeping. You must perform the recordkeeping requirements
as specified in Sec. 60.5420b(c)(8), (10), (12), and Sec. 60.5421b.
Sec. 60.5402b What are the exceptions to the GHG and VOC standards
for process unit equipment affected facilities?
(a) You may comply with the following exceptions to the provisions
of Sec. Sec. 60.5400b(a) and 60.5401b(a), as applicable.
(b) Pumps in light liquid service, pressure relief devices in gas/
vapor service, valves in gas/vapor and light liquid service, and
connectors in gas/vapor service and in light liquid service that are
located at a nonfractionating plant that does not have the design
capacity to process 283,200 standard cubic meters per day (scmd) (10
million standard cubic feet per day) or more of field gas may comply
with the exceptions specified in paragraphs (b)(1) or (2) of this
section.
(1) You are exempt from the bimonthly OGI monitoring as required
under Sec. 60.5400b(b).
(2) You are exempt from the routine Method 21 of appendix A-7
monitoring requirements of Sec. 60.5401b(b), (c), (f), and (h), if
complying with the alternative standards of Sec. 60.5401b.
(c) Pumps in light liquid service, pressure relief devices in gas/
vapor service, valves in gas/vapor and light liquid service, and
connectors in gas/vapor service and in light liquid service within a
process unit that is located in the Alaskan North Slope are exempt from
the monitoring requirements Sec. 60.5400b(b) and (c) and Sec.
60.5401b(b), (c), (f) and (h).
(d) You may use the following provisions instead of Sec.
60.5403b(e):
(1) Equipment is in heavy liquid service if the weight percent
evaporated is 10 percent or less at 150 degrees Celsius (302 degrees
Fahrenheit) as determined by ASTM D86-96 (incorporated by reference,
see Sec. 60.17).
(2) Equipment is in light liquid service if the weight percent
evaporated is greater than 10 percent at 150 degrees Celsius (302
degrees Fahrenheit) as determined by ASTM D86-96 (incorporated by
reference, see Sec. 60.17).
(e) Equipment that is in vacuum service, except connectors in gas/
vapor and light liquid service, is excluded from the requirements of
Sec. 60.5400b(b) through (g), if it is identified as required in Sec.
60.5421b(b)(15). Equipment that is in vacuum service is excluded from
the requirements of Sec. 60.5401b(b) through (g) if it is identified
as required in Sec. 60.5421b(b)(15).
(f) Equipment that you designate as having the potential to emit
methane or VOC less than 300 hr/yr is excluded from the requirements of
Sec. 60.5400b(b) through (g) and Sec. 60.5401b(b) through (h), if it
is identified as required in Sec. 60.5421b(b)(16) and it meets any of
the conditions specified in paragraphs (f)(1) through (3) of this
section.
(1) The equipment has the potential to emit methane or VOC only
during startup and shutdown.
(2) The equipment has the potential to emit methane or VOC only
during process malfunctions or other emergencies.
(3) The equipment is backup equipment that has the potential to
emit methane or VOC only when the primary equipment is out of service.
Sec. 60.5403b What test methods and procedures must I use for my
process unit equipment affected facilities?
(a) In conducting the performance tests required in Sec. 60.8, you
must use as reference methods and procedures the test methods in
appendix A to this part or other methods and procedures as specified in
this section, except as provided in Sec. 60.8(b).
(b) You must determine compliance with the standards in Sec.
60.5401b as follows:
(1) Method 21 of appendix A-7 to this part shall be used to
determine the presence of leaking sources. The instrument shall be
calibrated before use each day of its use by the procedures specified
in Method 21 of appendix A-7 to this part. The following calibration
gases shall be used:
(i) Zero air (less than 10 ppmv of hydrocarbon in air); and
(ii) A mixture of methane or n-hexane and air at a concentration no
more than 2,000 ppmv greater than the leak definition concentration of
the equipment monitored. If the monitoring instrument's design allows
for multiple calibration scales, then the lower scale shall be
calibrated with a calibration gas that is no higher than 2,000 ppmv
above the concentration specified as a leak, and the highest scale
shall be calibrated with a calibration gas that is approximately or
equal to 10,000 ppmv. If only one scale on an instrument will be used
during monitoring, you need not calibrate the scales that will not be
used during that day's monitoring.
(iii) Verification that your monitoring equipment meets the
requirements specified in Section 6.0 of Method 21 of appendix A-7 to
this part. For purposes of instrument capability, the leak definition
shall be 500 ppmv or greater methane using a FID-based instrument for
valves and connectors and 2,000 ppmv methane or greater for pumps. If
you wish to use an analyzer other than a FID-based instrument, you must
develop a site-specific leak definition that would be equivalent to 500
ppmv methane using a FID-based instrument (e.g., 10.6 eV PID with a
specified isobutylene concentration as the leak definition would
provide equivalent response to your compound of interest).
(2) The instrument must be calibrated before use each day of its
use by the procedures specified in Method 21 of appendix A-7 to this
part. At minimum, you must also conduct precision tests at the interval
specified in Method 21 of appendix A-7 to this part, Section 8.1.2, and
a calibration drift assessment at the
[[Page 17079]]
end of each monitoring day. The calibration drift assessment must be
conducted as specified in paragraph (b)(2)(i) of this section.
Corrective action for drift assessments is specified in paragraphs
(b)(2)(ii) and (iii) of this section.
(i) Check the instrument using the same calibration gas that was
used to calibrate the instrument before use. Follow the procedures
specified in Method 21 of appendix A-7 to this part, Section 10.1,
except do not adjust the meter readout to correspond to the calibration
gas value. If multiple scales are used, record the instrument reading
for each scale used. Divide the arithmetic difference of the initial
and post-test calibration response by the corresponding calibration gas
value for each scale and multiply by 100 to express the calibration
drift as a percentage.
(ii) If a calibration drift assessment shows a negative drift of
more than 10 percent, then all equipment with instrument readings
between the fugitive emission definition multiplied by (100 minus the
percent of negative drift) divided by 100 and the fugitive emission
definition that was monitored since the last calibration must be re-
monitored.
(iii) If any calibration drift assessment shows a positive drift of
more than 10 percent from the initial calibration value, then, at the
owner/operator's discretion, all equipment with instrument readings
above the fugitive emission definition and below the fugitive emission
definition multiplied by (100 plus the percent of positive drift)
divided by 100 monitored since the last calibration may be re-
monitored.
(c) You shall determine compliance with the no detectable emission
standards in Sec. 60.5401b(b), (c), and (f) as specified in paragraphs
(c)(1) and (2) of this section.
(1) The requirements of paragraph (b) of this section shall apply.
(2) Method 21 of appendix A-7 to this part shall be used to
determine the background level. All potential leak interfaces shall be
traversed as close to the interface as possible. The arithmetic
difference between the maximum concentration indicated by the
instrument and the background level is compared with 500 ppmv for
determining compliance.
(d) You shall demonstrate that a piece of equipment is in light
liquid service by showing that all of the following conditions apply:
(1) The vapor pressure of one or more of the organic components is
greater than 0.3 kPa at 20 [deg]C (1.2 in H2O at 68 [deg]F).
Standard reference texts or ASTM D2879-83, -96, or -97 (all
incorporated by reference, see Sec. 60.17) shall be used to determine
the vapor pressures.
(2) The total concentration of the pure organic components having a
vapor pressure greater than 0.3 kPa at 20 [deg]C (1.2 in H2O
at 68 [deg]F) is equal to or greater than 20 percent by weight.
(3) The fluid is a liquid at operating conditions.
(e) Samples used in conjunction with paragraphs (d) and (e) of this
section shall be representative of the process fluid that is contained
in or contacts the equipment, or the gas being combusted in the flare.
Sec. 60.5405b What standards apply to sweetening unit affected
facilities?
(a) During the initial performance test required by Sec. 60.8(b),
you must achieve at a minimum, an SO2 emission reduction
efficiency (Zi) to be determined from table 3 to this
subpart based on the sulfur feed rate (X) and the sulfur content of the
acid gas (Y) of the affected facility.
(b) After demonstrating compliance with the provisions of paragraph
(a) of this section, you must achieve at a minimum, an SO2
emission reduction efficiency (Zc) to be determined from
table 4 to this subpart based on the sulfur feed rate (X) and the
sulfur content of the acid gas (Y) of the affected facility.
(c) You must demonstrate initial compliance with the standards that
apply to sweetening unit affected facilities as required by Sec.
60.5410b(i).
(d) You must demonstrate continuous compliance with the standards
that apply to sweetening unit affected facilities as required by Sec.
60.5415b(k).
(e) You must perform the reporting as required by Sec.
60.5420b(a)(1), (b)(1), and Sec. 60.5423b and the recordkeeping as
required by Sec. 60.5423b.
Sec. 60.5406b What test methods and procedures must I use for my
sweetening unit affected facilities?
(a) In conducting the performance tests required in Sec. 60.8, you
must use the test methods in appendix A to this part or other methods
and procedures as specified in this section, except as provided in
Sec. 60.8(b).
(b) During a performance test required by Sec. 60.8, you must
determine the minimum required reduction efficiencies (Z) of
SO2 emissions as required in Sec. 60.5405b(a) and (b) as
follows:
(1) The average sulfur feed rate (X) must be computed as follows:
[GRAPHIC] [TIFF OMITTED] TR08MR24.001
Where:
X = average sulfur feed rate, Mg/D (LT/D).
Qa = average volumetric flow rate of acid gas from
sweetening unit, dscm/day (dscf/day).
Y = average H2S concentration in acid gas feed from
sweetening unit, percent by volume, expressed as a decimal.
K = (32 kg S/kg-mole)/((24.04 dscm/kg-mole)(1000 kg S/Mg)).
= 1.331 x 10-3Mg/dscm, for metric units.
= (32 lb S/lb-mole)/((385.36 dscf/lb-mole)(2240 lb S/long ton)).
= 3.707 x 10-5 long ton/dscf, for English units.
(2) You must use the continuous readings from the process flowmeter
to determine the average volumetric flow rate (Qa) in dscm/
day (dscf/day) of the acid gas from the sweetening unit for each run.
(3) You must use the Tutwiler procedure in Sec. 60.5408b or a
chromatographic procedure following ASTM E260-96 (incorporated by
reference, see Sec. 60.17) to determine the H2S
concentration in the acid gas feed from the sweetening unit (Y). At
least one sample per hour (at equally spaced intervals) must be taken
during each 4-hour run. The arithmetic mean of all samples must be the
average H2S concentration (Y) on a dry basis for the run. By
multiplying the result from the Tutwiler procedure by 1.62 x 10\-3\,
the units gr/100 scf are converted to volume percent.
(4) Using the information from paragraphs (b)(1) and (3) of this
section, tables 3 and 4 to this subpart must be used to determine the
required initial (Zi) and continuous (Zc)
reduction efficiencies of SO2 emissions.
[[Page 17080]]
(c) You must determine the emission reduction efficiency (R)
achieved by the sulfur recovery technology as follows:
(1) You must compute the emission reduction efficiency (R) achieved
by the sulfur recovery technology for each run using the following
equation:
[GRAPHIC] [TIFF OMITTED] TR08MR24.002
(2) You must use the level indicators or manual soundings to
measure the liquid sulfur accumulation rate in the product storage
vessels. You must use readings taken at the beginning and end of each
run, the tank geometry, sulfur density at the storage temperature, and
sample duration to determine the sulfur production rate (S) in kg/hr
(lb/hr) for each run.
(3) You must compute the emission rate of sulfur for each run as
follows:
[GRAPHIC] [TIFF OMITTED] TR08MR24.003
Where:
E = emission rate of sulfur per run, kg/hr.
Ce = concentration of sulfur equivalent (SO2+
reduced sulfur), g/dscm (lb/dscf).
Qsd = volumetric flow rate of effluent gas, dscm/hr
(dscf/hr).
K1 = conversion factor, 1000 g/kg (7000 gr/lb).
(4) The concentration (Ce) of sulfur equivalent must be
the sum of the SO2 and TRS concentrations, after being
converted to sulfur equivalents. For each run and each of the test
methods specified in this paragraph (c) of this section, you must use a
sampling time of at least 4 hours. You must use Method 1 of appendix A-
1 to this part to select the sampling site. The sampling point in the
duct must be at the centroid of the cross-section if the area is less
than 5 m\2\ (54 ft\2\) or at a point no closer to the walls than 1 m
(39 in) if the cross-sectional area is 5 m\2\ or more, and the centroid
is more than 1 m (39 in) from the wall.
(i) You must use Method 6 or 6C of appendix A-4 to this part to
determine the SO2 concentration. You must take eight samples
of 20 minutes each at 30-minute intervals. The arithmetic average must
be the concentration for the run. The concentration must be multiplied
by 0.5 x 10-3 to convert the results to sulfur equivalent.
In place of Method 6 of appendix A to this part, you may use ANSI/ASME
PTC 19.10-1981, Part 10 (manual portion only) (incorporated by
reference, see Sec. 60.17).
(ii) You must use Method 2 of appendix A-1 to this part to
determine the volumetric flow rate of the effluent gas. A velocity
traverse must be conducted at the beginning and end of each run. The
arithmetic average of the two measurements must be used to calculate
the volumetric flow rate (Qsd) for the run. For the
determination of the effluent gas molecular weight, a single integrated
sample over the 4-hour period may be taken and analyzed or grab samples
at 1-hour intervals may be taken, analyzed, and averaged.
(iii) You must use Method 4 of appendix A-2 to this part for
moisture content. Alternatively, you must take two samples of at least
0.10 dscm (3.5 dscf) and 10 minutes at the beginning of the 4-hour run
and near the end of the time period. The arithmetic average of the two
runs must be the moisture content for the run.
(iv) You must use Method 15 of appendix A-5 to this part to
determine the TRS concentration from reduction-type devices or where
the oxygen content of the effluent gas is less than 1.0 percent by
volume. The sampling rate must be at least 3 liters/min (0.1 ft\3\/min)
to insure minimum residence time in the sample line. You must take
sixteen samples at 15-minute intervals. The arithmetic average of all
the samples must be the concentration for the run. The concentration in
ppmv reduced sulfur as sulfur must be multiplied by 1.333 x
10-3 to convert the results to sulfur equivalent.
(v) You must use Method 16A of appendix A-6 to this part or ANSI/
ASME PTC 19.10-1981, Part 10 (manual portion only) (incorporated by
reference, see Sec. 60.17) to determine the reduced sulfur
concentration from oxidation-type devices or where the oxygen content
of the effluent gas is greater than 1.0 percent by volume. You must
take eight samples of 20 minutes each at 30-minute intervals. The
arithmetic average must be the concentration for the run. The
concentration in ppm reduced sulfur as sulfur must be multiplied by
1.333 x 10-3 to convert the results to sulfur equivalent.
(iv) You must use EPA Method 2 of appendix A-1 to this part to
determine the volumetric flow rate of the effluent gas. A velocity
traverse must be conducted at the beginning and end of each run. The
arithmetic average of the two measurements must be used to calculate
the volumetric flow rate (Qsd) for the run. For the
determination of the effluent gas molecular weight, a single integrated
sample over the 4-hour period may be taken and analyzed or grab samples
at 1-hour intervals may be taken, analyzed, and averaged. For the
moisture content, you must take two samples of at least 0.10 dscm (3.5
dscf) and 10 minutes at the beginning of the 4-hour run and near the
end of the time period. The arithmetic average of the two runs must be
the moisture content for the run.
Sec. 60.5407b What are the requirements for monitoring of emissions
and operations from my sweetening unit affected facilities?
(a) If your sweetening unit affected facility is subject to the
provisions of Sec. 60.5405b(a) or (b) you must install, calibrate,
maintain, and operate monitoring devices or perform measurements to
determine the following operations information on a daily basis:
(1) The accumulation of sulfur product over each 24-hour period.
The monitoring method may incorporate the use of an instrument to
measure and record the liquid sulfur production rate or may be a
procedure for measuring and recording the sulfur liquid levels in the
storage vessels with a level indicator or by manual soundings, with
subsequent calculation of the sulfur production rate based on the tank
geometry, stored sulfur density, and elapsed time between readings. The
method must be designed to be accurate
[[Page 17081]]
within 2 percent of the 24-hour sulfur accumulation.
(2) The H2S concentration in the acid gas from the
sweetening unit for each 24-hour period. At least one sample per 24-
hour period must be collected and analyzed using the equation specified
in Sec. 60.5406b(b)(1). The Administrator may require you to
demonstrate that the H2S concentration obtained from one or
more samples over a 24-hour period is within 20 percent of
the average of 12 samples collected at equally spaced intervals during
the 24-hour period. In instances where the H2S concentration
of a single sample is not within 20 percent of the average
of the 12 equally spaced samples, the Administrator may require a more
frequent sampling schedule.
(3) The average acid gas flow rate from the sweetening unit. You
must install and operate a monitoring device to continuously measure
the flow rate of acid gas. The monitoring device reading must be
recorded at least once per hour during each 24-hour period. The average
acid gas flow rate must be computed from the individual readings.
(4) The sulfur feed rate (X). For each 24-hour period, you must
compute X using the equation specified in Sec. 60.5406b(b)(1).
(5) The required sulfur dioxide emission reduction efficiency for
the 24-hour period. You must use the sulfur feed rate and the
H2S concentration in the acid gas for the 24-hour period, as
applicable, to determine the required reduction efficiency in
accordance with the provisions of Sec. 60.5405b(b).
(b) Where compliance is achieved through the use of an oxidation
control system or a reduction control system followed by a continually
operated incineration device, you must install, calibrate, maintain,
and operate monitoring devices and continuous emission monitors as
follows:
(1) A continuous monitoring system to measure the total sulfur
emission rate (E) of SO2 in the gases discharged to the
atmosphere. The SO2 emission rate must be expressed in terms
of equivalent sulfur mass flow rates (kg/hr (lb/hr)). The span of this
monitoring system must be set so that the equivalent emission limit of
Sec. 60.5405b(b) will be between 30 percent and 70 percent of the
measurement range of the instrument system.
(2) Except as provided in paragraph (b)(3) of this section: A
monitoring device to measure the temperature of the gas leaving the
combustion zone of the incinerator, if compliance with Sec.
60.5405b(a) is achieved through the use of an oxidation control system
or a reduction control system followed by a continually operated
incineration device. The monitoring device must be certified by the
manufacturer to be accurate to within 1 percent of the
temperature being measured.
(3) When performance tests are conducted under the provision of
Sec. 60.8 to demonstrate compliance with the standards under Sec.
60.5405b, the temperature of the gas leaving the incinerator combustion
zone must be determined using the monitoring device. If the volumetric
ratio of sulfur dioxide to sulfur dioxide plus total reduced sulfur
(expressed as SO2) in the gas leaving the incinerator is
equal to or less than 0.98, then temperature monitoring may be used to
demonstrate that sulfur dioxide emission monitoring is sufficient to
determine total sulfur emissions. At all times during the operation of
the facility, you must maintain the average temperature of the gas
leaving the combustion zone of the incinerator at or above the
appropriate level determined during the most recent performance test to
ensure the sulfur compound oxidation criteria are met. Operation at
lower average temperatures may be considered by the Administrator to be
unacceptable operation and maintenance of the affected facility. You
may request that the minimum incinerator temperature be reestablished
by conducting new performance tests under Sec. 60.8.
(4) Upon promulgation of a performance specification of continuous
monitoring systems for total reduced sulfur compounds at sulfur
recovery plants, you may, as an alternative to paragraph (b)(2) of this
section, install, calibrate, maintain, and operate a continuous
emission monitoring system for total reduced sulfur compounds as
required in paragraph (d) of this section in addition to a sulfur
dioxide emission monitoring system. The sum of the equivalent sulfur
mass emission rates from the two monitoring systems must be used to
compute the total sulfur emission rate (E).
(c) Where compliance is achieved using a reduction control system
not followed by a continually operated incineration device, you must
install, calibrate, maintain, and operate a continuous monitoring
system to measure the emission rate of reduced sulfur compounds as
SO2 equivalent in the gases discharged to the atmosphere.
The SO2 equivalent compound emission rate must be expressed
in terms of equivalent sulfur mass flow rates (kg/hr (lb/hr)). The span
of this monitoring system must be set so that the equivalent emission
limit of Sec. 60.5405b(b) will be between 30 and 70 percent of the
measurement range of the system. This requirement becomes effective
upon promulgation of a performance specification for continuous
monitoring systems for total reduced sulfur compounds at sulfur
recovery plants.
(d) For those sources required to comply with paragraph (b) or (c)
of this section, you must calculate the average sulfur emission
reduction efficiency achieved (R) for each 24-hour clock interval. The
24-hour interval may begin and end at any selected clock time but must
be consistent. You must compute the 24-hour average reduction
efficiency (R) based on the 24-hour average sulfur production rate (S)
and sulfur emission rate (E), using the equation in Sec.
60.5406b(c)(1).
(1) You must use data obtained from the sulfur production rate
monitoring device specified in paragraph (a) of this section to
determine S.
(2) You must use data obtained from the sulfur emission rate
monitoring systems specified in paragraphs (b) or (c) of this section
to calculate a 24-hour average for the sulfur emission rate (E). The
monitoring system must provide at least one data point in each
successive 15-minute interval. You must use at least two data points to
calculate each 1-hour average. You must use a minimum of 18 1-hour
averages to compute each 24-hour average.
(e) In lieu of complying with paragraphs (b) or (c) of this
section, those sources with a design capacity of less than 152 Mg/D
(150 LT/D) of H2S expressed as sulfur may calculate the
sulfur emission reduction efficiency achieved for each 24-hour period
by:
[GRAPHIC] [TIFF OMITTED] TR08MR24.004
[[Page 17082]]
Where:
R = The sulfur dioxide removal efficiency achieved during the 24-
hour period, percent.
K2 = Conversion factor, 0.02400 Mg/D per kg/hr (0.01071
LT/D per lb/hr).
S = The sulfur production rate during the 24-hour period, kg/hr (lb/
hr).
X = The sulfur feed rate in the acid gas, Mg/D (LT/D).
(f) The monitoring devices required in paragraphs (b)(1) and (3)
and (c) of this section must be calibrated at least annually according
to the manufacturer's specifications, as required by Sec. 60.13(b).
(g) The continuous emission monitoring systems required in
paragraphs (b)(1) and (3), and (c) of this section must be subject to
the emission monitoring requirements of Sec. 60.13. For conducting the
continuous emission monitoring system performance evaluation required
by Sec. 60.13(c), Performance Specification 2 of appendix B to this
part must apply, and Method 6 of appendix A-4 to this part must be used
for systems required by paragraph (b) of this section. In place of
Method 6 of appendix A-4 to this part, ASME PTC 19.10-1981
(incorporated by reference, see Sec. 60.17) may be used.
Sec. 60.5408b What is an optional procedure for measuring hydrogen
sulfide in acid gas--Tutwiler Procedure?
The Tutwiler procedure may be found in the Gas Engineers Handbook,
Fuel Gas Engineering practices, The Industrial Press, 93 Worth Street,
New York, NY, 1966, First Edition, Second Printing, page 6/25 (Docket
A-80-20-A, Entry II-I-67).
(a) Sampling. When an instantaneous sample is desired and
H2S concentration is 10 grains per 1000 cubic foot or more,
a 100 ml Tutwiler burette is used. For concentrations less than 10
grains, a 500 ml Tutwiler burette and more dilute solutions are used.
In principle, this method consists of titrating hydrogen sulfide in a
gas sample directly with a standard solution of iodine.
(b) Apparatus. (See figure 1 to this section.) A 100- or 500-ml
capacity Tutwiler burette, with two-way glass stopcock at bottom and
three-way stopcock at top that connect either with inlet tubulature or
glass-stoppered cylinder, 10 ml capacity, graduated in 0.1 ml
subdivision; rubber tubing connecting burette with leveling bottle.
(c) Reagents. (1) Iodine stock solution, 0.1N. Weight 12.7 g
iodine, and 20 to 25 g cp potassium iodide (KI) for each liter of
solution. Dissolve KI in as little water as necessary; dissolve iodine
in concentrated KI solution, make up to proper volume, and store in
glass-stoppered brown glass bottle.
(2) Standard iodine solution, 1 ml = 0.001771 g I. Transfer 33.7 ml
of above 0.1N stock solution into a 250 ml volumetric flask; add water
to mark and mix well. Then, for 100 ml sample of gas, 1 ml of standard
iodine solution is equivalent to 100 grains H2S per cubic
feet of gas.
(3) Rub into a thin paste about one teaspoonful of wheat starch
with a little water; pour into about a pint of boiling water; stir; let
cool and decant off clear solution. Make fresh solution every few days.
(d) Procedure. (Refer to figure 1 to this section.) Fill leveling
bulb with starch solution. Raise (L), open cock (G), open (F) to (A),
and close (F) when solutions start to run out of gas inlet. Close (G).
Purge gas sampling line and connect with (A). Lower (L) and open (F)
and (G). When liquid level is several ml past the 100 ml mark, close
(G) and (F), and disconnect sampling tube. Open (G) and bring starch
solution to 100 ml mark by raising (L); then close (G). Open (F)
momentarily, to bring gas in burette to atmospheric pressure, and close
(F). Open (G), bring liquid level down to 10 ml mark by lowering (L).
Close (G), clamp rubber tubing near (E) and disconnect it from burette.
Rinse graduated cylinder with a standard iodine solution (0.00171 g I
per ml); fill cylinder and record reading. Introduce successive small
amounts of iodine through (F); shake well after each addition; continue
until a faint permanent blue color is obtained. Record reading;
subtract from previous reading, and call difference D.
(e) Blank testing. (Refer to figure 1 to this section.) With every
fresh stock of starch solution perform a blank test as follows:
Introduce fresh starch solution into burette up to 100 ml mark. Close
(F) and (G). Lower (L) and open (G). When liquid level reaches the 10
ml mark, close (G). With air in burette, titrate as during a test and
up to same end point. Call ml of iodine used C. Then,
[GRAPHIC] [TIFF OMITTED] TR08MR24.044
(f) Test sensitivity. Greater sensitivity can be attained if a 500
ml capacity Tutwiler burette is used with a more dilute (0.001N) iodine
solution. Concentrations less than 1.0 grains per 100 cubic foot can be
determined in this way. Usually, the starch-iodine end point is much
less distinct, and a blank determination of end point, with
H2S-free gas or air, is required.
BILLING CODE 6560-50-P
[[Page 17083]]
[GRAPHIC] [TIFF OMITTED] TR08MR24.005
Figure 1 to Sec. 60.5408b. Tutwiler burette (lettered items mentioned
in text).
BILLING CODE 6560-50-C
Sec. 60.5410b How do I demonstrate initial compliance with the
standards for each of my affected facilities?
You must determine initial compliance with the standards for each
affected facility using the requirements of paragraphs (a) through (k)
of this section. Except as otherwise provided in this section, the
initial compliance period begins on the date specified in Sec.
60.5370b and ends no later than 1 year after that date. The initial
compliance period may be less than 1 full year.
(a) Well completion standards for well affected facilities. To
achieve initial compliance with the GHG and VOC standards for each well
completion operation conducted at your well affected facility as
required by Sec. 60.5375b, you must comply with paragraphs (a)(1)
through (4) of this section.
(1) You must submit the notification required in Sec.
60.5420b(a)(2).
(2) You must submit the initial annual report for your well
affected facility as required in Sec. 60.5420b(b)(1) and (2).
(3) You must maintain a log of records as specified in Sec.
60.5420b(c)(1)(i) through (iv) and (vii), as applicable, for each well
completion operation conducted. If you meet the exemption at Sec.
60.5375b(g) for wells with a GOR less than 300 scf per stock barrel of
oil produced, you do not have to maintain the records in Sec.
60.5420b(c)(1)(i) through (iv) and must maintain the record in Sec.
60.5420b(c)(1)(vi). If you meet the exemption at Sec. 60.5375b(h) for
a well modified in accordance with Sec. 60.5365b(a)(1)(ii) (i.e., an
existing well is hydraulically refractured), you do not need to
maintain the records in Sec. 60.5420b(c)(1)(i) through (iv) and must
maintain the record in Sec. 60.5420b(c)(1)(viii).
(4) For each well completion affected facility subject to both
Sec. 60.5375b(a)(1) and (2), as an alternative to retaining the
records specified in Sec. 60.5420b(c)(1)(i) through (iv), you may
maintain records in accordance with Sec. 60.5420b(c)(1)(v).
(b) Gas well liquids unloading standards for well affected
facility. To demonstrate initial compliance with the GHG and VOC
standards for each gas well liquids unloading operation conducted at
your gas well affected facility as required by Sec. 60.5376b, you must
comply with paragraphs (b)(1) through (4) of this section, as
applicable.
(1) You must submit the initial annual report for your well
affected facility as required in Sec. 60.5420b(b)(1) and (3).
[[Page 17084]]
(2) If you comply by using a liquids unloading technology or
technique that does not vent to the atmosphere according to Sec.
60.5376b(a)(1), you must maintain the records specified in Sec.
60.5420b(c)(2)(i).
(3) If you comply by using a liquids unloading technology or
technique that vents to the atmosphere according to Sec.
60.5376b(a)(2), (b) and (c), you must comply with paragraphs (b)(3)(i)
and (ii) of this section.
(i) Employ best management practices to minimize venting of methane
and VOC emissions as specified in Sec. 60.5376b(c) for each gas well
liquids unloading operation.
(ii) Maintain the records specified in Sec. 60.5420b(c)(2)(ii).
(4) If you comply by using Sec. 60.5376b(g), you must comply with
paragraphs (b)(4)(i) through (vii) of this section.
(i) Reduce methane and VOC emissions by 95.0 percent or greater and
as demonstrated by the requirements of Sec. 60.5413b.
(ii) Install a closed vent system that meets the requirements of
Sec. 60.5411b(a) and (c) to capture all emissions and route all
emissions to a control device that meets the conditions specified in
Sec. 60.5412b.
(iii) Conduct an initial performance test as required in Sec.
60.5413b within 180 days after the initial gas well liquids unloading
operation, or install a control device tested under Sec. 60.5413b(d)
which meets the criteria in Sec. 60.5413b(d)(11) and (e), and comply
with the continuous compliance requirements of Sec. 60.5415b(f).
(iv) You must conduct the initial inspections required in Sec.
60.5416b(a) and (b).
(v) You must install and operate the continuous parameter
monitoring systems in accordance with Sec. 60.5417b(a) through (i), as
applicable.
(vi) You must maintain the records specified in Sec.
60.5420b(c)(2)(iii),(c)(8) and (c)(10) through (13), as applicable and
submit the reports as required by Sec. 60.5420b(b)(11) through (13),
as applicable.
(c) Associated gas well standards for well affected facility. To
demonstrate initial compliance with the GHG and VOC standards for each
associated gas well as required by Sec. 60.5377b, you must comply with
paragraphs (c)(1) through (3) of this section.
(1) If you comply with the requirements of Sec. 60.5377b(a), you
must maintain the records specified in Sec. 60.5420b(c)(3)(i), (ii),
and (iv).
(2) For associated gas wells that comply with Sec. 60.5377b(f)
based on a demonstration and certification that it is not feasible to
comply with paragraph (a)(1), (2), (3), and (4) of this section due to
technical reasons in accordance with paragraph Sec. 60.5377b(g), you
must comply with paragraphs (c)(2)(i) and (ii) of this section.
(i) Document the technical reasons why it is infeasible to route
recovered associated gas into a gas gathering flow line or collection
system to a sales line, use it as an onsite fuel source, use it for
another useful purpose that a purchased fuel or raw material would
serve, or re-inject it into the well or inject it into another well,
and submit this documentation in the initial annual report.
(ii) Submit the certification as required by Sec. 60.5377b(g).
(3) If you comply with Sec. 60.5377b(d) or (f), you must comply
with paragraphs (c)(3)(i) through (vi) of this section.
(i) Reduce methane and VOC emissions by 95.0 percent or greater and
as demonstrated by the requirements of Sec. 60.5413b.
(ii) Install a closed vent system that meets the requirements of
Sec. 60.5411b(a) and (c) to capture the associated gas and route the
captured associated gas to a control device that meets the conditions
specified in Sec. 60.5412b.
(iii) Conduct an initial performance test as required in Sec.
60.5413b within 180 days after initial startup or by May 7, 2024,
whichever date is later, or install a control device tested under Sec.
60.5413b(d) which meets the criteria in Sec. 60.5413b(d)(11) and (e)
and you must comply with the continuous compliance requirements of
Sec. 60.5415b(f).
(iv) Conduct the initial inspections required in Sec. 60.5416b(a)
and (b).
(v) Install and operate the continuous parameter monitoring systems
in accordance with Sec. 60.5417b(a) through (i), as applicable.
(vi) Maintain the records specified in Sec. 60.5420b(c)(3)(iv) and
(c)(8) and (c)(10) through (13), as applicable.
(4) You must submit the initial annual report for your associated
gas well as required in Sec. 60.5420b(b)(1) and (4) and (b)(11)
through (13), as applicable.
(d) Centrifugal compressor affected facility. To demonstrate
initial compliance with the GHG and VOC standards for your centrifugal
compressor affected facility that uses a wet seal as required by Sec.
60.5380b, you must comply with paragraphs (d)(1) through (5) and
paragraphs (d)(7) and (8) of this section. To demonstrate initial
compliance with the GHG and VOC alternative standards for your
centrifugal compressor affected facility that is a self-contained wet
seal centrifugal compressor or a centrifugal compressor at the Alaska
North Slope equipped with sour seal oil separator and capture system as
allowed by Sec. 60.5380b, you must comply with paragraphs (d)(6)
through (8) of this section. To demonstrate initial compliance with the
GHG and VOC alternative standards for your dry seal centrifugal
compressor as required by Sec. 60.5380b, you must comply with
paragraphs (d)(6) through (8) of this section.
(1) You must reduce methane and VOC emissions by 95.0 percent or
greater according to Sec. 60.5380b(a)(1) and (2) and as demonstrated
by the requirements of Sec. 60.5413b, or you must route emissions to a
process according to Sec. 60.5380b(a)(3).
(2) If you use a control device to reduce emissions to comply with
Sec. 60.5380b(a)(1) and (2), you must equip the wet seal fluid
degassing system with a cover that meets the requirements of Sec.
60.5411b(b) that is connected through a closed vent system that meets
the requirements of Sec. 60.5411b(a) and (c) and is routed to a
control device that meets the conditions specified in Sec. 60.5412b.
If you comply with Sec. 60.5380b(a)(3) by routing the closed vent
system to a process as an alternative to routing the closed vent system
to a control device, you must equip the wet seal fluid degassing system
with a cover that meets the requirements of Sec. 60.5411b(b), and
route captured vapors through a closed vent system that meets the
requirements of Sec. 60.5411b(a) and (c).
(3) If you use a control device to comply with Sec. 60.5380b(a)(1)
and (2), you must conduct an initial performance test as required in
Sec. 60.5413b within 180 days after initial startup or by May 7, 2024,
whichever date is later, or install a control device tested under Sec.
60.5413b(d) which meets the criteria in Sec. 60.5413b(d)(11) and (e)
and you must comply with the continuous compliance requirements of
Sec. 60.5415b(f).
(4) If you use a control device to comply with Sec. 60.5380b(a)(1)
and (2) or comply with Sec. 60.5380b(a)(3) by routing to a process,
you must conduct the initial inspections required in Sec. 60.5416b(a)
and (b).
(5) If you use a control device to comply with Sec. 60.5380b(a)(1)
and (2), you must install and operate the continuous parameter
monitoring systems in accordance with Sec. 60.5417b(a) through (i), as
applicable.
(6) You must maintain the volumetric flow rates for your
centrifugal compressors as specified in paragraphs (d)(6)(i) through
(iii) of this section, as applicable. You must conduct your
[[Page 17085]]
initial annual volumetric measurement as required by Sec.
60.5380b(a)(5).
(i) For your self-contained wet seal centrifugal compressors, you
must maintain the volumetric flow rate at or below 3 scfm per seal.
(ii) For your centrifugal compressor on the Alaska North Slope
equipped with sour seal oil separator and capture system, you must
maintain the volumetric flow rate at or below 9 scfm per seal.
(iii) For your dry seal compressor, you must maintain the
volumetric flow rate at or below 10 scfm per seal.
(7) You must submit the initial annual report for your centrifugal
compressor affected facility as required in Sec. 60.5420b(b)(1) and
(5) and (b)(11) through (13), as applicable.
(8) You must maintain the records as specified in Sec.
60.5420b(c)(4) and (c)(8) through (13), as applicable.
(e) Reciprocating compressor affected facility. To demonstrate
initial compliance with the GHG and VOC standards for each
reciprocating compressor affected facility as required by Sec.
60.5385b, you must comply with paragraphs (e)(1) through (7) of this
section.
(1) If you comply with Sec. 60.5385b by maintaining volumetric
flow rate at or below 2 scfm per cylinder (or a combined cylinder
volumetric flow rate greater than the number of compression cylinders
multiplied by 2 scfm) as required by Sec. 60.5385b(a), you must
maintain volumetric flow rate at or below 2 scfm and you must conduct
your initial annual volumetric flow rate measurement as required by
Sec. 60.5385b(a)(1).
(2) If you comply with Sec. 60.5385bby collecting the methane and
VOC emissions from your reciprocating compressor rod packing using a
rod packing emissions collection system as required by Sec.
60.5385b(d)(1), you must equip the reciprocating compressor with a
cover that meets the requirements of Sec. 60.5411b(b), route emissions
to a process through a closed vent system that meets the requirements
of Sec. 60.5411b(a) and (c), and you must conduct the initial
inspections required in Sec. 60.5416b(a) and (b).
(3) If you comply with Sec. 60.5385b(d) by collecting the
emissions from your rod packing emissions collection system by using a
control device to reduce VOC and methane emissions by 95.0 percent as
required by Sec. 60.5385b(d)(2), you must equipe the reciprocating
compressor with a cover that meets the requirements of Sec.
60.5411b(b), route emissions to a control device that meets the
conditions specified in Sec. 60.5412b through a closed vent system
that meets the requirements of Sec. 60.5411b(a) and (c) and you must
conduct the initial inspections required in Sec. 60.5416b(a) and (b).
(4) If you comply with Sec. 60.5385b(d)(2), you must conduct an
initial performance test as required in Sec. 60.5413b within 180 days
after initial startup or by May 7, 2024, whichever date is later, or
install a control device tested under Sec. 60.5413b(d) which meets the
criteria in Sec. 60.5413b(d)(11) and (e) and you must comply with the
continuous compliance requirements of Sec. 60.5415b(f).
(5) If you comply with Sec. 60.5385b(d)(2), you must install and
operate the continuous parameter monitoring systems in accordance with
Sec. 60.5417b(a) through (i), as applicable.
(6) You must submit the initial annual report for your
reciprocating compressor as required in Sec. 60.5420b(b)(1), (6), and
(11) through (13), as applicable.
(7) You must maintain the records as specified in Sec.
60.5420b(c)(5) and (8) through (13) as applicable.
(f) Process controller affected facility. To demonstrate initial
compliance with GHG and VOC emission standards for your process
controller affected facility as required by Sec. 60.5390b, you must
comply with paragraphs (f)(1) through (5) of this section, as
applicable. If you change compliance methods, you must perform the
applicable compliance demonstrations of paragraphs (f)(1) through (3)
of this section again for the new compliance method, note the change in
compliance method in the annual report required by Sec.
60.5420b(b)(7)(iv), and maintain the records required by paragraph
(f)(5) of this section for the new compliance method.
(1) For process controller affected facilities complying with the
requirements of Sec. 60.5390b(a), you must demonstrate that your
process controller affected facility does not emit any VOC or methane
to the atmosphere by meeting the requirements of paragraphs (f)(1)(i)
or (ii) of this section.
(i) If you comply by routing the emissions to a process, you must
meet the requirements for closed vent systems specified in paragraph
(f)(3) of this section.
(ii) If you comply by using a self-contained natural gas-driven
process controller, you must conduct an initial no identifiable
emissions inspection as required by Sec. 60.5416b(b).
(2) For each process controller affected facility located at a site
in Alaska that does not have access to electrical power, you must
demonstrate initial compliance with Sec. 60.5390b(b)(1) and (2) or
with Sec. 60.5390b(b)(3), instead of complying with paragraph Sec.
60.5390b(a), by meeting the requirements specified in (f)(2)(i) through
(v) of this section for each process controller, as applicable.
(i) For each process controller in the process controller affected
facility operating with a bleed rate of less than or equal to 6 scfh,
you must maintain records in accordance with Sec.
60.5420b(c)(6)(iii)(A) that demonstrate the process controller is
designed and operated to achieve a bleed rate less than or equal to 6
scfh.
(ii) For each process controller in the process controller affected
facility operating with a bleed rate greater than 6 scfh, you must
maintain records that demonstrate that a controller with a higher bleed
rate than 6 scfh is required based on a specific functional need for
that controller as specified in Sec. 60.5420b(c)(6)(iii)(B).
(iii) For each intermittent vent process controller in the process
controller affected facility you must demonstrate that each
intermittent vent controller does not emit to the atmosphere during
idle periods by conducting initial monitoring in accordance with Sec.
60.5390b(b)(2)(ii).
(iv) For each process controller affected facility that complies by
reducing methane and VOC emissions from all controllers in the process
controller affected facility by 95.0 percent in accordance with Sec.
60.5390b(b)(3), you must comply with paragraphs (b)(2)(iv)(A) through
(D) of this section.
(A) Reduce methane and VOC emissions by 95.0 percent or greater and
as demonstrated by the requirements of Sec. 60.5413b.
(B) Route all process controller affected facility emissions to a
control device that meets the conditions specified in Sec. 60.5412b
through a closed vent system that meets the requirements specified in
paragraph (f)(3) of this section.
(C) Conduct an initial performance test as required in Sec.
60.5413b within 180 days after initial startup or by May 7, 2024,
whichever date is later, or install a control device tested under Sec.
60.5413b(d) which meets the criteria in Sec. 60.5413b(d)(11) and (e)
and you must comply with the continuous compliance requirements of
Sec. 60.5415b(f).
(D) Install and operate the continuous parameter monitoring systems
in accordance with Sec. 60.5417b(a) through (i), as applicable.
(3) For each closed vent system used to comply with Sec. 60.5390b,
you must meet the requirements specified in
[[Page 17086]]
paragraphs (f)(3)(i) and (ii) of this section.
(i) Install a closed vent system that meets the requirements of
Sec. 60.5411b(a) and (c).
(ii) Conduct the initial inspections of the closed vent system and
bypasses, if applicable, as required in Sec. 60.5416b(a) and (b).
(4) You must submit the initial annual report for your process
controller affected facility as required in Sec. 60.5420b(b)(1) and
(7).
(5) You must maintain the records as specified in Sec.
60.5420b(c)(6).
(g) Pump affected facility. To demonstrate initial compliance with
the GHG and VOC standards for your pump affected facility as required
by Sec. 60.5393b, you must comply with paragraphs (g)(1) through (4)
of this section, as applicable. If you change compliance methods, you
must perform the applicable compliance demonstrations of paragraphs
(g)(1) and (2) of this section again for the new compliance method,
note the change in compliance method in the annual report required by
Sec. 60.5420b(b)(10)(v)(C), and maintain the records required by
paragraph (g)(4) of this section for the new compliance method.
(1) For pump affected facilities complying with the requirements of
Sec. 60.5393b(a) or (b)(2) by routing emissions to a process, you must
meet the requirements specified in paragraphs (g)(ii) and (iv) of this
section. For pump affected facilities complying with the requirements
of Sec. 60.5393b(b)(3), you must meet the requirements specified in
paragraphs (g)(1)(i) through (v) of this section.
(i) Reduce methane and VOC emissions by 95.0 percent or greater and
as demonstrated by the requirements of Sec. 60.5413b.
(ii) Install a closed vent system that meets the requirements of
Sec. 60.5411b(a) and (c) to capture all emissions from all pumps in
the pump affected facility and route all emissions to a process or
control device that meets the conditions specified in Sec. 60.5412b.
(iii) Conduct an initial performance test as required in Sec.
60.5413b within 180 days after initial startup or by May 7, 2024,
whichever date is later, or install a control device tested under Sec.
60.5413b(d) which meets the criteria in Sec. 60.5413b(d)(11) and (e)
and you must comply with the continuous compliance requirements of
Sec. 60.5415b(f).
(iv) Conduct the initial inspections of the closed vent system and
bypasses, if applicable, as required in Sec. 60.5416b(a) and (b).
(v) Install and operate the continuous parameter monitoring systems
in accordance with Sec. 60.5417b(a) through (i), as applicable.
(2) Submit the certifications specified in paragraphs (g)(2)(i)
through (iii) of this section, as applicable.
(i) The certification required by Sec. 60.5393b(b)(3) that there
is no vapor recovery unit on site and that there is a control device on
site, but it does not achieve a 95.0 percent emissions reduction.
(ii) The certification required by Sec. 60.5393b(b)(4) that there
is no control device or process available on site.
(iii) The certification required by Sec. 60.5393b(b)(5)(i) that it
is technically infeasible to capture and route the pump affected
facility emissions to a process or an existing control device.
(3) You must submit the initial annual report for your pump
affected facility as specified in Sec. 60.5420b(b)(1), (10), and
(b)(11) through (13), as applicable.
(4) You must maintain the records for your pump affected facility
as specified in Sec. 60.5420b(c)(8) and (c)(10) through (13), as
applicable, and (c)(15).
(h) Process unit equipment affected facility. To achieve initial
compliance with the GHG and VOC standards for process unit equipment
affected facilities as required by Sec. 60.5400b, you must comply with
paragraphs (h)(1) through (4) and (h)(11) through (15) of this section,
unless you meet and comply with the exception in Sec. 60.5402b(b),
(e), or (f) or meet the exemption in Sec. 60.5402b(c). If you comply
with the GHG and VOC standards for process unit equipment affected
facilities using the alternative standards in Sec. 60.5401b, you must
comply with paragraphs (h)(5) through (15) of this section, unless you
meet the exemption in Sec. 60.5402b(b) or (c) or the exception in
Sec. 60.5402b(e) or (f).
(1) You must conduct monitoring for each pump in light liquid
service, pressure relief device in gas/vapor service, valve in gas/
vapor or light liquid service and connector in gas/vapor or light
liquid service as required by Sec. 60.5400b(b).
(2) You must conduct monitoring as required by Sec. 60.5400b(c)
for each pump in light liquid service.
(3) You must conduct monitoring as required by Sec. 60.5400b(d)
for each pressure relief device in gas/vapor service.
(4) You must comply with the equipment requirements for each open-
ended valve or line as required by Sec. 60.5400b(e).
(5) You must conduct monitoring for each pump in light liquid
service as required by Sec. 60.5401b(b).
(6) You must conduct monitoring for each pressure relief device in
gas/vapor service as required by Sec. 60.5401b(c).
(7) You must comply with the equipment requirements for each open-
ended valve or line as required by Sec. 60.5401b(d).
(8) You must conduct monitoring for each valve in gas/vapor or
light liquid service as required by Sec. 60.5401b(f).
(9) You must conduct monitoring for each pump, valve, and connector
in heavy liquid service and each pressure relief device in light liquid
or heavy liquid service as required by Sec. 60.5401b(g).
(10) You must conduct monitoring for each connector in gas/vapor or
light liquid service as required by Sec. 60.5401b(h).
(11) For each pump equipped with a dual mechanical seal system that
degasses the barrier fluid reservoir to a process or a control device,
each pump which captures and transports leakage from the seal or seals
to a process or a control device, or each pressure relief device which
captures and transports leakage through the pressure relief device to a
process or a control device, you must meet the requirements of
paragraph (h)(11)(i) through (vi) of this section.
(i) Reduce methane and VOC emissions by 95.0 percent or greater and
as demonstrated by the requirements of Sec. 60.5413b or route to a
process.
(ii) Install a closed vent system that meets the requirements of
Sec. 60.5411b(a) and (c) to capture all emissions from each pump
equipped with a dual mechanical seal system that degasses the barrier
fluid reservoir, each pump which captures and transports leakage from
the seal or seals, or each pressure relief device which captures and
transports leakage through the pressure relief device and route all
emissions to a process or to a control device that meets the conditions
specified in Sec. 60.5412b.
(iii) If routing to a control device, conduct an initial
performance test as required in Sec. 60.5413b within 180 days after
initial startup or by May 7, 2024, whichever date is later, or install
a control device tested under Sec. 60.5413b(d) which meets the
criteria in Sec. 60.5413b(d)(11) and (e), and you must comply with the
continuous compliance requirements of Sec. 60.5415b(f).
(iv) Conduct the initial inspections of the closed vent system and
bypasses, if applicable, as required in Sec. 60.5416b(a) and (b).
(v) Install and operate the continuous parameter monitoring systems
in
[[Page 17087]]
accordance with Sec. 60.5417b(a) through (i), as applicable.
(vi) Maintain the records as required by Sec. 60.5420b(c)(8) and
(c)(10) through (c)(13), as applicable and submit the reports as
required by Sec. 60.5420b(b)(11) through (13), as applicable.
(12) You must tag and repair each identified leak as required in
Sec. 60.5400b(h) or Sec. 60.5400b(i), as applicable.
(13) You must submit the notice required by Sec. 60.5420b(a)(1).
(14) You must submit the initial semiannual report and subsequent
semiannual report as required by Sec. 60.5422b.
(15) You must maintain the records specified by Sec. 60.5421b.
(i) Sweetening unit affected facility. To achieve initial
compliance with the SO2 standard for your sweetening unit
affected facility as required by Sec. 60.5405b, you must comply with
paragraphs (i)(1) through (14) of this section.
(1) You must conduct an initial performance test as required by
Sec. 60.8 and according to the requirements of Sec. 60.5406b.
(2) You must determine the minimum required initial reduction
efficiency of SO2 emissions (Zi) as required by
Sec. 60.5406b(b).
(3) You must determine the emission reduction efficiency (R)
achieved by your sulfur reduction technology using the procedures in
Sec. 60.5406b(c)(1) through (4).
(4) You must demonstrate compliance with the standard as required
by Sec. 60.5405b(a) by comparing the minimum required SO2
emission reduction efficiency (Zi) to the emission reduction
efficiency achieved by the sulfur recovery technology (R), where R must
be greater than or equal to Zi.
(5) You must install, calibrate, maintain, and operate monitoring
devices or perform measurements to determine the accumulation of sulfur
product, the H2S concentration, the average acid gas flow
rate, and the sulfur feed rate in accordance with Sec. 60.5407b(a).
(6) You must determine the required SO2 emissions
reduction efficiency each 24-hour period in accordance with Sec.
60.5407b(a), (d), and (e), as applicable.
(7) You must install, calibrate, maintain, and operate monitoring
devices and continuous emission monitors in accordance with Sec.
60.5407b(b), (f), and (g), if you use an oxidation control system or a
reduction control system followed by an incineration device.
(8) You must continuously operate the incineration device if you
use an oxidation control system, or a reduction control system followed
by an incineration device.
(9) You must install, calibrate, maintain, and operate a continuous
monitoring system to measure the emission rate of reduced sulfur
compounds in accordance with Sec. 60.5407b(c), (f), and (g), if you
use a reduction control system not followed by an incineration device.
(10) You must submit the notification required by Sec.
60.5420b(a)(1).
(11) You must submit the initial annual report required by Sec.
60.5423b(b).
(12) You must submit the performance test report in accordance with
the requirements of Sec. 60.5420b(b)(12).
(13) You must submit the annual excess emissions reports required
by Sec. 60.5423b(d), if applicable.
(14) You must maintain the records required by Sec. 60.5423b(a),
(e) and (f), as applicable.
(j) Storage vessel affected facility. To achieve initial compliance
with the GHG and VOC standards for each storage vessel affected
facility as required by Sec. 60.5395b, you must comply with paragraphs
(j)(1) through (9) of this section. To achieve initial compliance with
the GHG and VOC standards for each storage vessel affected facility
that complies by using a floating roof in accordance with Sec.
60.5395b(b)(2), you must comply with paragraphs (j)(1) and (10) of this
section.
(1) You must determine the potential for methane and VOC emissions
as specified in Sec. 60.5365b(e)(2).
(2) You must reduce methane and VOC emissions by 95.0 percent or
greater according to Sec. 60.5395b(a) and as demonstrated by the
requirements of Sec. 60.5413b or route to a process.
(3) If you use a control device to reduce emissions, you must equip
each storage vessel in the storage vessel affected facility with a
cover that meets the requirements of Sec. 60.5411b(b), install a
closed vent system that meets the requirements of Sec. 60.5411b(a) and
(c) to capture all emissions from the storage vessel affected facility,
and route all emissions to a control device that meets the conditions
specified in Sec. 60.5412b. If you route emissions to a process, you
must equip each storage vessel in the storage vessel affected facility
with a cover that meets the requirements of Sec. 60.5411b(b), install
a closed vent system that meets the requirements of Sec. 60.5411b(a)
and (c) to capture all emissions from the storage vessel affected
facility, and route all emissions to a process.
(4) If you use a control device to reduce emissions, you must
conduct an initial performance test as required in Sec. 60.5413b
within 180 days after initial startup or within 180 days of May 7,
2024, whichever date is later, or install a control device tested under
Sec. 60.5413b(d) which meets the criteria in Sec. 60.5413b(d)(11) and
(e), and you must comply with the continuous compliance requirements of
Sec. 60.5415b(f).
(5) You must conduct the initial inspections of the closed vent
system and bypasses, if applicable, as required in Sec. 60.5416b(a)
and (b).
(6) You must install and operate the continuous parameter
monitoring systems in accordance with Sec. 60.5417b(a) through (i), as
applicable.
(7) You must maintain the records as required by Sec.
60.5420b(c)(8) through (13), as applicable and submit the reports as
required by Sec. 60.5420b(b)(11) through (13), as applicable.
(8) You must submit the initial annual report for your storage
vessel affected facility required by Sec. 60.5420b(b)(1) and (8).
(9) You must maintain the records required for your storage vessel
affected facility, as specified in Sec. 60.5420b(c)(7) for each
storage vessel affected facility.
(10) For each storage vessel affected facility that complies by
using a floating roof, you must meet the requirements of Sec.
60.112b(a)(1) or (2) and the relevant monitoring, inspection,
recordkeeping, and reporting requirements in subpart Kb of this part.
You must submit a statement that you are complying with Sec.
60.112b(d)(a)(1) or (2) in accordance with Sec. 60.5395b(b)(2) with
the initial annual report specified in Sec. 60.5420b(b)(1) and (8).
(k) Fugitive emission components affected facility. To achieve
initial compliance with the GHG and VOC standards for fugitive
emissions components affected facilities as required by Sec. 60.5397b,
you must comply with paragraphs (k)(1) through (5) of this section.
(1) You must develop a fugitive emissions monitoring plan as
required in Sec. 60.5397b(b), (c), and (d).
(2) You must conduct an initial monitoring survey as required in
Sec. 60.5397b(e) and (f).
(3) You must repair each identified source of fugitive emissions
for each affected facility as required in Sec. 60.5397b(h).
(4) You must submit the initial annual report for each fugitive
emissions components affected facility as required in Sec.
60.5420b(b)(1) and (9).
(5) You must maintain the records specified in Sec.
60.5420b(c)(14).
[[Page 17088]]
Sec. 60.5411b What additional requirements must I meet to determine
initial compliance for my covers and closed vent systems?
For each cover or closed vent system at your well, centrifugal
compressor, reciprocating compressor, process controller, pump, storage
vessel, and process unit equipment affected facilities, you must comply
with the applicable requirements of paragraphs (a) through (c) of this
section.
(a) Closed vent system requirements. (1) Reciprocating compressor
rod packing, process controllers, and pumps. You must design the closed
vent system to capture and route all gases, vapors, and fumes to a
process.
(2) Associated gas wells, centrifugal compressors, process
controllers in Alaska, pumps complying with Sec. 60.5393b(b)(1),
storage vessels, and process unit equipment. You must design the closed
vent system to capture and route all gases, vapors, and fumes to a
process or a control device that meets the requirements specified in
Sec. 60.5412b(a) through (d) of this section. For pumps complying with
Sec. 60.5393b(b)(3), you must design the closed vent system to capture
and route all gases, vapors, and fumes to a control device that meets
the requirements specified in Sec. 60.5412b(a) through (d) of this
section.
(3) You must design and operate the closed vent system with no
identifiable emissions as demonstrated by Sec. 60.5416b(a) and (b).
(4) Bypass devices. You must meet the requirements specified in
paragraphs (a)(4)(i) and (ii) of this section if the closed vent system
contains one or more bypass devices that could be used to divert all or
a portion of the gases, vapors, or fumes from entering the control
device or being routed to a process.
(i) Except as provided in paragraph (a)(4)(ii) of this section, you
must comply with either paragraph (a)(4)(i)(A) or (B) of this section
for each bypass device.
(A) You must properly install, calibrate, maintain, and operate a
flow indicator at the inlet to the bypass device. The flow indicator
must be capable of taking periodic readings as specified in Sec.
60.5416b(a)(4)(i) and sound an alarm, or initiate notification via
remote alarm to the nearest field office, when the bypass device is
open such that the stream is being, or could be, diverted away from the
control device or process, and sent to the atmosphere. You must
maintain records of each time the alarm is activated according to Sec.
60.5420b(c)(10).
(B) You must secure the bypass device valve installed at the inlet
to the bypass device in the non-diverting position using a car-seal or
a lock-and-key type configuration.
(ii) Low leg drains, high point bleeds, analyzer vents, open-ended
valves or lines, and safety devices are not subject to the requirements
of paragraph (a)(4)(i) of this section.
(b) Cover requirements for storage vessels and centrifugal
compressors, and reciprocating compressors. (1) The cover and all
openings on the cover (e.g., access hatches, sampling ports, pressure
relief devices and gauge wells) shall form a continuous impermeable
barrier over the entire surface area of the liquid in the storage
vessel or centrifugal compressor wet seal fluid degassing system, or
reciprocating compressor rod packing emissions collection system.
(2) Each cover opening shall be secured in a closed, sealed
position (e.g., covered by a gasketed lid or cap) whenever material is
in the unit on which the cover is installed except during those times
when it is necessary to use an opening as follows:
(i) To add material to, or remove material from the unit (this
includes openings necessary to equalize or balance the internal
pressure of the unit following changes in the level of the material in
the unit);
(ii) To inspect or sample the material in the unit;
(iii) To inspect, maintain, repair, or replace equipment located
inside the unit; or
(iv) To vent liquids, gases, or fumes from the unit through a
closed vent system designed and operated in accordance with the
requirements of paragraph (a) of this section to a control device or to
a process.
(3) Each storage vessel thief hatch shall be equipped, maintained
and operated with a weighted mechanism or equivalent, to ensure that
the lid remains properly seated and sealed under normal operating
conditions, including such times when working, standing/breathing, and
flash emissions may be generated. You must select gasket material for
the hatch based on composition of the fluid in the storage vessel and
weather conditions.
(4) You must design and operate the cover with no identifiable
emissions as demonstrated by Sec. 60.5416b(a) and (b), except when
operated as provided in paragraphs (b)(2)(i) through (iii) of this
section.
(c) Design requirements. (1) You must conduct an assessment that
the closed vent system is of sufficient design and capacity to ensure
that all gases, vapors, and fumes from the affected facility are routed
to the control device or process and that the control device or process
is of sufficient design and capacity to accommodate all emissions from
the affected facility. The assessment must be certified by a qualified
professional engineer or an in-house engineer with expertise on the
design and operation of the closed vent system in accordance with
paragraphs (c)(1)(i) and (ii) of this section.
(i) You must provide the following certification, signed and dated
by a qualified professional engineer or an in-house engineer: ``I
certify that the closed vent system design and capacity assessment was
prepared under my direction or supervision. I further certify that the
closed vent system design and capacity assessment was conducted, and
this report was prepared pursuant to the requirements of subpart OOOOb
of this part. Based on my professional knowledge and experience, and
inquiry of personnel involved in the assessment, the certification
submitted herein is true, accurate, and complete.''
(ii) The assessment shall be prepared under the direction or
supervision of a qualified professional engineer or an in-house
engineer who signs the certification in paragraph (c)(1)(i) of this
section.
Sec. 60.5412b What additional requirements must I meet for
determining initial compliance of my control devices?
You must meet the requirements of paragraphs (a) and (b) of this
section for each control device used to comply with the emissions
standards for your well, centrifugal compressor, reciprocating
compressor, storage vessel, process controller, pump, or process unit
equipment affected facility. If you use a carbon adsorption system as a
control device to meet the requirements of paragraph (a)(2) of this
section, you also must meet the requirements in paragraph (c) of this
section.
(a) Each control device used to meet the emissions reduction
standard in Sec. 60.5377b(f) for your associated gas well at a well
affected facility; Sec. 60.5376b(g) for your well affected facility
gas well that unloads liquids; Sec. 60.5380b(a)(1) for your
centrifugal compressor affected facility; Sec. 60.5385b(d)(2) for your
reciprocating compressor affected facility; Sec. 60.5395b(a)(2) for
your storage vessel affected facility; Sec. 60.5390b(b)(3) for your
process controller affected facility in Alaska; Sec. 60.5393b(b)(1)
for your pumps affected facility; or either Sec. 60.5400b(f) or Sec.
60.5401b(e) for your process equipment affected facility must be
installed according to paragraphs (a)(1) through (3) of this section.
As an alternative to paragraphs (a)(1) through
[[Page 17089]]
(a)(3) of this section, you may install a control device model tested
under Sec. 60.5413b(d), which meets the criteria in Sec.
60.5413b(d)(11) and which meets the initial and continuous compliance
requirements in Sec. 60.5413b(e).
(1) Each enclosed combustion device (e.g., thermal vapor
incinerator, catalytic vapor incinerator, boiler, or process heater)
must be designed and operated in accordance with paragraph (a)(1)(i) of
this section, meet one of the operating limits specified in paragraphs
(a)(1)(ii) through (v) of this section, and except for boilers and
process heaters meeting the requirements of paragraph (a)(1)(iii) of
this section and catalytic vapor incinerators meeting the requirements
of paragraph (a)(1)(v) of this section, meet the operating limits
specified in paragraphs (a)(1)(vi) through (ix) of this section.
Alternatively, the enclosed combustion device must meet the
requirements specified in paragraph (d) of this section.
(i) You must reduce the mass content of methane and VOC in the
gases vented to the device by 95.0 percent by weight or greater or
reduce the concentration of total organic compounds (TOC) in the
exhaust gases at the outlet to the device to a level equal to or less
than 275 ppmv as propane on a wet basis corrected to 3 percent oxygen
as determined in accordance with the requirements of Sec. 60.5413b(b),
with the exceptions noted in Sec. 60.5413b(a).
(ii) For an enclosed combustion device for which you demonstrate
during the performance test conducted under Sec. 60.5413b(b) that
combustion zone temperature is an indicator of destruction efficiency,
you must operate at or above the minimum temperature established during
the most recent performance test. During the performance test conducted
under Sec. 60.5413b(b), you must continuously record the temperature
of the combustion zone and average the temperature for each test run.
The established minimum temperature limit is the average of the test
run averages.
(iii) For an enclosed combustion device which is a boiler or
process heater, you must introduce the vent stream into the flame zone
of the boiler or process heater and introduce the vent stream with the
primary fuel or use the vent stream as the primary fuel.
(iv) For an enclosed combustion device other than those meeting the
operating limits in paragraphs (a)(1)(ii), (iii), and (v) of this
section, if the enclosed combustion device is unassisted or pressure-
assisted, you must maintain the net heating value (NHV) of the gas sent
to the enclosed combustion device at or above the applicable limits
specified in paragraphs (a)(1)(iv)(A) and (B) of this section. If the
enclosed combustion device is steam-assisted or air-assisted, you must
meet the applicable limits specified in paragraphs (a)(1)(iv)(C) and
(D) of this section, as appropriate.
(A) For enclosed combustion devices that do not use assist gas or
pressure-assisted burner tips to promote mixing at the burner tip, 200
British thermal units (Btu) per standard cubic feet (Btu/scf).
(B) For enclosed combustion devices that use pressure-assisted
burner tips to promote mixing at the burner tip, 800 Btu/scf.
(C) For steam-assisted and air-assisted enclosed combustion
devices, maintain the combustion zone NHV (NHVcz) at or
above 270 Btu/scf.
(D) For enclosed combustion devices with perimeter assist air,
maintain the NHV dilution parameter (NHVdil) at or above 22
British thermal units per square foot (Btu/sqft). If the only assist
air provided to the enclosed combustion control device is perimeter
assist air intentionally entrained in lower and/or upper steam at the
burner tip and the effective diameter is 9 inches or greater, you are
only required to comply with the NHVcz limit specified in
paragraph (a)(1)(iv)(C) of this section.
(v) For an enclosed combustion device which is a catalytic vapor
incinerator, you must operate the catalytic vapor incinerator at or
above the minimum temperature of the catalyst bed inlet and at or above
the minimum temperature differential between the catalyst bed inlet and
the catalyst bed outlet established in accordance with Sec.
60.5417b(f) and as determined in your performance test conducted in
accordance with Sec. 60.5413b(b).
(vi) Unless you have an enclosed combustion device with pressure-
assisted burner tips to promote mixing at the burner tip, you must
operate each enclosed combustion device at or below the maximum inlet
gas flow rate established in accordance with Sec. 60.5417b(f) and as
determined in your performance test conducted in accordance with Sec.
60.5413b(b).
(vii) You must operate the combustion control device at or above
the minimum inlet gas flow rate established in accordance with Sec.
60.5417b(f).
(viii) You must install and operate a continuous burning pilot or
combustion flame. An alert must be sent to the nearest control room
whenever the pilot or combustion flame is unlit.
(ix) You must operate the enclosed combustion device with no
visible emissions, except for periods not to exceed a total of 1 minute
during any 15-minute period. A visible emissions test using section 11
of Method 22 of appendix A-7 to this part must be performed at least
once every calendar month, separated by at least 15 days between each
test. The observation period shall be 15 minutes or once the amount of
time visible emissions is present has exceeded 1 minute, whichever time
period is less. Alternatively, you may conduct visible emissions
monitoring according to Sec. 60.5417b(h). Devices failing the visible
emissions test must follow manufacturer's repair instructions, if
available, or best combustion engineering practice as outlined in the
unit inspection and maintenance plan, to return the unit to compliant
operation. All inspection, repair, and maintenance activities for each
unit must be recorded in a maintenance and repair log and must be
available for inspection. Following return to operation from
maintenance or repair activity, each device must pass a Method 22 of
appendix A-7 to this part visual observation as described in this
paragraph or be monitored according to Sec. 60.5417b(h).
(2) Each vapor recovery device (e.g., carbon adsorption system or
condenser) or other non-destructive control device must be designed and
operated to reduce the mass content of methane and VOC in the gases
vented to the device by 95.0 percent by weight or greater as determined
in accordance with the requirements of Sec. 60.5413b(b). As an
alternative to the performance testing requirements of Sec.
60.5413b(b), you may demonstrate initial compliance by conducting a
design analysis for vapor recovery devices according to the
requirements of Sec. 60.5413b(c). For a condenser, you also must
calculate the daily average condenser outlet temperature in accordance
with Sec. 60.5417b(e), and you must determine the condenser efficiency
for the current operating day using the daily average condenser outlet
temperature and the condenser performance curve established in
accordance with Sec. 60.5417b(f)(2). You must determine the average
TOC emission reduction in accordance with Sec. 60.5415b(f)(1)(ix)(D).
For a carbon adsorption system, you also must comply with paragraph (c)
of this section.
(3) Each flare must be designed and operated according to the
requirements specified in paragraphs (a)(3)(i) through (viii) of this
section, as applicable. Alternatively, flares must meet the
requirements specified in paragraph (d) of this section.
[[Page 17090]]
(i) For unassisted flares, you must maintain the NHV of the vent
gas sent to the flare at or above 200 Btu/scf.
(ii) For flares that use pressure-assisted burner tips to promote
mixing at the burner tip, you must maintain the NHV of the vent gas
sent to the flare at or above 800 Btu/scf.
(iii) For steam-assisted and air-assisted flares, you must maintain
the NHVcz at or above 270 Btu/scf.
(iv) For flares with perimeter assist air, you must maintain the
NHVdil at or above 22 Btu/sqft. If the only assist air
provided to the flare is perimeter assist air intentionally entrained
in lower and/or upper steam at the flare tip and the effective diameter
is 9 inches or greater, you are not required to comply with the
NHVdil limit.
(v) For flares other than pressure-assisted flares, you must
demonstrate compliance with the flare tip velocity limits in Sec.
60.18(b) according to Sec. 60.5417b(d)(8)(iv). The maximum flare tip
velocity limits do not apply for pressure-assisted flares.
(vi) You must operate the flare at or above the minimum inlet gas
flow rate. The minimum inlet gas flow rate is established based on
manufacturer recommendations.
(vii) You must operate the flare with no visible emissions, except
for periods not to exceed a total of 1 minute during any 15-minute
period. You must conduct the compliance determination with the visible
emission limits using Method 22 of appendix A-7 to this part, or you
must monitor the flare according to Sec. 60.5417b(h).
(viii) You must install and operate a continuous burning pilot or
combustion flame. An alert must be sent to the nearest control room
whenever the pilot or combustion flame is unlit.
(b) You must operate each control device installed on your well,
centrifugal compressor, reciprocating compressor, storage vessel,
process controller, pump, or process unit equipment affected facility
in accordance with the requirements specified in paragraphs (b)(1) and
(2) of this section.
(1) You must operate each control device used to comply with this
subpart at all times when gases, vapors, and fumes are vented from the
affected facility through the closed vent system to the control device.
You may vent more than one affected facility to a control device used
to comply with this subpart.
(2) For each control device monitored in accordance with the
requirements of Sec. 60.5417b(a) through (i), you must demonstrate
compliance according to the requirements of Sec. 60.5415b(f), as
applicable.
(c) For each carbon adsorption system used as a control device to
meet the requirements of paragraph (a)(2) of this section, you must
comply with the requirements of paragraph (c)(1) of this section. If
the carbon adsorption system is a regenerative-type carbon adsorption
system, you also must comply with the requirements of paragraph (c)(2)
of this section.
(1) You must manage the carbon in accordance with the requirements
specified in paragraphs (c)(1)(i) and (ii) of this section.
(i) Following the initial startup of the control device, you must
replace all carbon in the carbon adsorption system with fresh carbon on
a regular, predetermined time interval that is no longer than the
carbon service life established according to Sec. 60.5413b(c)(2) or
(3). You must maintain records identifying the schedule for replacement
and records of each carbon replacement as required in Sec.
60.5420b(c)(10) and (12).
(ii) You must either regenerate, reactivate, or burn the spent
carbon removed from the carbon adsorption system in one of the units
specified in paragraphs (c)(1)(ii)(A) through (F) of this section.
(A) Regenerate or reactivate the spent carbon in a unit for which
you have been issued a final permit under 40 CFR part 270 that
implements the requirements of 40 CFR part 264, subpart X.
(B) Regenerate or reactivate the spent carbon in a unit equipped
with an operating organic air emissions control in accordance with an
emissions standard for VOC under another subpart in 40 CFR part 63 or
this part.
(C) Burn the spent carbon in a hazardous waste incinerator for
which the owner or operator complies with the requirements of 40 CFR
part 63, subpart EEE, and has submitted a Notification of Compliance
under 40 CFR 63.1207(j).
(D) Burn the spent carbon in a hazardous waste boiler or industrial
furnace for which the owner or operator complies with the requirements
of 40 CFR part 63, subpart EEE, and has submitted a Notification of
Compliance under 40 CFR 63.1207(j).
(E) Burn the spent carbon in an industrial furnace for which you
have been issued a final permit under 40 CFR part 270 that implements
the requirements of 40 CFR part 266, subpart H.
(F) Burn the spent carbon in an industrial furnace that you have
designed and operated in accordance with the interim status
requirements of 40 CFR part 266, subpart H.
(2) You must comply with the requirements of paragraph (c)(2)(i)
through (iii) of this section for each regenerative-type carbon
adsorption system.
(i) You must measure and record the average total regeneration
stream mass flow or volumetric flow during each carbon bed regeneration
cycle to demonstrate compliance with the total regeneration stream flow
established in accordance with Sec. 60.5413b(c)(2).
(ii) You must check the mechanical connections for leakage at least
every month, and you must perform a visual inspection at least every 3
months of all components of the flow continuous parameter monitoring
system for physical and operational integrity and all electrical
connections for oxidation and galvanic corrosion, if your continuous
parameter monitoring system is not equipped with a redundant flow
sensor.
(iii) You must measure and record the average carbon bed
temperature for the duration of the carbon bed steaming cycle and
measure the actual carbon bed temperature after regeneration and within
15 minutes of completing the cooling cycle. You must maintain the
average carbon bed temperature above the temperature limit in
established accordance with Sec. 60.5413b(c)(2) during the carbon bed
steaming cycle and below the carbon bed temperature established in in
accordance with Sec. 60.5413b(c)(2) after the regeneration cycle.
(d) To demonstrate that a flare or enclosed combustion device
reduces methane and VOC in the gases vented to the device by 95.0
percent by weight or greater, as outlined in Sec. 60.8(b), you may
submit a request for an alternative test method. At a minimum, the
request must follow the requirements outlined in paragraphs (d)(1)
through (5) of this section.
(1) The alternative method must be capable of demonstrating
continuous compliance with a combustion efficiency of 95.0 percent or
greater or it must be capable of demonstrating continuous compliance
with the following metrics:
(i) NHVcz of 270 Btu/scf or greater.
(ii) NHVdil of 22 Btu/sqft or greater, if the
alternative test method will be used for enclosed combustion devices or
flares with perimeter assist air.
(2) The alternative method must be validated according to Method
301 in appendix A of 40 CFR part 63 for each type of control device
covered by the alternative test method (e.g., air-assisted flare,
unassisted enclosed combustion
[[Page 17091]]
device) or the alternative test method must contain performance-based
procedures and indicators to ensure self-validation.
(3) At a minimum the alternative test method must provide a reading
for each successive 15-minute period.
(4) The alternative test method must be capable of documenting
periods when the enclosed combustion device or flare operates with
visible emissions. If the alternative test method cannot identify
periods of visible emissions, you must conduct the inspections required
by Sec. 5417b(d)(8)(v).
(5) If the alternative test method demonstrates compliance with the
metrics specified in paragraphs (d)(1)(i) and (ii) of this section
instead of demonstrating continuous compliance with 95.0 percent or
greater combustion efficiency, you must still install the pilot or
combustion flame monitoring system required by Sec. 60.5417b(d)(8)(i).
If the alternative test method demonstrates continuous compliance with
a combustion efficiency of 95.0 percent or greater, the requirement in
Sec. 60.5417b(d)(8)(i) no longer applies.
Sec. 60.5413b What are the performance testing procedures for control
devices?
This section applies to the performance testing of control devices
used to demonstrate compliance with the emissions standards for your
well, centrifugal compressor, reciprocating compressor, storage vessel,
process controller, pump affected facilities complying with Sec.
60.5393b(b)(1), or process unit equipment affected facility. You must
demonstrate that a control device achieves the performance requirements
of Sec. 60.5412b(a)(1) or (2) using the performance test methods and
procedures specified in this section. For condensers and carbon
adsorbers, you may use a design analysis as specified in paragraph (c)
of this section in lieu of complying with paragraph (b) of this
section. In addition, this section contains the requirements for
enclosed combustion device performance tests conducted by the
manufacturer applicable to well, centrifugal compressor, reciprocating
compressor, storage vessel, process controller, pump affected
facilities complying with Sec. 60.5393b(b)(1), or process unit
equipment affected facilities.
(a) Performance test exemptions. You are exempt from the
requirements to conduct initial and periodic performance tests and
design analyses if you use any of the control devices described in
paragraphs (a)(1) through (6) of this section. You are exempt from the
requirements to conduct an initial performance test if you use a
control device described in paragraph (a)(7) of this section.
(1) A flare that is designed and operated in accordance with the
requirements in Sec. 60.5412b(a)(3). You must conduct the compliance
determination using Method 22 of appendix A-7 to this part to determine
visible emissions or monitor the flare according to Sec. 60.5417b(h).
The net heating value of the vent gas must be determined according to
Sec. 60.5417b(d)(8)(ii).
(2) A boiler or process heater with a design heat input capacity of
44 megawatts or greater.
(3) A boiler or process heater into which the vent stream is
introduced with the primary fuel or is used as the primary fuel.
(4) A boiler or process heater burning hazardous waste for which
you have been issued a final permit under 40 CFR part 270 and comply
with the requirements of 40 CFR part 266, subpart H; you have certified
compliance with the interim status requirements of 40 CFR part 266,
subpart H; you have submitted a Notification of Compliance under 40 CFR
63.1207(j) and comply with the requirements of 40 CFR part 63, subpart
EEE; or you comply with 40 CFR part 63, subpart EEE and will submit a
Notification of Compliance under 40 CFR 63.1207(j) by the date
specified in Sec. 60.5420b(b)(12) for submitting the initial
performance test report.
(5) A hazardous waste incinerator for which you have submitted a
Notification of Compliance under 40 CFR 63.1207(j), or for which you
will submit a Notification of Compliance under 40 CFR 63.1207(j) by the
date specified in Sec. 60.5420b(b)(12) for submitting the initial
performance test report, and you comply with the requirements of 40 CFR
part 63, subpart EEE.
(6) A control device for which performance test is waived in
accordance with Sec. 60.8(b).
(7) A control device whose model can be demonstrated to meet the
performance requirements of Sec. 60.5412b(a)(1)(i) through a
performance test conducted by the manufacturer, as specified in
paragraph (d) of this section.
(b) Test methods and procedures. You must use the test methods and
procedures specified in paragraphs (b)(1) through (4) of this section,
as applicable, for each performance test conducted to demonstrate that
a control device meets the requirements of Sec. 60.5412b(a)(1) or (2).
You must conduct the initial and periodic performance tests according
to the schedule specified in paragraph (b)(5) of this section. Each
performance test must consist of a minimum of 3 test runs. Each run
must be at least 1 hour long.
(1) You must use Method 1 or 1A of appendix A-1 to this part, as
appropriate, to select the sampling sites. Any references to
particulate mentioned in Methods 1 and 1A do not apply to this section.
(i) Sampling sites must be located at the inlet of the first
control device and at the outlet of the final control device to
determine compliance with a control device percent reduction
requirement.
(ii) The sampling site must be located at the outlet of the
combustion device to determine compliance with a TOC exhaust gas
concentration limit.
(2) You must determine the gas volumetric flow rate using Method 2,
2A, 2C, or 2D of appendix A-2 to this part, as appropriate.
(3) To determine compliance with the control device percent
reduction performance requirement in Sec. 60.5412b(a)(1)(i) or (a)(2),
you must use Method 25A of appendix A-7 to this part. You must use
Method 4 of appendix A-3 to this part to convert the Method 25A results
to a dry basis. You must use the procedures in paragraphs (b)(3)(i)
through (iii) of this section to calculate percent reduction
efficiency.
(i) You must compute the mass rate of TOC using the following
equations:
[GRAPHIC] [TIFF OMITTED] TR08MR24.006
[[Page 17092]]
Where:
Ei, Eo = Mass rate of TOC at the inlet and
outlet of the control device, respectively, dry basis, kilograms per
hour.
K2 = Constant, 2.494 x 10-6 (parts per
million) (gram-mole per standard cubic meter) (kilogram/gram)
(minute/hour), where standard temperature (gram-mole per standard
cubic meter) is 20 degrees Celsius.
Ci, Co = Concentration of TOC, as propane, of
the gas stream as measured by Method 25A of appendix A-7 to this
part at the inlet and outlet of the control device, respectively,
dry basis, parts per million by volume.
Mp = Molecular weight of propane, 44.1 gram/gram-mole.
Qi, Qo = Flow rate of gas stream at the inlet
and outlet of the control device, respectively, dry standard cubic
meter per minute.
(ii) You must calculate the percent reduction in TOC as follows:
[GRAPHIC] [TIFF OMITTED] TR08MR24.007
Where:
Rcd = Control efficiency of control device, percent.
Ei, = Mass rate of TOC at the inlet to the control device
as calculated under paragraph (b)(3)(i) of this section, kilograms
per hour.
Eo = Mass rate of TOC at the outlet of the control
device, as calculated under paragraph (b)(3)(i) of this section,
kilograms per hour.
(iii) If the vent stream entering a boiler or process heater with a
design capacity less than 44 megawatts is introduced with the
combustion air or as a secondary fuel, you must determine the weight-
percent reduction of total TOC across the device by comparing the TOC
in all combusted vent streams and primary and secondary fuels with the
TOC exiting the device, respectively.
(4) You must use Method 25A of appendix A-7 to this part to measure
TOC, as propane, to determine compliance with the TOC exhaust gas
concentration limit specified in Sec. 60.5412b(a)(1)(i). You must
determine the concentration in parts per million by volume on a wet
basis and correct it to 3 percent oxygen. You must use the emission
rate correction factor for excess air, integrated sampling and analysis
procedures of Method 3A or 3B of appendix A-2 to this part, ASTM D6522-
20, or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion only) (both
incorporated by reference, see Sec. 60.17) to determine the oxygen
concentration. The samples must be taken during the same time that the
samples are taken for determining TOC concentration. You must correct
the TOC concentration for percent oxygen as follows:
[GRAPHIC] [TIFF OMITTED] TR08MR24.008
Where:
Cc = TOC concentration, as propane, corrected to 3
percent oxygen, parts per million by volume on a wet basis.
Cm = TOC concentration, as propane, parts per million by
volume on a wet basis.
%O2m = Concentration of oxygen, percent by volume as
measured, wet.
(5) You must conduct performance tests according to the schedule
specified in paragraphs (b)(5)(i) through (iii) of this section.
(i) You must conduct an initial performance test within 180 days
after initial startup for your affected facility. You must submit the
performance test results as required in Sec. 60.5420b(b)(12).
(ii) You must conduct periodic performance tests for all control
devices required to conduct initial performance tests. You must conduct
the first periodic performance test no later than 60 months after the
initial performance test required in paragraph (b)(5)(i) of this
section. You must conduct subsequent periodic performance tests at
intervals no longer than 60 months following the previous periodic
performance test or whenever you desire to establish a new operating
limit. If a control device is not operational at the time a performance
test is due, you must conduct the performance test no later than 30
calendar days after returning the control device to service. You must
submit the periodic performance test results as specified in Sec.
60.5420b(b)(12).
(iii) If the initial performance test was conducted by the
manufacturer under paragraph (d) of this section, you must conduct the
first periodic performance test no later than 60 months after initial
installation and startup of the control device. You must conduct
subsequent periodic performance tests at intervals no longer than 60
months following the previous periodic performance test. If a control
device is not operational at the time a performance test is due, you
must conduct the performance test no later than 30 calendar days after
returning the control device to service. You must submit the periodic
performance test results as specified in Sec. 60.5420b(b)(12).
(c) Control device design analysis to meet the requirements of
Sec. 60.5412b(a)(2). (1) For a condenser, the design analysis must
include an analysis of the vent stream composition, constituent
concentrations, flow rate, relative humidity, and temperature and must
establish the design outlet organic compound concentration level,
design average temperature of the condenser exhaust vent stream and the
design average temperatures of the coolant fluid at the condenser inlet
and outlet.
(2) For a regenerable carbon adsorption system, the design analysis
shall include the vent stream composition, constituent concentrations,
flow rate, relative humidity and temperature and shall establish the
design exhaust vent stream organic compound concentration level,
adsorption cycle time, number and capacity of carbon beds, type and
working capacity of activated carbon used for the carbon beds, design
total regeneration stream flow over the period of each complete carbon
bed
[[Page 17093]]
regeneration cycle, design carbon bed temperature after regeneration,
design carbon bed regeneration time and design service life of the
carbon.
(3) For a nonregenerable carbon adsorption system, such as a carbon
canister, the design analysis shall include the vent stream
composition, constituent concentrations, flow rate, relative humidity
and temperature and shall establish the design exhaust vent stream
organic compound concentration level, capacity of the carbon bed, type
and working capacity of activated carbon used for the carbon bed and
design carbon replacement interval based on the total carbon working
capacity of the control device and source operating schedule. In
addition, these systems shall incorporate dual carbon canisters in case
of emission breakthrough occurring in one canister.
(4) If you and the Administrator do not agree on a demonstration of
control device performance using a design analysis, then you must
perform a performance test in accordance with the requirements of
paragraph (b) of this section to resolve the disagreement. The
Administrator may choose to have an authorized representative observe
the performance test.
(d) Performance testing for combustion control devices--
manufacturers' performance test. (1) This paragraph (d) applies to the
performance testing of a combustion control device conducted by the
device manufacturer. The manufacturer must demonstrate that a specific
model of control device achieves the performance requirements in
paragraph (d)(11) of this section by conducting a performance test as
specified in paragraphs (d)(2) through (10) of this section. You must
submit a test report for each combustion control device in accordance
with the requirements in paragraph (d)(12) of this section.
(2) Performance testing must consist of three 1-hour (or longer)
test runs for each of the four firing rate settings specified in
paragraphs (d)(2)(i) through (iv) of this section, making a total of 12
test runs per test. Propene (propylene) gas must be used for the
testing fuel. All fuel analyses must be performed by an independent
third-party laboratory (not affiliated with the control device
manufacturer or fuel supplier).
(i) 90-100 percent of maximum design rate (fixed rate).
(ii) 70-100-70 percent (ramp up, ramp down). Begin the test at 70
percent of the maximum design rate. During the first 5 minutes,
incrementally ramp the firing rate to 100 percent of the maximum design
rate. Hold at 100 percent for 5 minutes. In the 10- to 15-minute time
range, incrementally ramp back down to 70 percent of the maximum design
rate. Repeat three more times for a total of 60 minutes of sampling.
(iii) 30-70-30 percent (ramp up, ramp down). Begin the test at 30
percent of the maximum design rate. During the first 5 minutes,
incrementally ramp the firing rate to 70 percent of the maximum design
rate. Hold at 70 percent for 5 minutes. In the 10- to 15-minute time
range, incrementally ramp back down to 30 percent of the maximum design
rate. Repeat three more times for a total of 60 minutes of sampling.
(iv) 0-30-0 percent (ramp up, ramp down). Begin the test at the
minimum firing rate. During the first 5 minutes, incrementally ramp the
firing rate to 30 percent of the maximum design rate. Hold at 30
percent for 5 minutes. In the 10- to 15-minute time range,
incrementally ramp back down to the minimum firing rate. Repeat three
more times for a total of 60 minutes of sampling.
(3) All models employing multiple enclosures must be tested
simultaneously and with all burners operational. Results must be
reported for each enclosure individually and for the average of the
emissions from all interconnected combustion enclosures/chambers.
Control device operating data must be collected continuously throughout
the performance test using an electronic Data Acquisition System. A
graphic presentation or strip chart of the control device operating
data and emissions test data must be included in the test report in
accordance with paragraph (d)(12) of this section. Inlet fuel meter
data may be manually recorded provided that all inlet fuel data
readings are included in the final report.
(4) Inlet testing must be conducted as specified in paragraphs
(d)(4)(i) and (ii) of this section.
(i) The inlet gas flow metering system must be located in
accordance with Method 2A of appendix A-1 of this part (or other
approved procedure) to measure inlet gas flow rate at the control
device inlet location. You must position the fitting for filling fuel
sample containers a minimum of eight pipe diameters upstream of any
inlet gas flow monitoring meter.
(ii) Inlet flow rate must be determined using Method 2A to appendix
A-1 of this part. Record the start and stop reading for each 60-minute
THC test. Record the gas pressure and temperature at 5-minute intervals
throughout each 60-minute test.
(5) Inlet gas sampling must be conducted as specified in paragraphs
(d)(5)(i) and (ii) of this section.
(i) At the inlet gas sampling location, securely connect a fused
silica-coated stainless steel evacuated canister fitted with a flow
controller sufficient to fill the canister over a 3-hour period.
Filling must be conducted as specified in paragraphs (d)(5)(i)(A)
through (C) of this section.
(A) Open the canister sampling valve at the beginning of each test
run and close the canister at the end of each test run.
(B) Fill one canister across the three test runs such that one
composite fuel sample exists for each test condition.
(C) Label the canisters individually and record sample information
on a chain of custody form.
(ii) Analyze each inlet gas sample using the methods in paragraphs
(d)(5)(ii)(A) through (C) of this section. You must include the results
in the test report required by paragraph (d)(12) of this section.
(A) Hydrocarbon compounds containing between one and five atoms of
carbon plus benzene using ASTM D1945-03(R2010) (incorporated by
reference, see Sec. 60.17).
(B) Hydrogen (H2), carbon monoxide (CO), carbon dioxide
(CO2), nitrogen (N2), oxygen (O2)
using ASTM D1945-03(R2010) (incorporated by reference, see Sec.
60.17).
(C) Higher heating value using ASTM D3588-98(R2003) or ASTM D4891-
89(R2006) (both incorporated by reference, see Sec. 60.17).
(6) Outlet testing must be conducted in accordance with the
criteria in paragraphs (d)(6)(i) through (v) of this section.
(i) Sample and flow rate must be measured in accordance with
paragraphs (d)(6)(i)(A) and (B) of this section.
(A) The outlet sampling location must be a minimum of four
equivalent stack diameters downstream from the highest peak flame or
any other flow disturbance, and a minimum of one equivalent stack
diameter upstream of the exit or any other flow disturbance. A minimum
of two sample ports must be used.
(B) Flow rate must be measured using Method 1 of appendix A-1 to
this part for determining flow measurement traverse point location, and
Method 2 of appendix A-1 to this part for measuring duct velocity. If
low flow conditions are encountered (i.e., velocity pressure
differentials less than 0.05 inches of water) during the performance
test, a more sensitive manometer must be used to obtain an accurate
flow profile.
(ii) Molecular weight and excess air must be determined as
specified in paragraph (d)(7) of this section.
[[Page 17094]]
(iii) Carbon monoxide must be determined as specified in paragraph
(d)(8) of this section.
(iv) THC must be determined as specified in paragraph (d)(9) of
this section.
(v) Visible emissions must be determined as specified in paragraph
(d)(10) of this section.
(7) Molecular weight and excess air determination must be performed
as specified in paragraphs (d)(7)(i) through (iii) of this section.
(i) An integrated bag sample must be collected during the moisture
test required by Method 4 of appendix A-3 to this part following the
procedure specified in (d)(7)(i)(A) and (B) of this section. Analyze
the bag sample using a gas chromatograph-thermal conductivity detector
(GC-TCD) analysis meeting the criteria in paragraphs (d)(7)(i)(C) and
(D) of this section.
(A) Collect the integrated sample throughout the entire test and
collect representative volumes from each traverse location.
(B) Purge the sampling line with stack gas before opening the valve
and beginning to fill the bag. Clearly label each bag and record sample
information on a chain of custody form.
(C) The bag contents must be vigorously mixed prior to the gas
chromatograph analysis.
(D) The GC-TCD calibration procedure in Method 3C of appendix A-2
to this part must be modified as follows: For the initial calibration,
triplicate injections of any single concentration must agree within 5
percent of their mean to be valid. The calibration response factor for
a single concentration re-check must be within 10 percent of the
original calibration response factor for that concentration. If this
criterion is not met, repeat the initial calibration using at least
three concentration levels.
(ii) Calculate and report the molecular weight of oxygen, carbon
dioxide, methane and nitrogen in the integrated bag sample and include
in the test report specified in paragraph (d)(12) of this section.
Moisture must be determined using Method 4 of appendix A-3 to this
part. Traverse both ports with the sampling train required by Method 4
of appendix A-3 to this part during each test run. Ambient air must not
be introduced into the integrated bag sample required by Method 3C of
appendix A-2 to this part during the port change.
(iii) Excess air must be determined using resultant data from the
Method 3C tests and Method 3B of appendix A-2 to this part, equation
3B-1 in Method 3B, or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion
only) (incorporated by reference, see Sec. 60.17).
(8) Carbon monoxide must be determined using Method 10 of appendix
A-4 to this part. Run the test simultaneously with Method 25A of
appendix A-7 to this part using the same sampling points. An instrument
range of 0-10 parts per million by volume-dry (ppmvd) is recommended.
(9) Total hydrocarbon determination must be performed as specified
by in paragraphs (d)(9)(i) through (vii) of this section.
(i) Conduct THC sampling using Method 25A of appendix A-7 to this
part, except that the option for locating the probe in the center 10
percent of the stack is not allowed. The THC probe must be traversed to
16.7 percent, 50 percent, and 83.3 percent of the stack diameter during
each test run.
(ii) A valid test must consist of three Method 25A tests, each no
less than 60 minutes in duration.
(iii) A 0 to 10 parts per million by volume-wet (ppmvw) (as
propane) measurement range is preferred; as an alternative a 0 to 30
ppmvw (as propane) measurement range may be used.
(iv) Calibration gases must be propane in air and be certified
through EPA-600/R-12/531--``EPA Traceability Protocol for Assay and
Certification of Gaseous Calibration Standards,'' (incorporated by
reference, see Sec. 60.17).
(v) THC measurements must be reported in terms of ppmvw as propane.
(vi) THC results must be corrected to 3 percent CO2, as
measured by Method 3C of appendix A-2 to this part. You must use the
following equation for this diluent concentration correction:
[GRAPHIC] [TIFF OMITTED] TR08MR24.009
Where:
Cmeas = The measured concentration of the pollutant.
CO2meas = The measured concentration of the
CO2 diluent.
3 = The corrected reference concentration of CO2 diluent.
Ccorr = The corrected concentration of the pollutant.
(vii) Subtraction of methane or ethane from the THC data is not
allowed in determining results.
(10) Visible emissions must be determined using Method 22 of
appendix A-7 to this part. The test must be performed continuously
during each test run. A digital color photograph of the exhaust point,
taken from the position of the observer and annotated with date and
time, must be taken once per test run and the 12 photos included in the
test report specified in paragraph (d)(12) of this section.
(11)(i) The control device model tested must meet the criteria in
paragraphs (d)(11)(i)(A) through (D) of this section. These criteria
must be reported in the test report required by paragraph (d)(12) of
this section.
(A) Results from Method 22 of appendix A-7 to this part determined
under paragraph (d)(10) of this section with no indication of visible
emissions.
(B) Average results from Method 25A of appendix A-7 to this part
determined under paragraph (d)(9) of this section equal to or less than
10.0 ppmvw THC as propane corrected to 3.0 percent CO2.
(C) Average CO emissions determined under paragraph (d)(8) of this
section equal to or less than 10 parts ppmvd, corrected to 3.0 percent
CO2.
(D) Excess air determined under paragraph (d)(7) of this section
equal to or greater than 150 percent.
(ii) The manufacturer must determine a minimum inlet gas flow rate
above which each control device model must be operated to achieve the
criteria in paragraph (d)(11)(iii) of this section. The manufacturer
must determine a maximum inlet gas flow rate which must not be exceeded
for each control device model to achieve the criteria in paragraph
(d)(11)(iii) of this section. The minimum and maximum inlet gas flow
rate must be included in the test report required by paragraph (d)(12)
of this section.
(iii) A manufacturer must demonstrate a destruction efficiency of
at least 95.0 percent for THC, as propane. A control device model that
demonstrates a
[[Page 17095]]
destruction efficiency of 95.0 percent for THC, as propane, will meet
the control requirement for 95.0 percent destruction of VOC and methane
required under this subpart.
(12) The owner or operator of a combustion control device model
tested under this paragraph (d)(12) must submit the information listed
in paragraphs (d)(12)(i) through (vi) of this section for each test run
in the test report required by this section in accordance with Sec.
60.5420b(b)(13). Owners or operators who claim that any of the
performance test information being submitted is confidential business
information (CBI) must submit a complete file including information
claimed to be CBI to the OAQPS CBI office. The preferred method to
receive CBI is for it to be transmitted electronically using email
attachments, File Transfer Protocol, or other online file sharing
services. Electronic submissions must be transmitted directly to the
OAQPS CBI Office at the email address [email protected] and should
include clear CBI markings and be flagged to the attention of the
Leader, Measurement Policy Group. If assistance is needed with
submitting large electronic files that exceed the file size limit for
email attachments, and if you do not have your own file sharing
service, please email [email protected] to request a file transfer link.
If you cannot transmit the file electronically, you may send CBI
information through the postal service to the following address: U.S.
EPA, Attn: OAQPS Document Control Officer and Measurement Policy Group
Leader, Mail Drop: C404-02, 109 T.W. Alexander Drive, P.O. Box 12055,
RTP, North Carolina 27711. The mailed CBI material should be double
wrapped and clearly marked. Any CBI markings should not show through
the outer envelope. The same file with the CBI omitted must be
submitted to [email protected].
(i) A full schematic of the control device and dimensions of the
device components.
(ii) The maximum net heating value of the device.
(iii) The test fuel gas flow range (in both mass and volume).
Include the minimum and maximum allowable inlet gas flow rate.
(iv) The air/stream injection/assist ranges, if used.
(v) The test conditions listed in paragraphs (d)(12)(v)(A) through
(O) of this section, as applicable for the tested model.
(A) Fuel gas delivery pressure and temperature.
(B) Fuel gas moisture range.
(C) Purge gas usage range.
(D) Condensate (liquid fuel) separation range.
(E) Combustion zone temperature range. This is required for all
devices that measure this parameter.
(F) Excess air range.
(G) Flame arrestor(s).
(H) Burner manifold.
(I) Continuous pilot flame indicator.
(J) Pilot flame design fuel and calculated or measured fuel usage.
(K) Tip velocity range.
(L) Momentum flux ratio.
(M) Exit temperature range.
(N) Exit flow rate.
(O) Wind velocity and direction.
(vi) The test report must include all calibration quality
assurance/quality control data, calibration gas values, gas cylinder
certification, strip charts, or other graphic presentations of the data
annotated with test times and calibration values.
(e) Initial and continuous compliance for combustion control
devices tested by the manufacturer in accordance with paragraph (d) of
this section. This paragraph (e) applies to the demonstration of
compliance for a combustion control device tested under the provisions
in paragraph (d) of this section. Owners or operators must demonstrate
that a control device achieves the performance criteria in paragraph
(d)(11) of this section by installing a device tested under paragraph
(d) of this section, complying with the criteria specified in
paragraphs (e)(1) through (10) of this section, maintaining the records
specified in Sec. 60.5420b(c)(11) and submitting the report specified
in Sec. 60.5420b(b)(11)(v) and (13).
(1) The inlet gas flow rate must be equal to or greater than the
minimum inlet gas flow rate and equal to or less than the maximum inlet
gas flow rate specified by the manufacturer.
(2) A pilot or combustion flame must be present at all times of
operation. An alert must be sent to the nearest control room whenever
the pilot or combustion flame is unlit.
(3) Devices must be operated with no visible emissions, except for
periods not to exceed a total of 1 minute during any 15-minute period.
A visible emissions test conducted according to section 11 of Method 22
of appendix A-7 to this part must be performed at least once every
calendar month, separated by at least 15 days between each test. The
observation period shall be 15 minutes or once the amount of time
visible emissions is present has exceeded 1 minute, whichever time
period is less. Alternatively, you may conduct visible emissions
monitoring according to Sec. 60.5417b(h).
(4) Devices failing the visible emissions test must follow
manufacturer's repair instructions, if available, or best combustion
engineering practice as outlined in the unit inspection and maintenance
plan, to return the unit to compliant operation. All repairs and
maintenance activities for each unit must be recorded in a maintenance
and repair log and must be available for inspection.
(5) Following return to operation from maintenance or repair
activity, each device must pass a visual observation according to
Method 22 of appendix A-7 to this part as described in paragraph (e)(3)
of this section or be monitored according to Sec. 60.5417b(h).
(6) If the owner or operator operates a combustion control device
model tested under this section, an electronic copy of the performance
test results required by this section shall be submitted via email to
[email protected] unless the test results for that model of
combustion control device are posted at the following website: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.
(7) Ensure that each enclosed combustion device is maintained in a
leak free condition.
(8) Operate each control device following the manufacturer's
written operating instructions, procedures and maintenance schedule to
ensure good air pollution control practices for minimizing emissions.
(9) Install and operate the continuous parameter monitoring systems
in accordance with Sec. 60.5417b(a) and (c) through (i).
(10) Comply with the applicable NHV limit specified in Sec.
60.5412b(a)(1)(iv).
Sec. 60.5415b How do I demonstrate continuous compliance with the
standards for each of my affected facilities?
(a) Well completion standards for well affected facility. For each
well completion operation at your well affected facility, you must
demonstrate continuous compliance with the requirements of Sec.
60.5375b by submitting the annual report required by Sec.
60.5420b(b)(1) and (2) and maintaining the records for each completion
operation specified in Sec. 60.5420b(c)(1).
(b) Gas well liquids unloading standards for well affected
facility. For each well liquids unloading operation at your well
affected facility, you must demonstrate continuous compliance with the
requirements of Sec. 60.5376b by submitting the annual report
information specified in Sec. 60.5420b(b)(1) and (3) and maintaining
the records for each well liquids
[[Page 17096]]
unloading event specified in Sec. 60.5420b(c)(2). For each gas well
liquids unloading well affected facility that complies with the
requirements of Sec. 60.5376b(g), you must route emissions to a
control device through a closed vent system and continuously comply
with the closed vent requirements of Sec. 60.5416b. You also must
comply with the requirements specified in paragraph (f) of this section
and maintain the records in Sec. 60.5420b(c)(8), (10) and (12).
(c) Associated gas well standards for well affected facility. For
each associated gas well, you must demonstrate continuous compliance
with the requirements of Sec. 60.5377b by submitting the reports
required by Sec. 60.5420b(b)(1) and (4) and maintaining the records
specified in Sec. 60.5420b(c)(3). For each associated gas well that
complies with the requirements of Sec. 60.5377b(d) or (f), you must
route emissions to a control device through a closed vent system and
continuously comply with the closed vent requirements of Sec.
60.5416b. You also must comply with the requirements specified in
paragraph (f) of this section and maintain the records in Sec.
60.5420b(c)(8), (10) and (12).
(d) Centrifugal compressor affected facility. For each wet seal
centrifugal compressor affected facility complying with Sec.
60.5380b(a)(1) and (2), or with Sec. 60.5380b(a)(3) by routing
emissions to a control device or to a process, you must demonstrate
continuous compliance according to paragraph (d)(1) and paragraphs
(d)(3) and (4) of this section. For each self-contained wet seal
centrifugal compressor complying with the requirements in Sec.
60.5380b(a)(4), you must demonstrate continuous compliance according to
paragraphs (d)(2) through (4) of this section. For each centrifugal
compressor on the Alaska North Slope equipped with sour seal oil
separator and capture system, complying with the requirements of Sec.
60.5380b(a)(5), you must demonstrate continuous compliance according to
paragraphs (d)(2) through (4) of this section. For each dry seal
centrifugal compressor complying with the requirements in Sec.
60.5380b(a)(6), you must demonstrate continuous compliance according to
paragraphs (d)(2) through (4) of this section.
(1) For each wet seal centrifugal compressor affected facility
complying by routing emissions to a control device or to a process, you
must operate the wet seal emissions collection system to route
emissions to a control device or a process through a closed vent system
and continuously comply with the cover and closed vent requirements of
Sec. 60.5416b. If you comply with Sec. 60.5380b(a)(2) by using a
control device, you also must comply with the requirements in paragraph
(f) of this section.
(2) You must maintain volumetric flow rate at or below the flow
rates specified in Sec. 60.5380b(a)(5) for you centrifugal compressor
and you must conduct the required volumetric flow rate measurement of
your self-contained wet seal centrifugal compressor, Alaska North Slope
centrifugal compressor equipped with sour seal oil separator and
capture system, or dry seal centrifugal compressor in accordance with
Sec. 60.5380b(a)(6) on or before 8,760 hours of operation after your
last volumetric flow rate measurement which demonstrates compliance
with the volumetric flow rate specified in Sec. 60.5380b(a)(5) for you
centrifugal compressor.
(3) You must submit the annual reports as required in Sec.
60.5420b(b)(1), (5), and (11)(i) through (iv), as applicable.
(4) You must maintain records as required in Sec. 60.5420b(c)(4),
(8) through (10), and (12), as applicable.
(e) Pump affected facility. To demonstrate continuous compliance
with the GHG and VOC standards for your pump affected facility as
required by Sec. 60.5393b, you must comply with paragraphs (e)(1)
through (3) of this section.
(1) For pump affected facilities complying with the requirements of
Sec. 60.5393b(a) by routing emissions to a process, and for pump
affected facilities complying with the requirements of Sec.
60.5393b(b)(2), or (3), you must continuously comply with the closed
vent requirements of Sec. 60.5416b. If you comply with Sec.
60.5393b(b)(3), you also must comply with the requirements in paragraph
(f) of this section.
(2) You must submit the annual reports for your pump affected
facility as required in Sec. 60.5420b(b)(1), (10), and (11)(i) through
(iv), as applicable.
(3) You must maintain the records for your pump affected facility
as specified in Sec. 60.5420b(c)(8), (10), (12), and (15), as
applicable.
(f) Additional continuous compliance requirements for well,
centrifugal compressor, reciprocating compressor, process controllers
in Alaska, storage vessel, process unit equipment, or pump affected
facilities. For each associated gas well, each gas well that conducts
liquids unloading, each centrifugal compressor affected facility, each
reciprocating compressor affected facility, each process controller
affected facility in Alaska, each storage vessel affected facility,
each process unit equipment affected facility, and each pump affected
facility referenced to this paragraph from either paragraph (b), (c),
(d)(1), (e)(1), (g), (h)(2)(iv), (i) or (j) of this section, you must
also install monitoring systems as specified in Sec. 60.5417b,
demonstrate continuous compliance according to paragraph (f)(1) of this
section, maintain the records in paragraph (f)(2) of this section, and
comply with the reporting requirements specified in paragraph (f)(3) of
this section.
(1) You must demonstrate continuous compliance with the control
device performance requirements of Sec. 60.5412b(a) using the
procedures specified in paragraphs (f)(1)(i) through (viii) of this
section and conducting the monitoring as required by Sec. 60.5417b. If
you use a condenser as the control device to achieve the requirements
specified in Sec. 60.5412b(a)(2), you may demonstrate compliance
according to paragraph (f)(1)(ix) of this section. You may switch
between compliance with paragraphs (f)(1)(i) through (viii) of this
section and compliance with paragraph (f)(1)(ix) of this section only
after at least 1 year of operation in compliance with the selected
approach. You must provide notification of such a change in the
compliance method in the next annual report, following the change. If
you use an enclosed combustion device or a flare as the control device,
you must also conduct the monitoring required in paragraph (f)(1)(x) of
this section. If you use an enclosed combustion device or flare using
an alternative test method approved under Sec. 60.5412b(d), you must
use the procedures in paragraph (f)(1)(xi) of this section in lieu of
the procedures in paragraphs (f)(1)(i) through (viii) of this section,
but you must still conduct the monitoring required in paragraph
(f)(1)(x) of this section.
(i) You must operate below (or above) the site-specific maximum (or
minimum) parameter value established according to the requirements of
Sec. 60.5417b(f)(1). For flares, you must operate above the limits
specified in paragraphs (f)(1)(vii)(B) of this section.
(ii) You must calculate the average of the applicable monitored
parameter in accordance with Sec. 60.5417b(e).
(iii) Compliance with the operating parameter limit is achieved
when the average of the monitoring parameter value calculated under
paragraph (f)(1)(ii) of this section is either equal to or greater than
the minimum parameter value or equal to or less than the maximum
parameter value established under paragraph (f)(1)(i) of this section.
When performance testing of a
[[Page 17097]]
combustion control device is conducted by the device manufacturer as
specified in Sec. 60.5413b(d), compliance with the operating parameter
limit is achieved when the criteria in Sec. 60.5413b(e) are met.
(iv) You must operate the continuous monitoring system required in
Sec. 60.5417b(a) at all times the affected source is operating, except
for periods of monitoring system malfunctions, repairs associated with
monitoring system malfunctions and required monitoring system quality
assurance or quality control activities, including, as applicable,
system accuracy audits and required zero and span adjustments. A
monitoring system malfunction is any sudden, infrequent, not reasonably
preventable failure of the monitoring system to provide valid data.
Monitoring system failures that are caused in part by poor maintenance
or careless operation are not malfunctions. You are required to
complete monitoring system repairs in response to monitoring system
malfunctions and to return the monitoring system to operation as
expeditiously as practicable.
(v) You may not use data recorded during monitoring system
malfunctions, repairs associated with monitoring system malfunctions,
or required monitoring system quality assurance or control activities
in calculations used to report emissions or operating levels. You must
use all the data collected during all other required data collection
periods to assess the operation of the control device and associated
control system.
(vi) Failure to collect required data is a deviation of the
monitoring requirements.
(vii) If you use an enclosed combustion device to meet the
requirements of Sec. 60.5412b(a)(1) and you demonstrate compliance
using the test procedures specified in Sec. 60.5413b(b), or you use a
flare designed and operated in accordance with Sec. 60.5412b(a)(3),
you must comply with the applicable requirements in paragraphs
(f)(1)(vii)(A) through (E) of this section.
(A) For each enclosed combustion device which is not a catalytic
vapor incinerator and for each flare, you must comply with the
requirements in paragraphs (f)(1)(vii)(A)(1) through (4) of this
section.
(1) A pilot or combustion flame must be present at all times of
operation. An alert must be sent to the nearest control room whenever
the pilot or combustion flame is unlit.
(2) Devices must be operated with no visible emissions, except for
periods not to exceed a total of 1 minute during any 15-minute period.
A visible emissions test conducted according to section 11 of Method 22
of appendix A-7 to this part, must be performed at least once every
calendar month, separated by at least 15 days between each test. The
observation period shall be 15 minutes or once the amount of time
visible emissions is present has exceeded 1 minute, whichever time
period is less. Alternatively, you may conduct visible emissions
monitoring according to Sec. 60.5417b(h).
(3) Devices failing the visible emissions test must follow
manufacturer's repair instructions, if available, or best combustion
engineering practice as outlined in the unit inspection and maintenance
plan, to return the unit to compliant operation. All repairs and
maintenance activities for each unit must be recorded in a maintenance
and repair log and must be available for inspection.
(4) Following return to operation from maintenance or repair
activity, each device must pass a Method 22 of appendix A-7 to this
part visual observation as described in paragraph (f)(1)(vii)(D) of
this section or be monitored according to Sec. 60.5417b(h).
(B) For flares, you must comply with the requirements in paragraphs
(f)(1)(vii)(B)(1) through (6) of this section.
(1) For unassisted flares, maintain the NHV of the gas sent to the
flare at or above 200 Btu/scf.
(2) If you use a pressure assisted flare, maintain the NHV of gas
sent to the flare at or above 800 Btu/scf.
(3) For steam-assisted and air-assisted flares, maintain the
NHVcz at or above 270 Btu/scf.
(4) For flares with perimeter assist air, maintain the
NHVdil at or above 22 Btu/sqft. If the only assist air
provided to the flare is perimeter assist air intentionally entrained
in lower and/or upper steam at the flare tip and the effective diameter
is 9 inches or greater, you are not required to comply with the
NHVdil limit.
(5) Unless you use a pressure-assisted flare, maintain the flare
tip velocity below the applicable limits in Sec. 60.18(b).
(6) Maintain the total gas flow to the flare above the minimum
inlet gas flow rate. The minimum inlet gas flow rate is established
based on manufacturer recommendations.
(C) For enclosed combustion devices for which, during the
performance test conducted under Sec. 60.5413b(b), the combustion zone
temperature is not an indicator of destruction efficiency, you must
comply with the requirements in paragraphs (f)(1)(vii)(C)(1) through
(5) of this section, as applicable.
(1) Maintain the total gas flow to the enclosed combustion device
at or above the minimum inlet gas flow rate and at or below the maximum
inlet flow rate for the enclosed combustion device established in
accordance with Sec. 60.5417b(f).
(2) For unassisted enclosed combustion devices, maintain the NHV of
the gas sent to the enclosed combustion device at or above 200 Btu/scf.
(3) For enclosed combustion devices that use pressure-assisted
burner tips to promote mixing at the burner tip, maintain the NHV of
the gas sent to the enclosed combustion device at or above 800 Btu/scf.
(4) For steam-assisted and air-assisted enclosed combustion
devices, maintain the NHVcz at or above 270 Btu/scf.
(5) For enclosed combustion devices with perimeter assist air,
maintain the NHVdil at or above 22 Btu/sqft. If the only
assist air provided to the enclosed combustion device is perimeter
assist air intentionally entrained in lower and/or upper steam at the
flare tip and the effective diameter is 9 inches or greater, you are
not required to comply with the NHVdil limit.
(D) For enclosed combustion devices for which, during the
performance test conducted under Sec. 60.5413b(b), the combustion zone
temperature is demonstrated to be an indicator of destruction
efficiency, you must comply with the requirements in paragraphs
(f)(1)(vii)(D)(1) and (2) of this section.
(1) Maintain the temperature at or above the minimum temperature
established during the most recent performance test. The minimum
temperature limit established during the most recent performance test
is the average temperature recorded during each test run, averaged
across the 3 test runs (average of the test run averages).
(2) Maintain the total gas flow to the enclosed combustion device
at or above the minimum inlet gas flow rate and at or below the maximum
inlet flow rate for the enclosed combustion device established in
accordance with Sec. 60.5417b(f).
(E) For catalytic vapor incinerators you must operate the catalytic
vapor incinerator at or above the minimum temperature of the catalyst
bed inlet and at or above the minimum temperature differential between
the catalyst bed inlet and the catalyst bed outlet established in
accordance with Sec. 60.5417b(f).
(viii) If you use a carbon adsorption system as the control device
to meet the requirements of Sec. 60.5412b(a)(2), you
[[Page 17098]]
must demonstrate compliance by the procedures in paragraphs
(f)(1)(viii)(A) and (B) of this section, as applicable.
(A) If you use a regenerative-type carbon adsorption system, you
must comply with paragraphs (f)(1)(viii)(A)(1) through (4) of this
section.
(1) You must maintain the average regenerative mass flow or
volumetric flow to the carbon adsorber during each bed regeneration
cycle above the limit established in in accordance with Sec.
60.5413b(c)(2).
(2) You must maintain the average carbon bed temperature above the
temperature limit established in accordance with Sec. 60.5413b(c)(2)
during the carbon bed steaming cycle and below the carbon bed
temperature established in in accordance with Sec. 60.5413b(c)(2)
after the regeneration cycle.
(3) You must check the mechanical connections for leakage at least
every month, and you must perform a visual inspection at least every 3
months of all components of the continuous parameter monitoring system
for physical and operational integrity and all electrical connections
for oxidation and galvanic corrosion if your continuous parameter
monitoring system is not equipped with a redundant flow sensor.
(4) You must replace all carbon in the carbon adsorption system
with fresh carbon on a regular, predetermined time interval that is no
longer than the carbon service life established according to Sec.
60.5413b(c)(2).
(B) If you use a nonregenerative-type carbon adsorption system, you
must replace all carbon in the control device with fresh carbon on a
regular, predetermined time interval that is no longer than the carbon
service life established according to Sec. 60.5413b(c)(3).
(ix) If you use a condenser as the control device to achieve the
percent reduction performance requirements specified in Sec.
60.5412b(a)(2), you must demonstrate compliance using the procedures in
paragraphs (f)(1)(ix)(A) through (E) of this section.
(A) You must establish a site-specific condenser performance curve
according to Sec. 60.5417b(f)(2).
(B) You must calculate the daily average condenser outlet
temperature in accordance with Sec. 60.5417b(e).
(C) You must determine the condenser efficiency for the current
operating day using the daily average condenser outlet temperature
calculated under paragraph (f)(1)(ix)(B) of this section and the
condenser performance curve established under paragraph (f)(1)(ix)(A)
of this section.
(D) Except as provided in paragraphs (f)(1)(ix)(D)(1) and (2) of
this section, at the end of each operating day, you must calculate the
365-day rolling average TOC emission reduction, as appropriate, from
the condenser efficiencies as determined in paragraph (f)(1)(ix)(C) of
this section.
(1) After the compliance dates specified in Sec. 60.5370b(a), if
you have less than 120 days of data for determining average TOC
emission reduction, you must calculate the average TOC emission
reduction for the first 120 days of operation after the compliance
date. You have demonstrated compliance with the overall 95.0 percent
reduction requirement if the 120-day average TOC emission reduction is
equal to or greater than 95.0 percent.
(2) After 120 days and no more than 364 days of operation after the
compliance date specified in Sec. 60.5370b(a), you must calculate the
average TOC emission reduction as the TOC emission reduction averaged
over the number of days between the current day and the applicable
compliance date. You have demonstrated compliance with the overall 95.0
percent reduction requirement if the average TOC emission reduction is
equal to or greater than 95.0 percent.
(E) If you have data for 365 days or more of operation, you have
demonstrated compliance with the TOC emission reduction if the rolling
365-day average TOC emission reduction calculated in paragraph
(f)(1)(ix)(D) of this section is equal to or greater than 95.0 percent.
(x) During each inspection conducted using an OGI camera under
Sec. 60.5397b and during each periodic screening event or each
inspection conducted using an OGI camera under Sec. 60.5398b, you must
observe each enclosed combustion device and flare to determine if it is
operating properly. You must determine whether there is a flame present
and whether any uncontrolled emissions from the control device are
visible with the OGI camera or the technique used to conduct the
periodic screening event. During each inspection conducted under Sec.
60.5397b using AVO, you must observe each enclosed combustion device
and flare to determine if it is operating properly. Visually confirm
that the pilot or combustion flame is lit and that the pilot or
combustion flame is operating properly.
(xi) If you use an enclosed combustion device or flare using an
alternative test method approved under Sec. 60.5412b(d), you must
comply with paragraphs (f)(1)(xi)(A) through (E) of this section.
(A) You must maintain the combustion efficiency at or above 95.0
percent. Alternatively, if the alternative test method does not
directly monitor combustion efficiency, you must comply with the
applicable requirements in paragraphs (f)(1)(xi)(A)(1) and (2) of this
section.
(1) Maintain the NHVcz at or above 270 Btu/scf.
(2) For flares or enclosed combustion devices with perimeter assist
air, maintain the NHVdil at or above 22 Btu/sqft. If the
only assist air provided to the flare or enclosed combustion device is
perimeter assist air intentionally entrained in lower and/or upper
steam at the flare tip and the effective diameter is 9 inches or
greater, you are only required to comply with the NHVcz
limit specified in paragraph (f)(1)(xi)(A)(1) of this section.
(B) You must calculate the value of the applicable monitored
metric(s) in accordance with the approved alternative test method.
Compliance with the limit is achieved when the calculated values are
within the range specified in paragraph (f)(1)(xi)(A) of this section.
(C) You must conduct monitoring using the alternative test method
at all times the affected source is operating, except for periods of
monitoring system malfunctions, repairs associated with monitoring
system malfunctions and required monitoring system quality assurance or
quality control activities, including, as applicable, system accuracy
audits and required zero and span adjustments. A monitoring system
malfunction is any sudden, infrequent, not reasonably preventable
failure of the monitoring system to provide valid data. Monitoring
system failures that are caused in part by poor maintenance or careless
operation are not malfunctions. You are required to complete monitoring
system repairs in response to monitoring system malfunctions and to
return the monitoring system to operation as expeditiously as
practicable.
(D) You may not use data recorded during monitoring system
malfunctions, repairs associated with monitoring system malfunctions,
or required monitoring system quality assurance or control activities
in calculations used to report values to demonstrate compliance with
the limits specified in paragraph (f)(1)(xi)(A) of this section. You
must use all the data collected during all other required data
collection periods to assess the operation of the control device and
associated control system.
[[Page 17099]]
(E) Failure to collect required data is a deviation of the
monitoring requirements.
(2) You must maintain the records as specified in Sec.
60.5420b(c)(11) and (13).
(3) You must comply with the reporting requirements in Sec.
60.5420b(b)(11) through (13).
(g) Reciprocating compressor affected facility. For each
reciprocating compressor affected facility complying with Sec.
60.5385b(a) through (c), you must demonstrate continuous compliance
according to paragraphs (g)(1), (5), and (6) of this section. For each
reciprocating compressor affected facility complying with Sec.
60.5385b(d)(1) or (2), you must demonstrate continuous compliance
according to paragraphs (g)(2), (5) and (6) of this section. For each
reciprocating compressor affected facility complying with Sec.
60.5385b(d)(3), you must demonstrate continuous compliance according to
paragraphs (g)(3) through (6) of this section.
(1) You must maintain the volumetric flow rate at or below 2 scfm
per cylinder (or at or below the combined volumetric flow rate
determined by multiplying the number of cylinders by 2 scfm), and you
must conduct the required volumetric flow rate measurement of your
reciprocating compressor rod packing vents in accordance with Sec.
60.5385b(b) on or before 8,760 hours of operation after your last
volumetric flow rate measurement which demonstrated compliance with the
applicable volumetric flow rate.
(2) You must operate the rod packing emissions collection system to
route emissions to a control device or to a process through a closed
vent system and continuously comply with the cover and closed vent
requirements of Sec. 60.5416b. If you comply with Sec. 60.5385b(d) by
using a control device, you also must comply with the requirements in
paragraph (f) of this section.
(3) You must continuously monitor the number of hours of operation
for each reciprocating compressor affected facility since initial
startup, since May 7, 2024, since the previous flow rate measurement,
or since the date of the most recent reciprocating compressor rod
packing replacement, whichever date is latest.
(4) You must replace the reciprocating compressor rod packing on or
before the total number of hours of operation reaches 8,760 hours.
(5) You must submit the annual reports as required in Sec.
60.5420b(b)(1), (6), and (11)(i) through (iv), as applicable.
(6) You must maintain records as required in Sec. 60.5420b(c)(5),
(8) through (10), and (12), as applicable.
(h) Process controller affected facility. To demonstrate continuous
compliance with GHG and VOC emission standards for your process
controller affected facility as required by Sec. 60.5390b, you must
comply with paragraphs (h)(1) through (4) of this section, as
applicable.
(1) You must demonstrate that your process controller affected
facility does not emit any VOC or methane to the atmosphere by meeting
the requirements of paragraphs (h)(1)(i) or (ii) of this section.
(i) If you comply by routing the emissions to a process, you must
comply with the closed vent system inspection and monitoring
requirements of Sec. 60.5416b.
(ii) If you comply by using a self-contained natural gas-driven
process controller, you must conduct the no identifiable emissions
inspections required by Sec. 60.5416b(b).
(2) For each process controller affected facility located at a site
in Alaska that does not have access to electrical power and that
complies by reducing methane and VOC emissions from all controllers in
the process controller affected facility by 95.0 percent in accordance
with Sec. 60.5390b(b)(3), you must comply with the closed vent
requirements of Sec. 60.5416b and the requirements in paragraph (f) of
this section for the control device.
(3) You must submit the annual report for your process controller
as required in Sec. 60.5420b(b)(1), (7), and (11)(i) through (iv), as
applicable.
(4) You must maintain the records as specified in Sec.
60.5420b(c)(6), (8), (10), and (12) for each process controller
affected facility, as applicable.
(i) Storage vessel affected facility. For each storage vessel
affected facility, you must demonstrate continuous compliance with the
requirements of Sec. 60.5395b according to paragraphs (i)(1) through
(10) of this section, as applicable.
(1) For each storage vessel affected facility complying with the
requirements of Sec. 60.5395b(a)(2), you must demonstrate continuous
compliance according to paragraphs (i)(5), (9) and (10) of this
section.
(2) For each storage vessel affected facility complying with the
requirements of Sec. 60.5395b(a)(3), you must demonstrate continuous
compliance according to paragraphs (i)(2)(i), (ii), or (iii) of this
section, as applicable, and (i)(9) and (10) of this section.
(i) You must maintain the uncontrolled actual VOC emissions at less
than 4 tpy and the uncontrolled actual methane emissions at less than
14 tpy from the storage vessel affected facility.
(ii) You must comply with paragraph (i)(5) of this section as soon
as liquids from the well are routed to the storage vessel affected
facility following fracturing or refracturing according to the
requirements of Sec. 60.5395b(a)(3)(i).
(iii) You must comply with paragraph (i)(5) of this section within
30 days of the monthly determination according to the requirements of
Sec. 60.5395b(a)(3)(ii), where the monthly emissions determination
indicates that VOC emissions from your storage vessel affected facility
increase to 4 tpy or greater and the increase is not associated with
fracturing or refracturing of a well feeding the storage vessel
affected facility.
(3) For each storage vessel affected facility or portion of a
storage vessel affected facility removed from service, you must
demonstrate compliance with the requirements of Sec. 60.5395b(c)(1) by
complying with paragraphs (i)(6), (7), (9), and (10) of this section.
(4) For each storage vessel affected facility or portion of a
storage vessel affected facility returned to service, you must
demonstrate compliance with the requirements of Sec. 60.5395b(c)(1) by
complying with paragraphs (i)(8) through (10) of this section.
(5) For each storage vessel affected facility, you must comply with
paragraphs (i)(5)(i) and (ii) of this section.
(i) You must reduce VOC emissions as specified in Sec.
60.5395b(a)(2).
(ii) For each control device installed to meet the requirements of
Sec. 60.5395b(a)(2), you must demonstrate continuous compliance with
the performance requirements of Sec. 60.5412b for each storage vessel
affected facility using the procedure specified in paragraphs
(i)(5)(ii)(A) and (i)(5)(ii)(B) of this section. When routing emissions
to a process, you must demonstrate continuous compliance as specified
in paragraph (i)(5)(ii)(A) of this section.
(A) You must comply with Sec. 60.5416b for each cover and closed
vent system.
(B) You must comply with the requirements specified in paragraph
(f) of this section.
(6) You must completely empty and degas each storage vessel, such
that each storage vessel no longer contains crude oil, condensate,
produced water or intermediate hydrocarbon liquids. For a portion of a
storage vessel affected facility to be removed from service, you must
completely empty and degas the
[[Page 17100]]
storage vessel(s), such that the storage vessel(s) no longer contains
crude oil, condensate, produced water, or intermediate hydrocarbon
liquids. A storage vessel where liquid is left on walls, as bottom
clingage, or in pools due to floor irregularity is considered to be
completely empty.
(7) You must disconnect the storage vessel(s) from the tank battery
by isolating the storage vessel(s) from the tank battery such that the
storage vessel(s) is no longer manifolded to the tank battery by liquid
or vapor transfer.
(8) You must determine the affected facility status of a storage
vessel returned to service as provided in Sec. 60.5365b(e)(6).
(9) You must submit the annual reports as required by Sec.
60.5420b(b)(1), (8), and (11)(i) through (iv).
(10) You must maintain the records as required by Sec.
60.5420b(c)(7) through (10) and (c)(12), as applicable.
(j) Process unit equipment affected facility. For each process unit
equipment affected facility, you must demonstrate continuous compliance
with the requirements of Sec. 60.5400b according to paragraphs (j)(1)
through (4) and(11) through (15) of this section, unless you meet and
comply with the exception in Sec. 60.5402b(b), (e), or (f) or meet the
exemption in Sec. 60.5402b(c). Alternatively, if you comply with the
GHG and VOC standards for process unit affected facilities using the
standards in Sec. 60.5401b, you must comply with paragraphs (j)(5)
through (15) of this section, unless you meet the exemption in Sec.
60.5402b(b) or (c) or the exception in Sec. 60.5402b(e) and (f).
(1) You must conduct monitoring for each pump in light liquid
service, pressure relief device in gas/vapor service, valve in gas/
vapor and light liquid service and connector in gas/vapor and light
liquid service as required by Sec. 60.5400b(b).
(2) You must conduct monitoring as required by Sec. 60.5400b(c)
for each pump in light liquid service.
(3) You must conduct monitoring as required by Sec. 60.5400b(d)
for each pressure relief device in gas/vapor service.
(4) You must comply with the equipment requirements for each open-
ended valve or line as required by Sec. 60.5400b(e).
(5) You must conduct monitoring for each pump in light liquid
service as required by Sec. 60.5401b(b).
(6) You must conduct monitoring for each pressure relief device in
gas/vapor service as required by Sec. 60.5401b(c).
(7) You must comply with the equipment requirements for each open-
ended valve or line as required by Sec. 60.5401b(d).
(8) You must conduct monitoring for each valve in gas/vapor or
light liquid service as required by Sec. 60.5401b(f).
(9) You must conduct monitoring for each pump, valve, and connector
in heavy liquid service and each pressure relief device in light liquid
or heavy liquid service as required by Sec. 60.5401b(g).
(10) You must conduct monitoring for each connector in gas/vapor or
light liquid service as required by Sec. 60.5401b(h).
(11) You must collect emissions and meet the closed vent system
requirements as required by Sec. 60.5416b for each pump equipped with
a dual mechanical seal system that degasses the barrier fluid reservoir
to a process or a control device, each pump which captures and
transports leakage from the seal or seals to a process or control
device, or each pressure relief device which captures and transports
leakage through the pressure relief device to a process or control
device.
(12) You comply with the requirements specified in paragraph (f) of
this section.
(13) You must tag and repair each identified leak as required in
Sec. 60.5400(h) or Sec. 60.5401b(i), as applicable.
(14) You must submit semiannual reports as required by Sec.
60.5422b and the annual reports in Sec. 60.5420b(b)(11)(i) through
(iv), as applicable.
(15) You must maintain the records specified by Sec.
60.5420b(c)(8), (c)(10), and (c)(12) as applicable and Sec. 60.5421b.
(k) Sweetening unit affected facility. For each sweetening unit
affected facility, you must demonstrate continuous compliance with the
requirements of Sec. 60.5405b(b) according to paragraphs (k)(1)
through (10) of this section.
(1) You must determine the minimum required continuous reduction
efficiency of SO2 emissions (Zc) as required by
Sec. 60.5406b(b).
(2) You must determine the emission reduction efficiency (R)
achieved by your sulfur reduction technology using the procedures in
Sec. 60.5406b(c)(1) through (c)(4).
(3) You must demonstrate compliance with the standard at Sec.
60.5405b(b) by comparing the minimum required sulfur dioxide emission
reduction efficiency (Zc) to the emission reduction
efficiency achieved by the sulfur recovery technology (R), where R must
be greater than or equal to Zc.
(4) You must calibrate, maintain, and operate monitoring devices or
perform measurements to determine the accumulation of sulfur product,
the H2S concentration, the average acid gas flow rate, and
the sulfur feed rate in accordance with Sec. 60.5407b(a).
(5) You must determine the required SO2 emissions
reduction efficiency each 24-hour period in accordance with Sec.
60.5407b(a), Sec. 60.5407b(d), and Sec. 60.5407b(e), as applicable.
(6) You must calibrate, maintain, and operate monitoring devices
and continuous emission monitors in accordance with Sec. 60.5407b(b),
(f), and (g), if you use an oxidation control system or a reduction
control system followed by an incineration device.
(7) You must continuously operate the incineration device, if you
use an oxidation control system or a reduction control system followed
by an incineration device.
(8) You must calibrate, maintain, and operate a continuous
monitoring system to measure the emission rate of reduced sulfur
compounds in accordance with Sec. 60.5407b(c), (f), and (g), if you
use a reduction control system not followed by an incineration device.
(9) You must submit the reports as required by Sec. 60.5423b(b)
and (d).
(10) You must maintain the records as required by Sec.
60.5423b(a), (e), and (f), as applicable.
(l) Continuous compliance. For each fugitive emissions components
affected facility, you must demonstrate continuous compliance with the
requirements of Sec. 60.5397b(a) according to paragraphs (l)(1)
through (4) of this section.
(1) You must conduct periodic monitoring surveys as required in
Sec. 60.5397b(e) and (g).
(2) You must repair each identified source of fugitive emissions as
required in Sec. 60.5397b(h).
(3) You must submit annual reports for fugitive emissions
components affected facilities as required in Sec. 60.5420b(b)(1) and
(9).
(4) You must maintain records as specified in Sec.
60.5420b(c)(16).
Sec. 60.5416b What are the initial and continuous cover and closed
vent system inspection and monitoring requirements?
For each closed vent system and cover at your well, centrifugal
compressor, reciprocating compressor, process controller, pump, storage
vessel, and process unit equipment affected facilities, you must comply
with the applicable requirements of paragraphs (a) and (b) of this
section. Each self-contained natural gas process controller must comply
with paragraph (b) of this section.
(a) Inspections for closed vent systems, covers, and bypass
devices. If
[[Page 17101]]
you install a control device or route emissions to a process, you must
inspect each closed vent system according to the procedures and
schedule specified in paragraphs (a)(1) and (2) of this section,
inspect each cover according to the procedures and schedule specified
in paragraph (a)(3) of this section, and inspect each bypass device
according to the procedures of paragraph (a)(4) of this section, except
as provided in paragraphs (b)(6) and (7) of this section.
(1) For each closed vent system joint, seam, or other connection
that is permanently or semi-permanently sealed (e.g., a welded joint
between two sections of hard piping or a bolted and gasketed ducting
flange), you must meet the requirements specified in paragraphs
(a)(1)(i) through (iii) of this section.
(i) Conduct an initial inspection according to the test methods and
procedures specified in paragraph (b) of this section to demonstrate
that the closed vent system operates with no identifiable emissions
within the first 30 calendar days after startup of the affected
facility routing emissions through the closed vent system.
(ii) Conduct annual visual inspections for defects that could
result in air emissions. Defects include, but are not limited to,
visible cracks, holes, or gaps in piping; loose connections; liquid
leaks; or broken or missing caps or other closure devices. You must
monitor a component or connection using the test methods and procedures
in paragraph (b) of this section to demonstrate that it operates with
no identifiable emissions following any time the component is repaired
or replaced or the connection is unsealed.
(iii) Conduct AVO inspections in accordance with and at the same
frequency as specified for fugitive emissions components affected
facilities located at the same type of site as specified in Sec.
60.5397b(g). Process unit equipment affected facilities must conduct
annual AVO inspections concurrent with the inspections required by
paragraph (a)(1)(ii) of this section.
(2) For closed vent system components other than those specified in
paragraph (a)(1) of this section, you must meet the requirements of
paragraphs (a)(2)(i) through (iv) of this section.
(i) Conduct an initial inspection according to the test methods and
procedures specified in paragraph (b) of this section within the first
30 calendars days after startup of the affected facility routing
emissions through the closed vent system to demonstrate that the closed
vent system operates with no identifiable emissions.
(ii) Conduct inspections according to the test methods, procedures,
and frequencies specified in paragraph (b) of this section to
demonstrate that the components or connections operate with no
identifiable emissions.
(iii) Conduct annual visual inspections for defects that could
result in air emissions. Defects include, but are not limited to,
visible cracks, holes, or gaps in ductwork; loose connections; liquid
leaks; or broken or missing caps or other closure devices. You must
monitor a component or connection using the test methods and procedures
in paragraph (b) of this section to demonstrate that it operates with
no identifiable emissions following any time the component is repaired
or replaced or the connection is unsealed.
(iv) Conduct AVO inspections in accordance with and at the same
frequency as specified for fugitive emissions components affected
facilities located at the same type of site, as specified in Sec.
60.5397b(g). Process unit equipment affected facilities must conduct
annual AVO inspections concurrent with the inspections required by
paragraph (a)(2)(iii) of this section.
(3) For each cover, you must meet the requirements of paragraphs
(a)(3)(i) through (iv) of this section.
(i) Conduct the inspections specified in paragraphs (a)(3)(ii)
through (iv) of this section to identify defects that could result in
air emissions and to ensure the cover operates with no identifiable
emissions. Defects include, but are not limited to, visible cracks,
holes, or gaps in the cover, or between the cover and the separator
wall; broken, cracked, or otherwise damaged seals or gaskets on closure
devices; and broken or missing hatches, access covers, caps, or other
closure devices. In the case where the storage vessel is buried
partially or entirely underground, you must inspect only those portions
of the cover that extend to or above the ground surface, and those
connections that are on such portions of the cover (e.g., fill ports,
access hatches, gauge wells, etc.) and can be opened to the atmosphere.
(ii) An initial inspection according to the test methods and
procedures specified in paragraph (b) of this section, following
installation of the cover to demonstrate that each cover operates with
no identifiable emissions.
(iii) Conduct AVO inspections in accordance with and at the same
frequency as specified for fugitive emissions components affected
facilities located at the same type of site as specified in Sec.
60.5397b(g). Process unit equipment affected facilities must conduct
annual AVO inspections concurrent with the inspections required by
paragraph (a)(1)(ii) of this section.
(iv) Inspections according to the test methods, procedures, and
schedules specified in paragraph (b) of this section to demonstrate
that each cover operates with no identifiable emissions.
(4) For each bypass device, except as provided for in Sec.
60.5411b(a)(4)(ii), you must meet the requirements of paragraph
(a)(4)(i) or (ii) of this section.
(i) Set the flow indicator to take a reading at least once every 15
minutes at the inlet to the bypass device that could divert the stream
away from the control device and to the atmosphere.
(ii) If the bypass device valve installed at the inlet to the
bypass device is secured in the non-diverting position using a car-seal
or a lock-and-key type configuration, visually inspect the seal or
closure mechanism at least once every month to verify that the valve is
maintained in the non-diverting position and the vent stream is not
diverted through the bypass device.
(b) No identifiable emissions test methods and procedures. If you
are required to conduct an inspection of a closed vent system and cover
as specified in paragraph (a)(1), (2), or (3) of this section or Sec.
60.5398b(b), you must meet the requirements of paragraphs (b)(1)
through (9) of this section. You must meet the requirements of
paragraphs (b)(1), (2), (4), and (9) of this section for each self-
contained process controller at your process controller affected
facility as specified at Sec. 60.5390b(a)(2).
(1) Initial and periodic inspection. You must conduct initial and
periodic no identifiable emissions inspections as specified in
paragraphs (b)(1)(i) through (iii) of this section, as applicable.
(i) You must conduct inspections for no identifiable emissions from
your covers and closed vent systems at your well, centrifugal
compressor, reciprocating compressor, process controller, pump, or
storage vessel affected facility, using the procedures for conducting
OGI inspections in Sec. 60.5397b(c)(7). As an alternative you may
conduct inspections in accordance with Method 21 of appendix A-7 to
this part. Monitoring must be conducted at the same frequency as
specified for fugitive emissions components affected facilities located
at the same type of site, as specified in Sec. 60.5397b(g).
(ii) For covers and closed vent systems located at onshore natural
gas processing plants, OGI inspections for no identifiable emissions
must be
[[Page 17102]]
conducted initially and bimonthly in accordance with appendix K to this
part. As an alternative you must conduct quarterly inspections for no
identifiable emissions in accordance with Method 21 of appendix A-7 to
this part.
(iii) For your self-contained process controller, you must conduct
initial and quarterly inspections for no identifiable emissions using
the procedures for conducting OGI inspections in Sec. 60.5397b(c)(7).
As an alternative you may conduct quarterly inspections in accordance
with Method 21 of appendix A-7 to this part.
(2) OGI application, Where OGI is used, the closed vent system,
cover, or self-contained process controller is determined to operate
with no identifiable emissions if no emissions are imaged during the
inspection. Emissions imaged by OGI constitute a deviation of the no
identifiable emissions standard until an OGI inspection conducted in
accordance with this paragraph (b)(2) of this section determines that
the closed vent system, cover, or self-contained process controller, as
applicable, operates with no identifiable emissions.
(3) AVO application. Where AVO inspections are required, the closed
vent system or cover is determined to operate with no identifiable
emissions if no emissions are detected by AVO. Emissions detected by
AVO constitute a deviation of the no identifiable emissions standard
until an AVO inspection determines that the closed vent system or cover
operates with no identifiable emissions.
(4) Method 21 application. Where Method 21 of appendix A-7 to this
part is used for the inspection, the requirements of paragraphs
(b)(4)(i) through (vii) of this section apply.
(i) The detection instrument must meet the performance criteria of
Method 21 of appendix A-7 to this part, except that the instrument
response factor criteria in section 8.1.1 of Method 21 must be for the
average composition of the fluid and not for each individual organic
compound in the stream.
(ii) You must calibrate the detection instrument before use on each
day of its use by the procedures specified in Method 21 of appendix A-7
to this part.
(iii) Calibration gases must be as specified in paragraphs
(b)(4)(iii)(A) and (B) of this section.
(A) Zero air (less than 10 parts per million by volume hydrocarbon
in air).
(B) A mixture of methane in air at a concentration less than 500
ppmv.
(iv) You may choose to adjust or not adjust the detection
instrument readings to account for the background organic concentration
level. If you choose to adjust the instrument readings for the
background level, you must determine the background level value
according to the procedures in Method 21 of appendix A-7 to this part.
(v) Your detection instrument must meet the performance criteria
specified in paragraphs (b)(4)(v)(A) and (B) of this section.
(A) Except as provided in paragraph (b)(4)(v)(B) of this section,
the detection instrument must meet the performance criteria of Method
21 of appendix A-7 to this part, except the instrument response factor
criteria in section 8.1.1 of Method 21 must be for the average
composition of the process fluid, not each individual volatile organic
compound in the stream. For process streams that contain nitrogen, air,
or other inerts that are not organic hazardous air pollutants or
volatile organic compounds, you must calculate the average stream
response factor on an inert-free basis.
(B) If no instrument is available that will meet the performance
criteria specified in paragraph (b)(4)(v)(A) of this section, you may
adjust the instrument readings by multiplying by the average response
factor of the process fluid, calculated on an inert-free basis, as
described in paragraph (b)(4)(v)(A) of this section.
(vi) You must determine if a potential leak interface operates with
no identifiable emissions using the applicable procedure specified in
paragraph (b)(4)(vi)(A) or (B) of this section.
(A) If you choose not to adjust the detection instrument readings
for the background organic concentration level, then you must directly
compare the maximum organic concentration value measured by the
detection instrument to the applicable value for the potential leak
interface as specified in paragraph (b)(4)(vii) of this section.
(B) If you choose to adjust the detection instrument readings for
the background organic concentration level, you must compare the value
of the arithmetic difference between the maximum organic concentration
value measured by the instrument and the background organic
concentration value as determined in paragraph (b)(4)(iv) of this
section with the applicable value for the potential leak interface as
specified in paragraph (b)(4)(vii) of this section.
(vii) A closed vent system, cover, or self-contained process
controller is determined to operate with no identifiable emissions if
the organic concentration value determined in paragraph (b)(4)(vi) of
this section is less than 500 ppmv. An organic concentration value
determined in paragraph (b)(4)(vi) of this section of greater than or
equal to 500 ppmv constitutes a deviation of the no identifiable
emissions standard until an inspection conducted in accordance with
paragraph (b)(4) of this section determines that the closed vent
system, cover, or self-contained process controller, as applicable,
operates with no identifiable emissions.
(5) Repairs. Whenever emissions or a defect is detected, you must
repair the emissions or defect as soon as practicable according to the
requirements of paragraphs (b)(5)(i) through (iii) of this section,
except as provided in paragraph (b)(6) of this section.
(i) A first attempt at repair must be made no later than 5 calendar
days after the emissions or defect is detected.
(ii) Repair must be completed no later than 30 calendar days after
the emissions or defect is detected.
(iii) For covers, grease or another substance compatible with the
gasket material must be applied to deteriorating or cracked gaskets to
improve the seal while awaiting repair.
(6) Delay of repair. Delay of repair of a closed vent system or
cover for which emissions or defects have been detected is allowed if
the repair is technically infeasible without a shutdown, or if you
determine that emissions resulting from immediate repair would be
greater than the emissions likely to result from delay of repair. You
must complete repair of such equipment by the end of the next shutdown.
(7) Unsafe to inspect requirements. You may designate any parts of
the closed vent system or cover as unsafe to inspect if the
requirements of paragraphs (b)(7)(i) and (ii) of this section are met.
Unsafe to inspect parts are exempt from the inspection requirements of
paragraphs (a)(1) through (3) of this section.
(i) You determine that the equipment is unsafe to inspect because
inspecting personnel would be exposed to an imminent or potential
danger as a consequence of complying with paragraphs (a)(1), (2), or
(3) of this section.
(ii) You have a written plan that requires inspection of the
equipment as frequently as practicable during safe-to-inspect times.
(8) Difficult to inspect requirements. You may designate any parts
of the closed vent system or cover as difficult to inspect if the
requirements of paragraphs (b)(8)(i) and (ii) of this section are met.
Difficult to inspect parts are exempt from the inspection
[[Page 17103]]
requirements of paragraphs (a)(1) through (3) of this section.
(i) You determine that the equipment cannot be inspected without
elevating the inspecting personnel more than 2 meters above a support
surface.
(ii) You have a written plan that requires inspection of the
equipment at least once every 5 years.
(9) Records and reports. You must maintain records of all
inspection results as specified in Sec. 60.5420b(c)(8) through (10).
You must submit the reports as specified in Sec. 60.5420b(b)(11).
Sec. 60.5417b What are the continuous monitoring requirements for my
control devices?
You must meet the requirements of this section to demonstrate
continuous compliance for each control device used to meet emission
standards for your well, centrifugal compressor, reciprocating
compressor, process controller, pump, storage vessel, and process unit
equipment affected facilities.
(a) For each control device used to comply with the emission
reduction standard in Sec. 60.5377b(b) for well affected facilities,
Sec. 60.5380b(a)(1) for centrifugal compressor affected facilities,
Sec. 60.5385b(d)(2) for reciprocating compressor affected facilities,
Sec. 60.5390b(b)(3) for your process controller affected facility in
Alaska, Sec. 60.5393b(b)(1) for your pumps affected facility, Sec.
60.5395b(a)(2) for your storage vessel affected facility, or either
Sec. 60.5400b(f) or Sec. 60.5401b(e) for your process equipment
affected facility, you must install and operate a continuous parameter
monitoring system for each control device as specified in paragraphs
(c) through (h) of this section, except as provided for in paragraph
(b) of this section. If you install and operate a flare in accordance
with Sec. 60.5412b(a)(3), you are exempt from the requirements of
paragraph (f) of this section. If you operate an enclosed combustion
device or flare using an alternative test method approved under Sec.
60.5412b(d), you must operate the control device as specified in
paragraph (i) of this section instead of using the procedures specified
in paragraphs (c) through (h) of this section. You must keep records
and report in accordance with paragraph (j) of this section.
(b) You are exempt from the monitoring requirements specified in
paragraphs (c) through (g) of this section for the control devices
listed in paragraphs (b)(1) and (2) of this section.
(1) A boiler or process heater in which all vent streams are
introduced with the primary fuel or are used as the primary fuel.
(2) A boiler or process heater with a design heat input capacity
equal to or greater than 44 megawatts.
(c) You must meet the specifications and requirements of paragraphs
(c)(1) through (4) of this section.
(1) Except for continuous parameter monitoring systems used to
detect the presence of a pilot or combustion flame, each continuous
parameter monitoring system must measure data values at least once
every hour and record the values for each parameter as required in
paragraphs (c)(1)(i) or (ii) of this section. Continuous parameter
monitoring systems used to detect the presence of a pilot or combustion
flame must record a reading at least once every 5 minutes.
(i) Each measured data value.
(ii) Each block average value for each 1-hour period or shorter
periods calculated from all measured data values during each period.
(2) You must prepare a monitoring plan that covers each control
device for affected facilities within each company-defined area. The
monitoring plan must address the monitoring system design, data
collection, and the quality assurance and quality control elements
outlined in paragraphs (c)(2)(i) through (v) of this section. You must
install, calibrate, operate, and maintain each continuous parameter
monitoring system in accordance with the procedures in your monitoring
plan. Heat sensing monitoring devices that indicate the continuous
ignition of a pilot or combustion flame are exempt from the
calibration, quality assurance and quality control requirements of this
section.
(i) The performance criteria and design specifications for the
monitoring system equipment, including the sample interface, detector
signal analyzer, and data acquisition and calculations.
(ii) Sampling interface (e.g., thermocouple) location such that the
monitoring system will provide representative measurements.
(iii) Equipment performance checks, system accuracy audits, or
other audit procedures.
(iv) Ongoing operation and maintenance procedures in accordance
with provisions in Sec. 60.13(b).
(v) Ongoing recordkeeping procedures in accordance with provisions
in Sec. 60.7(f).
(3) You must conduct the continuous parameter monitoring system
equipment performance checks, system accuracy audits, or other audit
procedures specified in the monitoring plan at least once every 12
months.
(4) You must conduct a performance evaluation of each continuous
parameter monitoring system in accordance with the monitoring plan.
Heat sensing monitoring devices that indicate the continuous ignition
of a pilot or combustion flame are exempt from the calibration, quality
assurance and quality control requirements of this section.
(d) You must install, calibrate, operate, and maintain a device
equipped with a continuous recorder to measure the values of operating
parameters appropriate for the control device as specified in
paragraphs (d)(1) through (8) of this section, as applicable. Instead
of complying with the requirements in paragraphs (d)(1) through (8) of
this section, you may install an organic monitoring device equipped
with a continuous recorder that measures the concentration level of
organic compounds in the exhaust vent stream from the control device to
demonstrate compliance with the applicable performance requirement
specified in Sec. 60.5412b(a)(1). The monitor must meet the
requirements of Performance Specification 8 or 9 of appendix B to this
part. You must install, calibrate, and maintain the monitor according
to the manufacturer's specifications and the requirements in
Performance Specification 8 or 9. You may also request approval from
the Administrator to monitor different operating parameters than those
specified in paragraphs (d)(1) through (8) of this section in
accordance with Sec. 60.13(i).
(1) For an enclosed combustion device that demonstrates during the
performance test conducted under Sec. 60.5413b(b) that combustion zone
temperature is an accurate indicator of performance, a temperature
monitoring device equipped with a continuous recorder. The monitoring
device must have a minimum accuracy of 1 percent of the
temperature being monitored in degrees Celsius, or 2.5
[deg]C, whichever value is greater. You must install the temperature
sensor at a location representative of the combustion zone temperature.
You must also comply with the requirements of paragraphs (d)(8)(i),
(iv), and (v) of this section.
(2) For a catalytic vapor incinerator, a temperature monitoring
device equipped with a continuous recorder. The device must be capable
of monitoring temperature at two locations and have a minimum accuracy
of 1 percent of the temperature being monitored in degrees
Celsius, or 2.5 [deg]C, whichever value is greater. You
must install one temperature sensor in the vent stream at the nearest
feasible point
[[Page 17104]]
to the catalyst bed inlet, and you must install a second temperature
sensor in the vent stream at the nearest feasible point to the catalyst
bed outlet.
(3) For a boiler or process heater, a temperature monitoring device
equipped with a continuous recorder. The temperature monitoring device
must have a minimum accuracy of 1 percent of the
temperature being monitored in degrees Celsius, or 2.5
[deg]C, whichever value is greater. You must install the temperature
sensor at a location representative of the combustion zone temperature.
(4) For a condenser, a temperature monitoring device equipped with
a continuous recorder. The temperature monitoring device must have a
minimum accuracy of 1 percent of the temperature being
monitored in degrees Celsius, or 2.5 [deg]C, whichever
value is greater. You must install the temperature sensor at a location
in the exhaust vent stream from the condenser.
(5) For a regenerative-type carbon adsorption system, a continuous
monitoring system that meets the specifications in paragraphs (d)(5)(i)
and (ii) of this section. You also must monitor the design carbon
service life established using a design analysis performed as specified
in Sec. 60.5413b(c)(2).
(i) The continuous parameter monitoring system must measure and
record the average total regeneration stream mass flow or volumetric
flow during each carbon bed regeneration cycle. The flow sensor must
have a measurement sensitivity of 5 percent of the flow rate or 10
cubic feet per minute, whichever is greater. You must check the
mechanical connections for leakage at least every month, and you must
perform a visual inspection at least every 3 months of all components
of the flow continuous parameter monitoring system for physical and
operational integrity and all electrical connections for oxidation and
galvanic corrosion if your flow continuous parameter monitoring system
is not equipped with a redundant flow sensor; and
(ii) The continuous parameter monitoring system must measure and
record the average carbon bed temperature for the duration of the
carbon bed steaming cycle and measure the actual carbon bed temperature
after regeneration and within 15 minutes of completing the cooling
cycle. The temperature monitoring device must have a minimum accuracy
of 1 percent of the temperature being monitored in degrees
Celsius, or 2.5 [deg]C, whichever value is greater.
(6) For a nonregenerative-type carbon adsorption system, you must
monitor the design carbon replacement interval established using a
design analysis performed as specified in Sec. 60.5413b(c)(3). The
design carbon replacement interval must be based on the total carbon
working capacity of the control device and source operating schedule.
(7) For a combustion control device whose model is tested under
Sec. 60.5413b(d), continuous monitoring systems as specified in
paragraphs (d)(8)(i) through (iv) and (d)(8)(vi) of this section and
visible emission observations conducted as specified in paragraph
(d)(8)(v) of this section.
(8) For an enclosed combustion device other than those listed in
paragraphs (d)(1) through (3) and (7) of this section or for a flare,
continuous monitoring systems as specified in paragraphs (d)(8)(i)
through (iv) of this section and visible emission observations
conducted as specified in paragraph (d)(8)(v) of this section.
Additionally, for enclosed combustion devices or flares that are air-
assisted or steam-assisted, the continuous monitoring systems specified
in paragraph (d)(8)(vi) of this section.
(i) Continuously monitor at least once every five minutes for the
presence of a pilot flame or combustion flame using a device
(including, but not limited to, a thermocouple, ultraviolet beam
sensor, or infrared sensor) capable of detecting that the pilot or
combustion flame is present at all times. An alert must be sent to the
nearest control room whenever the pilot or combustion flame is unlit.
Continuous monitoring systems used for the presence of a pilot flame or
combustion flame are not subject to a minimum accuracy requirement
beyond being able to detect the presence or absence of a flame and are
exempt from the calibration requirements of this section.
(ii) Except as provided in this paragraph (d)(8)(ii) and paragraph
(d)(8)(iii) of this section, use one of the following methods to
continuously determine the NHV of the inlet gas to the enclosed
combustion device or flare at standard conditions. If the only inlet
gas stream to the enclosed combustion device or flare is associated gas
from a well affected facility, the NHV of the inlet stream is
considered to be sufficiently above the minimum required NHV for the
inlet gas, and you are not required to conduct the continuous
monitoring in this paragraph (d)(8)(ii) of this section or the
demonstration in paragraph (d)(8)(iii) of this section.
(A) A calorimeter with a minimum accuracy of 2 percent
of span.
(B) A gas chromatograph that meets the requirements in paragraphs
(d)(8)(ii)(B)(1) through (5) of this section.
(1) You must follow the procedure in Performance Specification 9 of
appendix B of this part, except that a single daily mid-level
calibration check can be used (rather than triplicate analysis), the
multi-point calibration can be conducted quarterly (rather than
monthly), and the sampling line temperature must be maintained at a
minimum temperature of 60 [deg]C (rather than 120 [deg]C). Calibration
gas cylinders must be certified to an accuracy of 2 percent and
traceable to National Institute of Standards and Technology (NIST)
standards.
(2) You must meet the accuracy requirements in Performance
Specification 9 of appendix B of this part.
(3) You must use a calibration gas or multiple gases that includes
the compounds that are reasonably expected to be present in the flare
gas stream. If multiple calibration gases are necessary to cover all
compounds, you must calibrate the instrument on all of the gases. You
may only use the compounds used to calibrate the gas chromatograph in
the calculation of the vent gas NHV.
(4) In lieu of the calibration gas described in paragraph
(d)(8)(ii)(B)(3) of this section, you may use a surrogate calibration
gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All
of the calibration gases may be combined in one cylinder. If multiple
calibration gases are necessary to cover all compounds, you must
calibrate the instrument on all of the gases. Use the response factor
for the nearest normal hydrocarbon (i.e., n-alkane) in the calibration
mixture to quantify unknown components detected in the analysis. Use
the response factor for n-pentane to quantify unknown components
detected in the analysis that elute after n-pentane.
(5) To determine the NHV of the vent gas, determine the product of
the volume fraction of the individual component in the vent gas and the
net heating value of that individual component. Sum the products for
all components in the vent gas to determine the NHV for the vent gas.
For the net heating value of each individual component, use the net
heating value at 25 [deg]C and 1 atmosphere.
(C) A mass spectrometer that meets the requirements in paragraphs
(d)(8)(ii)(C)(1) through (6) of this section.
(1) You must meet applicable requirements in Performance
[[Page 17105]]
Specification 9 of appendix B of this part for continuous monitoring
system acceptance including, but not limited to, performing an initial
multi-point calibration check at three concentrations following the
procedure in Section 10.1. A single daily mid-level calibration check
can be used (rather than triplicate analysis), the multi-point
calibration can be conducted quarterly (rather than monthly), and the
sampling line temperature must be maintained at a minimum temperature
of 60 [deg]C (rather than 120 [deg]C). Calibration gas cylinders must
be certified to an accuracy of 2 percent and traceable to NIST
standards.
(2) The average instrument calibration error (CE) for each
calibration compound at any calibration concentration must not differ
by more than 10 percent from the certified cylinder gas value. The CE
for each component in the calibration blend must be calculated using
the following equation:
[GRAPHIC] [TIFF OMITTED] TR08MR24.010
Where:
Cm = Average instrument response (ppm).
Ca = Certified cylinder gas value (ppm).
(3) You must use a calibration gas or multiple gases that includes
the compounds that are reasonably expected to be present in the flare
gas stream. If multiple calibration gases are necessary to cover all
compounds, you must calibrate the instrument on all of the gases. You
may only use the compounds used to calibrate the mass spectrometer in
the calculation of the vent gas NHV.
(4) In lieu of the calibration gas described in paragraph
(d)(8)(ii)(C)(3) of this section, you may use a surrogate calibration
gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All
of the calibration gases may be combined in one cylinder. If multiple
calibration gases are necessary to cover all compounds, you must
calibrate the instrument on all of the gases. For unknown gas
components that have similar analytical mass fragments to calibration
compounds, you may report the unknowns as an increase in the overlapped
calibration gas compound. For unknown compounds that produce mass
fragments that do not overlap calibration compounds, you may use the
response factor for the nearest molecular weight hydrocarbon in the
calibration mix to quantify the unknown component. You may use the
response factor for n-pentane to quantify any unknown components
detected with a higher molecular weight than n-pentane.
(5) You must perform an initial calibration to identify mass
fragment overlap and response factors for the target compounds.
(6) To determine the NHV of the vent gas, determine the product of
the volume fraction of the individual component in the vent gas and the
net heating value of that individual component. Sum the products for
all components in the vent gas to determine the NHV for the vent gas.
For the net heating value of each individual component, use the net
heating value at 25 [deg]C and 1 atmosphere.
(D) A grab sampling system capable of collecting an evacuated
canister sample for subsequent compositional analysis at least once
every eight hours. Subsequent compositional analysis of the samples
must be performed according to ASTM D1945-14 (R2019) (incorporated by
reference, see Sec. 60.17). To determine the NHV of the vent gas,
determine the product of the volume fraction of the individual
component in the vent gas and the net heating value of that individual
component. Sum the products for all components in the vent gas to
determine the NHV for the vent gas. For the net heating value of each
individual component, use the net heating value at 25 [deg]C and 1
atmosphere.
(iii) For an unassisted or pressure-assisted flare or enclosed
combustion device, if you demonstrate according to the methods
described in paragraphs (d)(8)(iii)(A) through (F) of this section that
the NHV of the inlet gas to the enclosed combustion device or flare
consistently exceeds the applicable operating limit specified in Sec.
60.5415b(f)(1)(vii)(B) or (C), continuous monitoring of the NHV is not
required, but you must conduct the ongoing sampling in paragraph
(d)(8)(iii)(G) of this section. For flares and enclosed combustion
devices that use only perimeter assist air and do not use steam assist
or premix assist air, if you demonstrate according to the methods
described in paragraphs (d)(8)(iii)(A) through (F) of this section that
the NHV of the inlet gas to the enclosed combustion device or flare
consistently exceeds 300 Btu/scf, continuous monitoring of the NHV is
not required, but you must conduct the ongoing sampling in paragraph
(d)(8)(iii)(G) of this section. For an unassisted or pressure-assisted
flare or enclosed combustion device, in lieu of conducting the
demonstration outlined in paragraphs (d)(8)(iii)(A) through (D) of this
section, you may conduct the demonstration outlined in paragraph
(d)(8)(iii)(H) of this section, but you must still comply with
paragraphs (d)(8)(iii)(E) through (G) of this section.
(A) Continuously monitor or collect a sample of the inlet gas to
the enclosed combustion device or flare twice daily to determine the
average NHV of the gas stream for 14 consecutive operating days. If you
do not continuously monitor the NHV, the minimum time of collection for
each individual sample be at least one hour. Consecutive samples must
be separated by at least 6 hours. If inlet gas flow is intermittent
such that there are not at least 28 samples over the 14 operating day
period, you must continue to collect samples of the inlet gas beyond
the 14 operating day period until you collect a minimum of 28 samples.
(B) If you collect samples twice per day, count the number of
samples where the NHV value is less than 1.2 times the applicable
operating limit specified in Sec. 60.5415b(f)(1)(vii)(B), (C), or
paragraph (d)(8)(iii) of this section (i.e., values that are less than
240, 360, or 960 Btu/scf, as applicable) during the sample collection
period in paragraph (d)(8)(iii)(A) of this section.
(C) If you continuously sample the inlet stream for 14 days, count
the number of hourly average NHV values that are less than the
applicable operating limit specified in Sec. 60.5415b(f)(1)(vii)(B),
Sec. 60.5415b(f)(1)(vii)(C)(1), or paragraph (d)(8)(iii) of this
section (i.e., values that are less than 200, 300, or 800 Btu/scf, as
applicable), during the sample collection period in paragraph
(d)(8)(iii)(A) of this section.
[[Page 17106]]
(D) If there are no samples counted under paragraph (d)(8)(iii)(B)
of this section or there are no hourly values counted under paragraph
(d)(8)(iii)(C) of this section, the gas stream is considered to
consistently exceed the applicable NHV operating limit and on-going
continuous monitoring is not required.
(E) If process operations are revised that could impact the NHV of
the gas sent to the enclosed combustion device or flare, such as the
removal or addition of process equipment, and at any time the
Administrator requires, re-evaluation of the gas stream must be
performed according to paragraphs (d)(8)(iii)(A) through (D) of this
section to ensure the gas stream still consistently exceeds the
applicable operating limit specified in Sec. 60.5415b(f)(1)(vii)(B),
(f)(1)(vii)(C)(1), or paragraph (d)(8)(iii) of this section.
(F) When collecting samples under paragraph (d)(8)(iii)(A) of this
section, the owner or operator must account for any sources of inert
gases that can be sent to the enclosed combustion device or flare
(e.g., streams from compressors in acid gas service, streams from
enhanced oil recovery facilities). The report in Sec.
60.5420b(b)(11)(v)(I) and the records of the demonstration in Sec.
60.5420b(c)(11)(vi) must note whether the enclosed combustion device or
flare has the potential to receive inert gases, and if so, whether the
sampling included periods where the highest percentage of inert gases
were sent to the enclosed combustion device or flare. If the
introduction of inerts is intermittent and does not occur during the
initial demonstration, the introduction of inerts will be considered a
revision to process operations that triggers a re-evaluation under
paragraph (d)(8)(iii)(E) of this section. If conditions at the site did
not allow sampling during periods where the introduction of inert gases
was at the highest percentage possible, increasing the percentage of
inerts will be considered a revision to process operations that
triggers a re-evaluation under paragraph (d)(8)(iii)(E) of this
section.
(G) You must collect three samples of the inlet gas to the enclosed
combustion device or flare at least once every 5 years. The minimum
time of collection for each individual sample must be at least one
hour. The samples must be taken during the period with the lowest
expected NHV (i.e., the period with the highest percentage of inerts).
The first set of periodic samples must be taken, or continuous
monitoring commenced, no later than 60 calendar months following the
last sample taken under paragraph (d)(8)(iii)(A) of this section.
Subsequent periodic samples must be taken, or continuous monitoring
commenced, no later than 60 calendar months following the previous
sample. If any sample has an NHV value less than 1.2 times the
applicable operating limit specified in Sec. 60.5415b(f)(1)(vii)(B),
Sec. 60.5415b(f)(1)(vii)(C), or paragraph (d)(8)(iii) of this section
(i.e., values that are less than 240, 360, or 960 Btu/scf, as
applicable), you must conduct the monitoring required by paragraph
(d)(8)(ii) of this section.
(H) You may request an alternative test method under Sec.
60.5412b(d) to demonstrate that the flare or enclosed combustion device
reduces methane and VOC in the gases vented to the device by 95.0
percent by weight or greater. You must use an alternative test method
that demonstrates compliance with the combustion efficiency limit; you
may not use an alternative test method that demonstrates compliance
with NHVcz and NHVdil in lieu of measuring
combustion efficiency directly. You must measure data values at the
frequency specified in the alternative test method and conduct the
quality assurance and quality control requirements outlined in the
alternative test method at the frequency outlined in the alternative
test method. You must monitor the combustion efficiency of the flare
continuously for 14 days. If there are no values of the combustion
efficiency measured by the alternative test method that are less than
95.0 percent, the gas stream is considered to consistently exceed the
applicable NHV operating limit, and you are not required to
continuously monitor the NHV of the inlet gas to the flare or enclosed
combustion device.
(iv) Except as noted in paragraphs (d)(8)(iv)(A) through (E) of
this section, a continuous parameter monitoring system for measuring
the flow of gas to the enclosed combustion device or flare. You may use
direct flow meters or other parameter monitoring systems combined with
engineering calculations, such as inlet line pressure, line size, and
burner nozzle dimensions, to satisfy this requirement. The monitoring
instrument must have an accuracy of 10 percent or better at
the maximum expected flow rate.
(A) Pressure-assisted flares and pressure-assisted enclosed
combustion devices are not required to have a continuous parameter
monitoring system for measuring the inlet flow of gas to the device if
you install, calibrate, maintain, and operate a backpressure regulator
valve calibrated to open at the minimum pressure set point
corresponding to the minimum inlet gas flow rate. The set point must be
consistent with manufacturer specifications for minimum flow or
pressure and must be supported by an engineering evaluation. At least
annually, you must confirm that the backpressure regulator valve set
point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(B) Unassisted flares are not required to have a continuous
parameter monitoring system for measuring the inlet flow of gas to the
device if you meet the conditions in paragraphs (d)(8)(iv)(B)(1) and
(2) of this section.
(1) You must demonstrate, based on the maximum potential pressure
of units manifolded to the flare and applicable engineering
calculations for the manifolded closed vent system, that the maximum
flow rate to the flare cannot cause the flare tip velocity to exceed
18.3 meter/second (60 feet/second). If there are changes to the process
or control device that can be reasonably expected to impact the maximum
flow rate to the flare, you must conduct a new demonstration to
determine whether the maximum flow rate to the flare is less than 18.3
meter/second (60 feet/second).
(2) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an engineering evaluation. At
least annually, you must confirm that the backpressure regulator valve
set point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(C) Unassisted enclosed combustion devices are not required to have
a continuous parameter monitoring system for measuring the inlet flow
of gas to the device if you meet the conditions in paragraphs
(d)(8)(iv)(C)(1) and (2) of this section.
(1) You must demonstrate, based on the maximum potential pressure
of units manifolded to the enclosed combustion device and applicable
engineering calculations for the manifolded closed vent system, that
the maximum flow rate to the enclosed combustion device cannot cause
the maximum inlet flow rate established in accordance with paragraph
(f)(1) of this section to be exceeded. If there are
[[Page 17107]]
changes to the process or control device that can be reasonably
expected to impact the maximum flow rate to the enclosed combustion
device, you must conduct a new demonstration to determine whether the
maximum flow rate to the enclosed combustor is less than the maximum
inlet flow rate established in accordance with paragraph (f)(1) of this
section.
(2) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an engineering evaluation. At
least annually, you must confirm that the backpressure regulator valve
set point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(D) Air-assisted flares or enclosed combustion devices that use
only perimeter assist air and have no assist steam or premix assist air
are not required to have a continuous parameter monitoring system for
measuring the inlet flow of gas to the device or the flow of assist air
if you meet the conditions in paragraphs (d)(8)(iv)(D)(1) and (2) of
this section. For these flares and enclosed combustion devices,
NHVcz is assumed to be equal to the vent gas NHV.
(1) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an engineering evaluation. At
least annually, you must confirm that the backpressure regulator valve
set point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(2) You must demonstrate, based on the maximum flow rate of
perimeter assist air to the enclosed combustion device or flare and
applicable engineering calculations, that the NHVdil can
never be less than the minimum required NHVdil. The
demonstration must clearly document why the maximum flow rate of
perimeter assist air will never exceed the rate used in the
demonstration. You must use the minimum flow rate of vent gas allowed
by your backpressure regulator valve and the minimum expected value of
the NHV of the inlet gas to the enclosed combustion device or flare
based on previous sampling results or process knowledge of the streams
sent to the enclosed combustion device or flare in your demonstration.
You must update this demonstration if there are changes to the
backpressure regulator valve, the backpressure regulator valve set
point, or the maximum flow rate of perimeter assist air. You must also
update this demonstration if any sampling results of the NHV of the
inlet gas to the enclosed combustion device or flare under paragraphs
(d)(8)(ii) or (iii) of this section are lower than the NHV vent gas
value used in your demonstration.
(E) Air-assisted flares or enclosed combustion devices that use
only premix assist air and have no assist steam or perimeter assist air
are not required to have a continuous parameter monitoring system for
measuring the inlet flow of gas to the device or the flow of assist air
if you meet the conditions in paragraphs (d)(8)(iv)(E)(1) and (2) of
this section.
(1) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an engineering evaluation. At
least annually, you must confirm that the backpressure regulator valve
set point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(2) You must demonstrate, based on the maximum flow rate of premix
assist air to the enclosed combustion device or flare and applicable
engineering calculations, that the NHVcz will never be less
than the minimum required NHVcz. The demonstration must
clearly document why the maximum flow rate of premix assist air will
never exceed the rate used in the demonstration. You must use the
minimum flow rate of vent gas allowed by your backpressure regulator
valve in and the minimum expected value of the NHV of the inlet gas to
the enclosed combustion device or flare based on previous sampling
results or process knowledge of the streams sent to the enclosed
combustion device or flare in your demonstration. You must update this
demonstration if there are changes to the backpressure regulator valve,
the backpressure regulator valve set point, or the maximum flow rate of
premix assist air. You must also update this demonstration if any
sampling results of the NHV of the inlet gas to the enclosed combustion
device or flare under paragraphs (d)(8)(ii) or (iii) of this section
are lower than the NHV vent gas value used in your demonstration.
(v) Conduct inspections monthly and at other times as requested by
the Administrator to monitor for visible emissions from the combustion
device using section 11 of Method 22 of appendix A of this part or
conduct visible emissions monitoring according to paragraph (h) of this
section. The observation period shall be 15 minutes or once the amount
of time visible emissions is present has exceeded 1 minute. Devices
must be operated with no visible emissions, except for periods not to
exceed a total of 1 minute during any 15-minute period.
(vi) If you use a flare or enclosed combustion device that is air-
assisted or steam-assisted, you must also meet the following
requirements.
(A) Except as allowed by paragraph (d)(8)(iv)(E) of this section,
you must monitor and calculate NHVcz as specified in Sec.
63.670(m) of this chapter. Additionally, for flares and enclosed
combustion devices that use only perimeter assist air and do not use
steam assist or premix assist air, the NHVcz is equal to the
vent gas NHV. When NHVcz is equal to the vent gas NHV, you
are not required to continuously monitor NHVcz if you meet
the requirements in paragraph (d)(8)(iii) of this section.
(B) Except as allowed by paragraph (d)(8)(iv)(D) of this section,
for each flare using perimeter assist air, you must also monitor and
calculate NHVdil as specified in Sec. 63.670(n) of this
chapter. If the only assist air provided to the flare or enclosed
combustion control device is perimeter assist air intentionally
entrained in lower and/or upper steam at the flare tip and the
effective diameter is 9 inches or greater, you are only required to
comply with the NHVcz limit specified in paragraph
(f)(8)(vi)(A) of this section.
(C) Except as allowed by paragraph (d)(8)(iv) of this section, you
must monitor the flare vent gas and assist gas as specified in Sec.
63.670(i) of this chapter.
(D) You must determine the flare vent gas net heating value as
specified in Sec. 63.670(l) of this chapter using one of the methods
specified in paragraph (d)(8)(ii) of this section. Where the phrase
``petroleum refinery'' is used, for purposes of this subpart, it will
refer to flares controlling an affected facility under this subpart. If
you are not
[[Page 17108]]
required to continuously monitor the NHV of the inlet gas because you
have demonstrated that it consistently exceeds the applicable operating
limit as provided in paragraph (d)(8)(iii) of this section, you must
use the lowest net heating value measured in the sampling program in
paragraph (d)(8)(iii) of this section for the calculations performed in
paragraphs (d)(8)(vi)(A) and (B). You must update this value if a
subsequent sampling result of the NHV of the inlet gas to the enclosed
combustion device or flare under paragraph (d)(8)(iii) of this section
is lower than the NHV vent gas value used in your calculations.
(e) Calculate the value of the applicable monitored parameter in
accordance with paragraphs (e)(1) through (5) of this section.
(1) You must calculate the daily average value for condenser outlet
temperature for each operating day, using the data recorded by the
monitoring system. If the emissions unit operation is continuous, the
operating day is a 24-hour period. If the emissions unit operation is
not continuous, the operating day is the total number of hours of
control device operation per 24-hour period. Valid data points must be
available for 75 percent of the operating hours in an operating day to
compute the daily average.
(2) You must use the 5-minute readings from the heat sensing
devices to assess the presence of a pilot or combustion flame.
(3) You must use the regeneration cycle time (i.e., duration of the
carbon bed steaming cycle) for each regenerative-type carbon adsorption
system to calculate the average parameter to compare with the maximum
steam mass flow or volumetric flow during each carbon bed regeneration
cycle and the maximum carbon bed temperature during the steaming cycle.
The carbon bed temperature after the regeneration cycle should not be
averaged; you must use the carbon bed temperature measured within 15
minutes of completing the cooling cycle to compare with the minimum
carbon bed temperature after the regeneration cycle.
(4) You must use 15-minute blocks to calculate NHVcz and
NHVdil.
(5) For all operating parameters others than those described in
paragraphs (e)(1) through (4) of this section, you must calculate the
3-hour rolling average of each monitored parameter. For each operating
hour, calculate the hourly value of the operating parameter from your
continuous monitoring system. Average the three most recent hours of
data to determine the 3-hour average. Determine the 3-hour rolling
average by recalculating the 3-hour average each hour.
(f) For each operating parameter monitor installed in accordance
with the requirements of paragraph (d) of this section, you must comply
with paragraph (f)(1) of this section for all control devices. When
condensers are installed, you must also comply with paragraph (f)(2) of
this section.
(1) You must establish a minimum operating parameter value or a
maximum operating parameter value, as appropriate for the control
device, to define the conditions at which the control device must be
operated to continuously achieve the applicable performance
requirements of Sec. 60.5412b(a)(1) or (2). You must establish each
minimum or maximum operating parameter value as specified in paragraphs
(f)(1)(i) through (iv) of this section.
(i) If you conduct performance tests in accordance with the
requirements of Sec. 60.5413b(b) to demonstrate that the control
device achieves the applicable performance requirements specified in
Sec. 60.5412b(a)(1) or (2), then you must establish the minimum
operating parameter value or the maximum operating parameter value
based on values measured during the performance test and supplemented,
as necessary, by a condenser or carbon adsorption system design
analysis or control device manufacturer recommendations or a
combination of both. If you operate an enclosed combustion device, you
must establish the maximum inlet flow rate based on values measured
during the performance test and you may establish the minimum inlet
flow rate based on control device manufacturer recommendations.
(ii) If you use a condenser or carbon adsorption system design
analysis in accordance with the requirements of Sec. 60.5413b(c) to
demonstrate that the control device achieves the applicable performance
requirements specified in Sec. 60.5412b(a)(2), then you must establish
the minimum operating parameter value or the maximum operating
parameter value based on the design analysis and supplemented, as
necessary, by the manufacturer's recommendations.
(iii) If you operate a control device where the performance test
requirement was met under Sec. 60.5413b(d) to demonstrate that the
control device achieves the applicable performance requirements
specified in Sec. 60.5412b(a)(1), then your control device inlet gas
flow rate must be equal to or greater than the minimum inlet gas flow
rate and equal to or less than the maximum inlet gas flow rate
determined by the manufacturer.
(iv) If you operate an enclosed combustion device where the
combustion zone temperature is not an indicator of destruction
efficiency or a control device where the performance test requirement
was met under Sec. 60.5413b(d), you must maintain the NHV of the gas
sent to the enclosed combustion device, the NHVcz, and the
NHVdil above the applicable limits specified in paragraphs
Sec. 60.5412b(a)(1)(iv)(A) through (D).
(2) If you use a condenser as specified in paragraph (d)(1)(v) of
this section, you must establish a condenser performance curve showing
the relationship between condenser outlet temperature and condenser
control efficiency, according to the requirements of paragraphs
(f)(2)(i) and (ii) of this section.
(i) If you conduct a performance test in accordance with the
requirements of Sec. 60.5413b(b) to demonstrate that the condenser
achieves the applicable performance requirements of Sec.
60.5412b(a)(2), then the condenser performance curve must be based on
values measured during the performance test and supplemented as
necessary by control device design analysis, or control device
manufacturer's recommendations, or a combination or both.
(ii) If you use a control device design analysis in accordance with
the requirements of Sec. 60.5413b(c)(1) to demonstrate that the
condenser achieves the applicable performance requirements specified in
Sec. 60.5412b(a)(2), then the condenser performance curve must be
based on the condenser design analysis and supplemented, as necessary,
by the control device manufacturer's recommendations.
(g) A deviation for a control device is determined to have occurred
when the monitoring data or lack of monitoring data result in any one
of the criteria specified in paragraphs (g)(1) through (7) of this
section being met. If you monitor multiple operating parameters for the
same control device during the same operating day and more than one of
these operating parameters meets a deviation criterion specified in
paragraphs (g)(1) through (7) of this section, then a single excursion
is determined to have occurred for the control device for that
operating day.
(1) A deviation occurs when the average value of a monitored
operating parameter determined in accordance with paragraph (e) of this
section is less than the minimum operating parameter limit (and, if
applicable, greater than the
[[Page 17109]]
maximum operating parameter limit) established in paragraph (f)(1) of
this section; for flares, when the average value of a monitored
operating parameter determined in accordance with paragraph (e) of this
section is above the limits specified in Sec. 60.5415b(f)(1)(vii)(B);
or when the heat sensing device indicates that there is no pilot or
combustion flame present for any time period. If you use a backpressure
regulator valve to maintain the inlet gas flow to an enclosed
combustion device or flare above the minimum value, a deviation occurs
if the annual inspection finds that the backpressure regulator valve
set point is not set correctly or indicates that the backpressure
regulator valve does not fully close when not in the open position.
(2) If you are subject to Sec. 60.5412b(a)(2), a deviation occurs
when the 365-day average condenser efficiency calculated according to
the requirements specified in Sec. 60.5415b(f)(1)(ix)(D) is less than
95.0 percent.
(3) If you are subject to Sec. 60.5412b(a)(2) and you have less
than 365 days of data, a deviation occurs when the average condenser
efficiency calculated according to the procedures specified in Sec.
60.5415b(f)(1)(ix)(D)(1) or (2) is less than 95.0 percent.
(4) A deviation occurs when the monitoring data are not available
for at least 75 percent of the operating hours in a day.
(5) If the closed vent system contains one or more bypass devices
that could be used to divert all or a portion of the gases, vapors, or
fumes from entering the control device, a deviation occurs when the
requirements of paragraph (g)(5)(i) or (ii) of this section are met.
(i) For each bypass line subject to Sec. 60.5411b(a)(4)(i)(A), the
flow indicator indicates that flow has been detected and that the
stream has been diverted away from the control device to the
atmosphere.
(ii) For each bypass line subject to Sec. 60.5411b(a)(4)(i)(B), if
the seal or closure mechanism has been broken, the bypass line valve
position has changed, the key for the lock-and-key type lock has been
checked out, or the car-seal has broken.
(6) For a combustion control device whose model is tested under
Sec. 60.5413b(d), a deviation occurs when the conditions of paragraph
(g)(4), (5), or (6)(i) through (vi) of this section are met.
(i) The hourly inlet gas flow rate is less than the minimum inlet
gas flow rate or greater than the maximum inlet gas flow rate
determined by the manufacturer. If you use a backpressure regulator
valve to maintain the inlet gas flow above the minimum value, a
deviation occurs if the annual inspection finds that the backpressure
regulator valve set point is not set correctly or indicates that the
backpressure regulator valve does not fully close when not in the open
position.
(ii) Results of the monthly visible emissions test conducted under
Sec. 60.5413b(e)(3) or monitoring under paragraph (h) of this section
indicate visible emissions exceed 1 minute in any 15-minute period.
(iii) There is no indication of the presence of a pilot or
combustion flame for any 5-minute time period.
(iv) The control device is not maintained in a leak free condition.
(v) The control device is not operated in accordance with the
manufacturer's written operating instructions, procedures and
maintenance schedule.
(vi) The NHV of the vent gas, the NHVcz, or the
NHVdil is below the applicable limit specified in Sec.
60.5412b(a)(1)(iv).
(7) For an enclosed combustion device or flare subject to paragraph
(d)(8) of this section, a deviation occurs when any of the conditions
described by paragraphs (g)(1), (4) or (5) of this section are met or
when the results of the visible emissions monitoring conducted under
paragraph (d)(8)(v) or (h) of this section exceed 1 minute in any 15-
minute period.
(h) For enclosed combustion devices and flares, in lieu of
conducting a visible emissions observation using Method 22 of appendix
A-7 to this part, you may use a video surveillance camera to
continuously monitor and record the flare flame according to the
requirements in paragraphs (h)(1) through (6) of this section.
(1) You must provide real-time high-definition video surveillance
camera output (i.e., at least 720p) at a frame rate of at least 15
frames per second to the control room or other continuously manned
location where the camera images may be viewed at the same resolution
at any time.
(2) You must record at least one frame every 15 seconds with date
and time stamp.
(3) The camera must be located at a reasonable distance above the
flare flame at an angle suitable for visual emissions observations. The
position of the camera should be such that the sun is not in the field
of view.
(4) The camera must be located no more than 400 m (0.25 miles) from
the emission source.
(5) Operators must look at the video feed at least once daily for
an observation period of at least 1 minute to determine if visible
emissions are present. If visible emissions are present during a daily
observation, the operator must observe the video feed for 15 minutes or
until the amount of time visible emissions is present has exceeded 1
minute, whichever time period is less.
(6) Enclosed combustion devices and flares must be operated with no
visible emissions, except for periods not to exceed a total of 1 minute
during any 15-minute period.
(i) If you use an enclosed combustion device or flare using an
alternative test method approved under Sec. 60.5412b(d), you must
comply with paragraphs (i)(1) through (6) of this section.
(1) You must measure data values at the frequency specified in the
alternative test method.
(2) You must prepare a monitoring plan that covers each control
device for affected facilities within each company-defined area. The
monitoring plan must address the monitoring system design, data
collection, and the quality assurance and quality control elements
outlined in the alternative test method and in paragraphs (i)(2)(i)
through (iii) of this section. You must operate and maintain each
monitoring system in accordance with the procedures in your monitoring
plan.
(i) The performance criteria and design specifications for the
monitoring system equipment.
(ii) Location of monitoring system in relation to the monitored
control device.
(iii) Ongoing reporting and recordkeeping procedures.
(3) You must conduct the quality assurance and quality control
requirements outlined in the alternative test method at the frequency
outlined in the alternative test method.
(4) If required by Sec. 5412b(d)(4), you must conduct the
inspections required by paragraph (d)(8)(v) of this section.
(5) If required by Sec. 5412b(d)(5), you must install the pilot or
combustion flame monitoring system required by paragraph (d)(8)(i) of
this section.
(6) A deviation for the control device is determined to have
occurred when the monitoring data or lack of monitoring data result in
any one of the criteria specified in paragraphs (i)(6)(i) through (v)
of this section being met.
(i) A deviation occurs if the combustion efficiency is less than
95.0 percent, the combustion zone NHV is less than 270 Btu/scf, or the
NHV dilution parameter is less than 22 Btu/sqft.
(ii) A deviation occurs when the monitoring data are not available
for at
[[Page 17110]]
least 75 percent of the operating hours in a day.
(iii) A deviation occurs when any of the conditions described by
paragraph (g)(5) of this section are met.
(iv) If required by paragraph (i)(4) of this section to conduct
visible emissions inspections, a deviation occurs when the results of
the visible emissions monitoring conducted under paragraph (d)(8)(v) or
(h) of this section exceeds 1 minute in any 15-minute period.
(v) If required by paragraph (i)(5) of this section to install a
pilot or combustion flame monitoring system, a deviation occurs when
there is no indication of the presence of a pilot or combustion flame
for any 5-minute period.
(j) You must submit annual reports for control devices as required
in Sec. 60.5420b(b)(1) and (11). You must maintain records as
specified in Sec. 60.5420b(c)(1).
Sec. 60.5420b What are my notification, reporting, and recordkeeping
requirements?
(a) Notifications. You must submit notifications according to
paragraphs (a)(1) and (2) of this section if you own or operate one or
more of the affected facilities specified in Sec. 60.5365b that was
constructed, modified, or reconstructed during the reporting period.
You must submit the notification in paragraph (a)(3) of this section if
you use an alternative standard for fugitive emissions components in
accordance with Sec. 60.5399b. You must submit the notification in
paragraph (a)(4) of this section if you undertake well closure
activities as specified in Sec. 60.5397b(l).
(1) If you own or operate a process unit equipment affected
facility located at an onshore natural gas processing plant, or a
sweetening unit, you must submit the notifications required in
Sec. Sec. 60.7(a)(1), (3), and (4) and 60.15(d). If you own or operate
a well, centrifugal compressor, reciprocating compressor, process
controller, pump, storage vessel, collection of fugitive emissions
components at a well site, or collection of fugitive emissions
components at a compressor station affected facility, you are not
required to submit the notifications required in Sec. Sec. 60.7(a)(1),
(3), and (4) and 60.15(d).
(2) If you own or operate a well affected facility, you must notify
the Administrator no later than 2 days prior to the commencement of
each well completion operation listing the anticipated date of the well
completion operation. The notification shall include contact
information for the owner or operator; the United States Well Number;
the latitude and longitude coordinates for each well in decimal degrees
to an accuracy and precision of five (5) decimals of a degree using the
North American Datum of 1983; and the planned date of the beginning of
flowback. You may submit the notification in writing or in electronic
format. If you are subject to state regulations that require advance
notification of well completions and you have met those notification
requirements, then you are considered to have met the advance
notification requirements of this paragraph.
(3) An owner or operator electing to comply with the provisions of
Sec. 60.5399b for fugitive emissions components shall notify the
Administrator of the alternative fugitive emissions standard selected
within the annual report, as specified in paragraph (b)(9)(iii) of this
section.
(4) An owner or operator who commences well closure activities must
submit the following notices to the Administrator according to the
schedule in paragraph (a)(4)(i) and (ii) of this section. The
notification shall include contact information for the owner or
operator; the United States Well Number; the latitude and longitude
coordinates for each well at the well site in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using the North
American Datum of 1983. You must submit notifications in portable
document format (PDF) following the procedures specified in paragraph
(d) of this section.
(i) You must submit a well closure plan to the Administrator within
30 days of the cessation of production from all wells located at the
well site.
(ii) You must submit a notification of the intent to close a well
site 60 days before you begin well closure activities.
(b) Reporting requirements. You must submit annual reports
containing the information specified in paragraphs (b)(1) through (14)
of this section following the procedure specified in paragraph (b)(15)
of this section. You must submit performance test reports as specified
in paragraph (b)(12) or (13) of this section, if applicable. The
initial annual report is due no later than 90 days after the end of the
initial compliance period as determined according to Sec. 60.5410b.
Subsequent annual reports are due no later than the same date each year
as the initial annual report. If you own or operate more than one
affected facility, you may submit one report for multiple affected
facilities provided the report contains all of the information required
as specified in paragraphs (b)(1) through (14) of this section. Annual
reports may coincide with title V reports as long as all the required
elements of the annual report are included. You may arrange with the
Administrator a common schedule on which reports required by this part
may be submitted as long as the schedule does not extend the reporting
period. You must submit the information in paragraph (b)(1)(v) of this
section, as applicable, for your well affected facility which undergoes
a change of ownership during the reporting period, regardless of
whether reporting under paragraphs (b)(2) through (4) of this section
is required for the well affected facility.
(1) The general information specified in paragraphs (b)(1)(i)
through (v) of this section is required for all reports.
(i) The company name, facility site name associated with the
affected facility, U.S. Well ID or U.S. Well ID associated with the
affected facility, if applicable, and address of the affected facility.
If an address is not available for the site, include a description of
the site location and provide the latitude and longitude coordinates of
the site in decimal degrees to an accuracy and precision of five (5)
decimals of a degree using the North American Datum of 1983.
(ii) An identification of each affected facility being included in
the annual report.
(iii) Beginning and ending dates of the reporting period.
(iv) A certification by a certifying official of truth, accuracy,
and completeness. This certification shall state that, based on
information and belief formed after reasonable inquiry, the statements
and information in the document are true, accurate, and complete. If
your report is submitted via CEDRI, the certifier's electronic
signature during the submission process replaces the requirement in
this paragraph (b)(1)(iv).
(v) Identification of each well affected facility for which
ownership changed due to sale or transfer of ownership including the
United States Well Number; the latitude and longitude coordinates of
the well affected facility in decimal degrees to an accuracy and
precision of five (5) decimals of a degree using the North American
Datum of 1983; and the information in paragraph (b)(1)(v)(A) or (B) of
this section, as applicable.
(A) The name and contact information, including the phone number,
email address, and mailing address, of the owner or operator to which
you sold or transferred ownership of the well affected facility
identified in paragraph (b)(v) of this section.
[[Page 17111]]
(B) The name and contact information, including the phone number,
email address, and mailing address, of the owner or operator from whom
you acquired the well affected facility identified in paragraph (b)(v)
of this section.
(2) For each well affected facility that is subject to Sec.
60.5375b(a) or (f), the records of each well completion operation
conducted during the reporting period, including the information
specified in paragraphs (b)(2)(i) through (xiv) of this section, if
applicable. In lieu of submitting the records specified in paragraphs
(b)(2)(i) through (xiv) of this section, the owner or operator may
submit a list of each well completion with hydraulic fracturing
completed during the reporting period, and the digital photograph
required by paragraph (c)(1)(v) of this section for each well
completion. For each well affected facility that routes all flowback
entirely through one or more production separators, only the records
specified in paragraphs (b)(2)(i) through (iv) and (vi) of this section
are required to be reported. For periods where salable gas is unable to
be separated, the records specified in paragraphs (b)(2)(iv) and (viii)
through (xii) of this section must also be reported, as applicable. For
each well affected facility that is subject to Sec. 60.5375b(g), the
record specified in paragraph (b)(2)(xv) of this section is required to
be reported. For each well affected facility which makes a claim that
the exemption in Sec. 60.5375b(h) was met, the records specified in
paragraph (b)(2)(i) through (iv) and (b)(2)(xvi) of this section are
required to be reported.
(i) Well Completion ID.
(ii) Latitude and longitude of the well in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using North
American Datum of 1983.
(iii) U.S. Well ID.
(iv) The date and time of the onset of flowback following hydraulic
fracturing or refracturing or identification that the well immediately
starts production.
(v) The date and time of each attempt to direct flowback to a
separator as required in Sec. 60.5375b(a)(1)(ii).
(vi) The date and time that the well was shut in and the flowback
equipment was permanently disconnected, or the startup of production.
(vii) The duration (in hours) of flowback.
(viii) The duration (in hours) of recovery and disposition of
recovery (i.e., routed to the gas flow line or collection system, re-
injected into the well or another well, used as an onsite fuel source,
or used for another useful purpose that a purchased fuel or raw
material would serve).
(ix) The duration (in hours) of combustion.
(x) The duration (in hours) of venting.
(xi) The specific reasons for venting in lieu of capture or
combustion.
(xii) For any deviations recorded as specified in paragraph
(c)(1)(ii) of this section, the date and time the deviation began, the
duration of the deviation in hours, and a description of the deviation.
(xiii) For each well affected facility subject to Sec.
60.5375b(f), a record of the well type (i.e., wildcat well, delineation
well, or low pressure well (as defined Sec. 60.5430b)) and supporting
inputs and calculations, if applicable.
(xiv) For each well affected facility for which you claim an
exception under Sec. 60.5375b(a)(2), the specific exception claimed
and reasons why the well meets the claimed exception.
(xv) For each well affected facility with less than 300 scf of gas
per stock tank barrel of oil produced, the supporting analysis that was
performed in order the make that claim, including but not limited to,
GOR values for established leases and data from wells in the same basin
and field.
(xvi) For each well affected facility which meets the exemption in
Sec. 60.5375b(h), a statement that the well completion operation
requirements of Sec. 60.5375b(a)(1) through (3) were met.
(3) For each well affected facility that is subject to Sec.
60.5376b(a)(1) or (2), your annual report is required to include the
information specified in paragraphs (b)(3)(i) and (ii) of this section,
as applicable.
(i) For each well affected facility where all gas well liquids
unloading operations comply with Sec. 60.5376b(a)(1), your annual
report must include the information specified in paragraphs
(b)(3)(i)(A) through (C) of this section, as applicable.
(A) Identification of each well affected facility (U.S. Well ID or
U.S. Well ID associated with the well affected facility) that conducts
a gas well liquid unloading operation during the reporting period using
a method that does not vent to the atmosphere and the technology or
technique used. If more than one non-venting technology or technique is
used, you must identify all of the differing non-venting liquids
unloading methods used during the reporting period.
(B) Number of gas well liquids unloading operations conducted
during the year where the well affected facility identified in
(b)(3)(i)(A) had unplanned venting to the atmosphere and best
management practices were conducted according to your best management
practice plan, as required by Sec. 60.5376b(c). If no venting events
occurred, the number would be zero. Other reported information required
to be submitted where unplanned venting occurs is specified in
paragraphs (b)(3)(i)(B)(1) and (2) of this section.
(1) Log of best management practice plan steps used during the
unplanned venting to minimize emissions to the maximum extent possible.
(2) The number of liquids unloading events during the year where
deviations from your best management practice plan occurred, the date
and time the deviation began, the duration of the deviation in hours,
documentation of why best management practice plan steps were not
followed, and what steps, in lieu of your best management practice plan
steps, were followed to minimize emissions to the maximum extent
possible.
(C) The number of liquids unloading events where unplanned
emissions are vented to the atmosphere during a gas well liquids
unloading operation where you complied with best management practices
to minimize emissions to the maximum extent possible.
(ii) For each well affected facility where all gas well liquids
unloading operations comply with Sec. 60.5376b(b) and (c) best
management practices, your annual report must include the information
specified in paragraphs (b)(3)(ii)(A) through (E) of this section.
(A) Identification of each well affected facility that conducts a
gas well liquids unloading during the reporting period.
(B) Number of liquids unloading events conducted during the
reporting period.
(C) Log of best management practice plan steps used during the
reporting period to minimize emissions to the maximum extent possible.
(D) The number of liquids unloading events during the year that
best management practices were conducted according to your best
management practice plan.
(E) The number of liquids unloading events during the year where
deviations from your best management practice plan occurred, the date
and time the deviation began, the duration of the deviation in hours,
documentation of why best management practice plan steps were not
followed, and what steps, in lieu of your best management practice plan
steps, were followed to minimize emissions to the maximum extent
possible.
(4) For each associated gas well subject to Sec. 60.5377b, your
annual report is required to include the applicable information
specified in
[[Page 17112]]
paragraphs (b)(4)(i) through (vi) of this section, as applicable.
(i) For each associated gas well that complies with Sec.
60.5377b(a)(1), (2), (3), or (4) your annual report is required to
include the information specified in paragraphs (b)(4)(i)(A) and (B) of
this section.
(A) An identification of each associated gas well constructed,
modified, or reconstructed during the reporting period that complies
with Sec. 60.5377b(a)(1), (2), (3), or (4).
(B) The information specified in paragraphs (b)(2)(i)(B)(1) through
(3) of this section for each incident when the associated gas was
temporarily routed to a flare or control device in accordance with
Sec. 60.5377b(d)
(1) The reason in Sec. 60.5377b(d)(1), (2), (3), or (4) for each
incident.
(2) The start date and time of each incident of routing associated
gas to the flare or control device, along with the total duration in
hours of each incident.
(3) Documentation that all CVS requirements specified in Sec.
60.5411b(a) and (c) and all applicable flare or control device
requirements specified in Sec. 60.5412b were met during each period
when the associated gas is routed to the flare or control device.
(ii) For all instances where you temporarily vent the associated
gas in accordance with Sec. 60.5377b(e), you must report the
information specified in paragraphs (b)(4)(ii)(A) through (D) of this
section. This information is required to be reported if you are
routinely complying with Sec. 60.5377b(a) or Sec. 60.5377b(f) or
temporarily complying with Sec. 60.5377b(d). In addition to this
information for each incident, you must report the cumulative duration
in hours of venting incidents and the cumulative VOC and methane
emissions in pounds for all incidents in the calendar year.
(A) The reason in Sec. 60.5377b(e)(1), (2), or (3) for each
incident.
(B) The start date and time of each incident of venting the
associated gas, along with the total duration in hours of each
incident.
(C) The VOC and methane emissions in pounds that were emitted
during each incident.
(D) The total duration of venting for all incidents in the year,
along with the cumulative VOC and methane emissions in pounds that were
emitted.
(iii) For each associated gas well that complies with the
requirements of Sec. 60.5377b(f) your annual report must include the
information specified in paragraphs (b)(4)(iii)(A) through (E) of this
section. The information in paragraphs (b)(4)(iii)(A) and (B) of this
section is only required in the initial annual report.
(A) An identification of each associated gas well that commenced
construction between May 7, 2024 and May 7, 2026. This identification
must include the certification of why it is infeasible to comply with
Sec. 60.5377b(a)(1), (2), (3), or (4) in accordance with Sec.
60.5377b(g).
(B) An identification of each associated gas well that commenced
construction between December 6, 2022, and May 7, 2024. This
identification must include the certification of why it is infeasible
to comply with Sec. 60.5377b(a)(1), (2), (3), or (4) in accordance
with Sec. 60.5377b(g).
(C) An identification of each associated gas well modified or
reconstructed during the reporting period that complies by routing the
gas to a control device that reduces VOC and methane emissions by at
least 95.0 percent. This identification must include the certification
of why it is infeasible to comply with Sec. 60.5377b(a)(1), (2), (3),
or (4) in accordance with Sec. 60.5377b(g).
(D) For each associated gas well that was constructed, modified or
reconstructed in a previous reporting period that complies by routing
the gas to a control device that reduces VOC and methane emissions by
at least 95.0 percent, a re-certification of why it is infeasible to
comply with Sec. 60.5377b(a)(1), (2), (3), or (4) in accordance with
Sec. 60.5377b(g).
(E) The information specified in paragraphs (b)(11)(i) through (iv)
of this section.
(iv) If you comply with Sec. 60.5377b(f) with a control device,
identification of the associated gas well using the control device and
the information in paragraph (b)(11)(v) of this section.
(v) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(b)(11)(i) and (ii) of this section, you must provide the information
specified in Sec. 60.5424b.
(vi) For each deviation recorded as specified in paragraph
(c)(3)(v) of this section, the date and time the deviation began, the
duration of the deviation in hours, and a description of the deviation.
If no deviations occurred during the reporting period, you must include
a statement that no deviations occurred during the reporting period.
(5) For each wet seal centrifugal compressor affected facility, the
information specified in paragraphs (b)(5)(i) through (v) of this
section. For each self-contained wet seal centrifugal compressor,
Alaska North Slope centrifugal compressor equipped with sour seal oil
separator and capture system, or dry seal centrifugal compressor
affected facility, the information specified in paragraphs (b)(5)(vi)
through (ix) of this section.
(i) An identification of each centrifugal compressor constructed,
modified, or reconstructed during the reporting period.
(ii) For each deviation that occurred during the reporting period
and recorded as specified in paragraph (c)(4) of this section, the date
and time the deviation began, the duration of the deviation in hours,
and a description of the deviation. If no deviations occurred during
the reporting period, you must include a statement that no deviations
occurred during the reporting period.
(iii) If required to comply with Sec. 60.5380b(a)(2), the
information specified in paragraphs (b)(11)(i) through (iv) of this
section.
(iv) If complying with Sec. 60.5380b(a)(1) with a control device,
identification of the centrifugal compressor with the control device
and the information in paragraph (b)(11)(v) of this section.
(v) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(b)(11)(i) and (ii) of this section, you must provide the information
specified in Sec. 60.5424b.
(vi) If complying with Sec. 60.5380b(a)(4) or (5) for a self-
contained wet seal centrifugal compressor, Alaska North Slope
centrifugal compressor equipped with sour seal oil separator and
capture system, or dry seal centrifugal compressor requirements, the
cumulative number of hours of operation since initial startup, since
May 7, 2024, or since the previous volumetric flow rate emissions
measurement, as applicable, which have elapsed prior to conducting your
volumetric flow rate emission measurement or emissions screening.
(vii) A description of the method used and the results of the
volumetric emissions measurement or emissions screening, as applicable.
(viii) Number and type of seals on delay of repair and explanation
for each delay of repair.
(ix) Date of planned shutdown(s) that occurred during the reporting
period if there are any seals that have been placed on delay of repair.
(6) For each reciprocating compressor affected facility, the
information specified in paragraphs (b)(6)(i) through (vii) of this
section, as applicable.
(i) The cumulative number of hours of operation since initial
startup, since May 7, 2024, or since the previous volumetric flow rate
measurement, or since the previous reciprocating
[[Page 17113]]
compressor rod packing replacement, as applicable, which have elapsed
prior to conducting your volumetric flow rate measurement or emissions
screening. Alternatively, a statement that emissions from the rod
packing are being routed to a process or control device through a
closed vent system.
(ii) If applicable, for each deviation that occurred during the
reporting period and recorded as specified in paragraph (c)(5)(i) of
this section, the date and time the deviation began, duration of the
deviation in hours and a description of the deviation. If no deviations
occurred during the reporting period, you must include a statement that
no deviations occurred during the reporting period.
(iii) A description of the method used and the results of the
volumetric flow rate measurement or emissions screening, as applicable.
(iv) If complying with Sec. 60.5385b(d), the information in
paragraphs (b)(11)(i) through (iv) of this section.
(v) Number and type of rod packing replacements/repairs on delay of
repair and explanation for each delay of repair.
(vi) Date of planned shutdown(s) that occurred during the reporting
period if there are any rod packing replacements/repairs that have been
placed on delay of repair.
(vii) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(b)(11)(i) and (ii) of this section, you must provide the information
specified in Sec. 60.5424b.
(7) For each process controller affected facility, the information
specified in paragraphs (b)(7)(i) through (iii) of this section in your
initial annual report and in subsequent annual reports for each process
controller affected facility that is constructed, modified, or
reconstructed during the reporting period. Each annual report must
contain the information specified in paragraphs (b)(7)(iv) through (x)
of this section for each process controller affected facility.
(i) An identification of each process controller that is driven by
natural gas, as required by Sec. 60.5390b(d), that allows traceability
to the records required in paragraph (c)(6)(i) of this section.
(ii) For each process controller in the affected facility complying
with Sec. 60.5390b(a), you must report the information specified in
paragraphs (b)(7)(ii)(A) and (B) of this section, as applicable.
(A) An identification of each process controller complying with
Sec. 60.5390b(a) by routing the emissions to a process.
(B) An identification of each process controller complying with
Sec. 60.5390b(a) by using a self-contained natural gas-driven process
controller.
(iii) For each process controller affected facility located at a
site in Alaska that does not have access to electrical power and that
complies with Sec. 60.5390b(b), you must report the information
specified in paragraphs (b)(7)(iii)(A), (B), or (C) of this section, as
applicable.
(A) For each process controller complying with Sec. 60.5390b(b)(1)
process controller bleed rate requirements, you must report the
information specified in paragraphs (b)(7)(iii)(A)(1) and (2) of this
section.
(1) The identification of process controllers designed and operated
to achieve a bleed rate less than or equal to 6 scfh.
(2) Where necessary to meet a functional need, the identification
and demonstration why it is necessary to use a process controller with
a natural gas bleed rate greater than 6 scfh.
(B) An identification of each intermittent vent process controller
complying with the requirements in paragraph Sec. 60.5390b(b)(2).
(C) An identification of each process controller complying with the
requirements in Sec. 60.5390b(b) by routing emissions to a control
device in accordance with Sec. 60.5390b(b)(3).
(iv) Identification of each process controller which changes its
method of compliance during the reporting period and the applicable
information specified in paragraphs (b)(7)(v) through (ix) of this
section for the new method of compliance.
(v) For each process controller in the affected facility complying
with the requirements of Sec. 60.5390b(a) by routing the emissions to
a process, you must report the information specified in (b)(11)(i)
through (iii) of this section.
(vi) For each process controller in the affected facility complying
with the requirements of Sec. 60.5390b(a) by using a self-contained
natural gas-driven process controller, you must report the information
specified in paragraphs (b)(7)(vi)(A) and (B) of this section.
(A) Dates of each inspection required under Sec. 60.5416b(b); and
(B) Each defect or leak identified during each natural gas-driven-
self-contained process controller system inspection, and the date of
repair or date of anticipated repair if repair is delayed.
(vii) For each process controller in the affected facility
complying with the requirements of Sec. 60.5390b(b)(2), you must
report the information specified in paragraphs (b)(7)(vii)(A) and (B)
of this section.
(A) Dates and results of the intermittent vent process controller
monitoring required by Sec. 60.5390b(b)(2)(ii).
(B) For each instance in which monitoring identifies emissions to
the atmosphere from an intermittent vent controller during idle
periods, the date of repair or replacement or the date of anticipated
repair or replacement if the repair or replacement is delayed, and the
date and results of the re-survey after repair or replacement.
(viii) For each process controller affected facility complying with
Sec. 60.5390b(b)(3) by routing emissions to a control device, you must
report the information specified in paragraph (b)(11) of this section.
(ix) For each deviation that occurred during the reporting period,
the date and time the deviation began, the duration of the deviation in
hours, and a description of the deviation. If no deviations occurred
during the reporting period, you must include a statement that no
deviations occurred during the reporting period.
(x) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(b)(7)(ii)(B) and (b)(11)(i) and (ii) of this section, you must provide
the information specified in Sec. 60.5424b.
(8) For each storage vessel affected facility, the information in
paragraphs (b)(8)(i) through (x) of this section.
(i) An identification, including the location, of each storage
vessel affected facility, including those for which construction,
modification, or reconstruction commenced during the reporting period,
and those provided in previous reports. The location of the storage
vessel affected facility shall be in latitude and longitude coordinates
in decimal degrees to an accuracy and precision of five (5) decimals of
a degree using the North American Datum of 1983.
(ii) Documentation of the methane and VOC emission rate
determination according to Sec. 60.5365b(e)(1) for each tank battery
that became an affected facility during the reporting period or is
returned to service during the reporting period.
(iii) For each deviation that occurred during the reporting period
and recorded as specified in paragraph (c)(7)(iii) of this section, the
date and time the deviation began, duration of the deviation in hours
and a description of the deviation. If no deviations occurred during
the reporting period, you must include a statement that no deviations
occurred during the reporting period.
(iv) For each storage vessel affected facility constructed,
modified,
[[Page 17114]]
reconstructed, or returned to service during the reporting period
complying with Sec. 60.5395b(a)(2) with a control device, report the
identification of the storage vessel affected facility with the control
device and the information in paragraph (b)(11)(v) of this section.
(v) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(b)(11)(i) and (ii) of this section, you must provide the information
specified in Sec. 60.5424b.
(vi) If required to comply with Sec. 60.5395b(b)(1), the
information in paragraphs (b)(11)(i) through (iv) of this section.
(vii) You must identify each storage vessel affected facility that
is removed from service during the reporting period as specified in
Sec. 60.5395b(c)(1)(ii), including the date the storage vessel
affected facility was removed from service. You must identify each
storage vessel that that is removed from service from a storage vessel
affected facility during the reporting period as specified in Sec.
60.5395b(c)(2)(iii), including identifying the impacted storage vessel
affected facility and the date each storage vessel was removed from
service.
(viii) You must identify each storage vessel affected facility or
portion of a storage vessel affected facility returned to service
during the reporting period as specified in Sec. 60.5395b(c)(4),
including the date the storage vessel affected facility or portion of a
storage vessel affected facility was returned to service.
(ix) You must identify each storage vessel affected facility that
no longer complies with Sec. 60.5395b(a)(3) and instead complies with
Sec. 60.5395b(a)(2). You must identify whether the change in the
method of compliance was due to fracturing or refracturing or whether
the change was due to an increase in the monthly emissions
determination. If the change was due to an increase in the monthly
emissions determination, you must provide documentation of the
emissions rate. You must identify the date that you complied with Sec.
60.5395b(a)(2) and must submit the information in (b)(8)(iii) through
(vii) of this section.
(x) You must submit a statement that you are complying with Sec.
60.112b(a)(1) or (2), if applicable, in your initial annual report.
(9) For the fugitive emissions components affected facility, report
the information specified in paragraphs (b)(9)(i) through (v) of this
section, as applicable.
(i)(A) Designation of the type of site (i.e., well site,
centralized production facility, or compressor station) at which the
fugitive emissions components affected facility is located.
(B) For the fugitive emissions components affected facility at a
well site or centralized production facility that became an affected
facility during the reporting period, you must include the date of the
startup of production or the date of the first day of production after
modification. For the fugitive emissions components affected facility
at a compressor station that became an affected facility during the
reporting period, you must include the date of startup or the date of
modification.
(C) For the fugitive emissions components affected facility at a
well site, you must specify what type of well site it is (i.e., single
wellhead only well site, small wellsite, multi-wellhead only well site,
or a well site with major production and processing equipment).
(D) For the fugitive emissions components affected facility at a
well site where during the reporting period you complete the removal of
all major production and processing equipment such that the well site
contains only one or more wellheads, you must include the date of the
change to status as a wellhead only well site.
(E) For the fugitive emissions components affected facility at a
well site where you previously reported under paragraph (b)(9)(i)(D) of
this section the removal of all major production and processing
equipment and during the reporting period major production and
processing equipment is added back to the well site, the date that the
first piece of major production and processing equipment is added back
to the well site.
(F) For the fugitive emissions components affected facility at a
well site where during the reporting period you undertake well closure
requirements, the date of the cessation of production from all wells at
the well site, the date you began well closure activities at the well
site, and the dates of the notifications submitted in accordance with
paragraph (a)(4) of this section.
(ii) For each fugitive emissions monitoring survey performed during
the annual reporting period, the information specified in paragraphs
(b)(9)(ii)(A) through (G) of this section.
(A) Date of the survey.
(B) Monitoring instrument or, if the survey was conducted by AVO
methods, notation that AVO was used.
(C) Any deviations from the monitoring plan elements under Sec.
60.5397b(c)(1), (2), and (7), (c)(8)(i), or (d) or a statement that
there were no deviations from these elements of the monitoring plan.
(D) Number and type of components for which fugitive emissions were
detected.
(E) Number and type of fugitive emissions components that were not
repaired as required in Sec. 60.5397b(h).
(F) Number and type of fugitive emission components (including
designation as difficult-to-monitor or unsafe-to-monitor, if
applicable) on delay of repair and explanation for each delay of
repair.
(G) Date of planned shutdown(s) that occurred during the reporting
period if there are any components that have been placed on delay of
repair.
(iii) For the fugitive emissions components affected facility
complying with an alternative fugitive emissions standard under Sec.
60.5399b, in lieu of the information specified in paragraphs (b)(9)(i)
and (ii) of this section, you must provide the information specified in
paragraphs (b)(9)(iii)(A) through (C) of this section.
(A) The alternative standard with which you are complying.
(B) The site-specific reports specified by the specific alternative
fugitive emissions standard, submitted in the format in which they were
submitted to the state, local, or Tribal authority. If the report is in
hard copy, you must scan the document and submit it as an electronic
attachment to the annual report required in paragraph (b) of this
section.
(C) If the report specified by the specific alternative fugitive
emissions standard is not site-specific, you must submit the
information specified in paragraphs (b)(9)(i) and (ii) of this section
for each individual site complying with the alternative standard.
(iv) For well closure activities which occurred during the
reporting period, the information in paragraphs (b)(9)(iv)(A) and (B)
of this section.
(A) A status report with dates for the well closure activities
schedule developed in the well closure plan. If all steps in the well
closure plan are completed in the reporting period, the date that all
activities are completed.
(B) If an OGI survey is conducted during the reporting period, the
information in paragraphs (b)(9)(iv)(B)(1) through (3) of this section.
(1) Date of the OGI survey.
(2) Monitoring instrument used.
(3) A statement that no fugitive emissions were found, or if
fugitive emissions were found, a description of the steps taken to
eliminate those emissions, the date of the resurvey, the results of the
resurvey, and the date of
[[Page 17115]]
the final resurvey which detected no emissions.
(v) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(b)(9)(i) and (ii) of this section, you must provide the information
specified in Sec. 60.5424b.
(10) For each pump affected facility, the information specified in
paragraphs (b)(10)(i) through (iv) of this section in your initial
annual report and in subsequent annual reports for each pump affected
facility that is constructed, modified, or reconstructed during the
reporting period. Each annual report must contain the information
specified in paragraphs (b)(10)(v) through (ix) of this section for
each pump affected facility.
(i) The identification of each of your pumps that are driven by
natural gas, as required by Sec. 60.5393b(a) that allows traceability
to the records required by paragraph (c)(15)(i) of this section.
(ii) For each pump affected facility for which there is a control
device on site but it does not achieve a 95.0 percent emissions
reduction, the certification that there is a control device available
on site but it does not achieve a 95.0 percent emissions reduction
required under Sec. 60.5393b(b)(3). You must also report the emissions
reduction percentage the control device is designed to achieve.
(iii) For each pump affected facility for which there is no control
device or vapor recovery unit on site, the certification required under
Sec. 60.5393b(b)(4) that there is no control device or vapor recovery
unit on site.
(iv) For each pump affected facility for which it is technically
infeasible to route the emissions to a process or control device, the
certification of technically infeasibility required under Sec.
60.5393b(b)(5).
(v) For any pump affected facility which has previously reported as
required under paragraph (b)(10)(i) through (iv) of this section and
for which a change in the reported condition has occurred during the
reporting period, provide the identification of the pump affected
facility and the date that the pump affected facility meets one of the
change conditions described in paragraphs (b)(10)(v)(A), (B), or (C) of
this section.
(A) If you install a control device or vapor recovery unit, you
must report that a control device or vapor recovery unit has been added
to the site and that the pump affected facility now is required to
comply with Sec. 60.5393b(b)(1) or (3), as applicable.
(B) If your pump affected facility previously complied with Sec.
60.5393b(b)(1) or (3) by routing emissions to a process or a control
device and the process or control device is subsequently removed from
the site or is no longer available such that there is no ability to
route the emissions to a process or control device at the site, or that
it is not technically feasible to capture and route the emissions to
another control device or process located on site, report that you are
no longer complying with the applicable requirements of Sec.
60.5393b(b)(1) or (3) and submit the information provided in paragraphs
(b)(10)(v)(B)(1) or (2) of this section.
(1) Certification that there is no control device or vapor recovery
unit on site.
(2) Certification of the engineering assessment that it is
technically infeasible to capture and route the emissions to another
control device or process located on site.
(C) If any pump affected facility or individual natural gas-driven
pump changes its method of compliance during the reporting period other
than for the reasons specified in paragraphs (10)(v)(A) and (B) of this
section, identify the new compliance method for each natural gas-driven
pump within the affected facility which changes its method of
compliance during the reporting period and provide the applicable
information specified in paragraphs (b)(10)(ii) through (iv) and (vi)
through (viii) of this section for the new method of compliance.
(vi) For each pump affected facility complying with the
requirements of Sec. 60.5393b(a), (b)(1), or (b)(3) by routing the
emissions to a process, you must report the information specified in
paragraphs (b)(11)(i) through (iv) of this section.
(vii) For each pump affected facility complying with the
requirements of Sec. 60.5393b(b)(1) or (3) by routing the emissions to
a control device, you must report the information required under
paragraph (b)(11) of this section.
(viii) For each deviation that occurred during the reporting
period, the date and time the deviation began, the duration of the
deviation in hours, and a description of the deviation. If no
deviations occurred during the reporting period, you must include a
statement that no deviations occurred during the reporting period.
(ix) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(b)(11)(i) and (ii) of this section, you must provide the information
specified in Sec. 60.5424b.
(11) For each well, centrifugal compressor, reciprocating
compressor, storage vessel, process controller, pump, or process unit
equipment affected facility which uses a closed vent system routed to a
control device to meet the emissions reduction standard, you must
submit the information in paragraphs (b)(11)(i) through (v) of this
section. For each reciprocating compressor, process controller, pump,
storage vessel, or process unit equipment which uses a closed vent
system to route to a process, you must submit the information in
paragraphs (b)(11)(i) through (iv) of this section. For each
centrifugal compressor, reciprocating compressor, and storage vessel
equipped with a cover, you must submit the information in paragraphs
(b)(11)(i) and (ii) of this section.
(i) Dates of each inspection required under Sec. 60.5416b(a) and
(b).
(ii) Each defect or emissions identified during each inspection and
the date of repair or the date of anticipated repair if the repair is
delayed.
(iii) Date and time of each bypass alarm or each instance the key
is checked out if you are subject to the bypass requirements of Sec.
60.5416b(a)(4).
(iv) You must submit the certification signed by the qualified
professional engineer or in-house engineer according to Sec.
60.5411b(c) for each closed vent system routing to a control device or
process in the reporting year in which the certification is signed.
(v) If you comply with the emissions standard for your well,
centrifugal compressor, reciprocating compressor, storage vessel,
process controller, pump, or process unit equipment affected facility
with a control device, the information in paragraphs (b)(11)(v)(A)
through (L) of this section, unless you use an enclosed combustion
device or flare using an alternative test method approved under Sec.
60.5412b(d). If you use an enclosed combustion device or flare using an
alternative test method approved under Sec. 60.5412b(d), the
information in paragraphs (b)(11)(v)(A) through (C) and (L) through (P)
of this section.
(A) Identification of the control device.
(B) Make, model, and date of installation of the control device.
(C) Identification of the affected facility controlled by the
device.
(D) For each continuous parameter monitoring system used to
demonstrate compliance for the control device, a unique continuous
parameter monitoring system identifier and the make, model number, and
date of last calibration check of the continuous parameter monitoring
system.
[[Page 17116]]
(E) For each instance where there is a deviation of the control
device in accordance with Sec. 60.5417b(g)(1) through (3) or (g)(5)
through (7) include the date and time the deviation began, the duration
of the deviation in hours, the type of the deviation (e.g., NHV
operating limit, lack of pilot or combustion flame, condenser
efficiency, bypass line flow, visible emissions), and cause of the
deviation.
(F) For each instance where there is a deviation of the continuous
parameter monitoring system in accordance with Sec. 60.5417b(g)(4)
include the date and time the deviation began, the duration of the
deviation in hours, and cause of the deviation.
(G) For each visible emissions test following return to operation
from a maintenance or repair activity, the date of the visible
emissions test or observation of the video surveillance output, the
length of the observation in minutes, and the number of minutes for
which visible emissions were present.
(H) If a performance test was conducted on the control device
during the reporting period, provide the date the performance test was
conducted. Submit the performance test report following the procedures
specified in paragraph (b)(12) of this section.
(I) If a demonstration of the NHV of the inlet gas to the enclosed
combustion device or flare was conducted during the reporting period in
accordance with Sec. 60.5417b(d)(8)(iii), an indication of whether
this is a re-evaluation of vent gas NHV and the reason for the re-
evaluation; the applicable required minimum vent gas NHV; if twice
daily samples of the vent stream were taken, the number of hourly
average NHV values that are less than 1.2 times the applicable required
minimum NHV; if continuous NHV sampling of the vent stream was
conducted, the number of hourly average NHV values that are less than
the required minimum vent gas NHV; if continuous combustion efficiency
monitoring was conducted using an alternative test method approved
under Sec. 60.5412b(d), the number of values of the combustion
efficiency that were less than 95.0 percent; the resulting
determination of whether NHV monitoring is required or not in
accordance with Sec. 60.5417b(d)(8)(iii)(D) or (H); and an indication
of whether the enclosed combustion device or flare has the potential to
receive inert gases, and if so, whether the sampling included periods
where the highest percentage of inert gases were sent to the enclosed
combustion device or flare.
(J) If a demonstration was conducted in accordance with Sec.
60.5417b(d)(8)(iv) that the maximum potential pressure of units
manifolded to an enclosed combustion device or flare cannot cause the
maximum inlet flow rate established in accordance with Sec.
60.5417b(f)(1) or a flare tip velocity limit of 18.3 meter/second (60
feet/second) to be exceeded, an indication of whether this is a re-
evaluation of the gas flow and the reason for the re-evaluation; the
demonstration conducted; and applicable engineering calculations.
(K) For each periodic sampling event conducted under Sec.
60.5417b(d)(8)(iii)(G), provide the date of the sampling, the required
minimum vent gas NHV, and the NHV value for each vent gas sample.
(L) For each flare and enclosed combustion device, provide the date
each device is observed with OGI in accordance with Sec.
60.5415b(f)(x) and whether uncombusted emissions were present. Provide
the date each device was visibly observed during an AVO inspection in
accordance with Sec. 60.5415b(f)(x), whether the pilot or combustion
flame was lit at the time of observation, and whether the device was
found to be operating properly.
(M) An identification of the alternative test method used.
(N) For each instance where there is a deviation of the control
device in accordance with Sec. 60.5417b(i)(6)(i) or (iii) through (v)
include the date and time the deviation began, the duration of the
deviation in hours, the type of the deviation (e.g., NHVcz
operating limit, lack of pilot or combustion flame, visible emissions),
and cause of the deviation.
(O) For each instance where there is a deviation of the data
availability in accordance with Sec. 60.5417b(i)(6)(ii) include the
date of each operating day when monitoring data are not available for
at least 75 percent of the operating hours.
(P) If no deviations occurred under paragraphs (b)(11)(v)(N) or (O)
of this section, a statement that there were no deviations for the
control device during the annual report period.
(Q) Any additional information required to be reported as specified
by the Administrator as part of the alternative test method approval
under Sec. 60.5412b(d).
(12) Within 60 days after the date of completing each performance
test (see Sec. 60.8) required by this subpart, except testing
conducted by the manufacturer as specified in Sec. 60.5413b(d), you
must submit the results of the performance test following the
procedures specified in paragraph (d) of this section. Data collected
using test methods that are supported by the EPA's Electronic Reporting
Tool (ERT) as listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at
the time of the test must be submitted in a file format generated using
the EPA's ERT. Alternatively, you may submit an electronic file
consistent with the extensible markup language (XML) schema listed on
the EPA's ERT website. Data collected using test methods that are not
supported by the EPA's ERT as listed on the EPA's ERT website at the
time of the test must be included as an attachment in the ERT or
alternate electronic file.
(13) For combustion control devices tested by the manufacturer in
accordance with Sec. 60.5413b(d), an electronic copy of the
performance test results required by Sec. 60.5413b(d) shall be
submitted via email to [email protected] unless the test results
for that model of combustion control device are posted at the following
website: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.
(14) If you had a super-emitter event during the reporting period,
the start date of the super-emitter event, the duration of the super-
emitter event in hours, and the affected facility associated with the
super-emitter event, if applicable.
(15) You must submit your annual report using the appropriate
electronic report template on the Compliance and Emissions Data
Reporting Interface (CEDRI) website for this subpart and following the
procedure specified in paragraph (d) of this section. If the reporting
form specific to this subpart is not available on the CEDRI website at
the time that the report is due, you must submit the report to the
Administrator at the appropriate address listed in Sec. 60.4. Once the
form has been available on the CEDRI website for at least 90 calendar
days, you must begin submitting all subsequent reports via CEDRI. The
date reporting forms become available will be listed on the CEDRI
website. Unless the Administrator or delegated state agency or other
authority has approved a different schedule for submission of reports,
the report must be submitted by the deadline specified in this subpart,
regardless of the method in which the report is submitted.
(c) Recordkeeping requirements. You must maintain the records
identified as specified in Sec. 60.7(f) and in paragraphs (c)(1)
through (15) of this section. All records required by this subpart must
be maintained either onsite or at the nearest local field office for at
least 5 years. Any records required to be maintained by this subpart
that are
[[Page 17117]]
submitted electronically via the EPA's CEDRI may be maintained in
electronic format. This ability to maintain electronic copies does not
affect the requirement for facilities to make records, data, and
reports available upon request to a delegated air agency or the EPA as
part of an on-site compliance evaluation.
(1) The records for each well affected facility subject to the well
completion operation standards of Sec. 60.5375b, as specified in
paragraphs (c)(1)(i) through (vii) of this section, as applicable. For
each well affected facility subject to the well completion operations
of Sec. 60.5375b, for which you make a claim that the well affected
facility is not subject to the requirements for well completions
pursuant to Sec. 60.5375b(g), you must maintain the record in
paragraph (c)(1)(vi) of this section, only. For each well affected
facility which meets the exemption in Sec. 60.5375b(h) for well
completion operations (i.e., an existing well is hydraulically
refractured), you must maintain the records in paragraph (c)(1)(viii),
only. For each well affected facility that routes flowback entirely
through one or more production separators that are designed to
accommodate flowback, only records of the United States Well Number,
the latitude and longitude of the well in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using North
American Datum of 1983, the Well Completion ID, and the date and time
of startup of production are required. For periods where salable gas is
unable to be separated, records of the date and time of onset of
flowback, the duration and disposition of recovery, the duration of
combustion and venting (if applicable), reasons for venting (if
applicable), and deviations are required.
(i) Records identifying each well completion operation for each
well affected facility.
(ii) Records of deviations in cases where well completion
operations with hydraulic fracturing were not performed in compliance
with the requirements specified in Sec. 60.5375b, including the date
and time the deviation began, the duration of the deviation, and a
description of the deviation.
(iii) You must maintain the records specified in paragraphs
(c)(1)(iii)(A) through (C) of this section.
(A) For each well affected facility required to comply with the
requirements of Sec. 60.5375b(a), you must record: The latitude and
longitude of the well in decimal degrees to an accuracy and precision
of five (5) decimals of a degree using North American Datum of 1983;
the United States Well Number; the date and time of the onset of
flowback following hydraulic fracturing or refracturing; the date and
time of each attempt to direct flowback to a separator as required in
Sec. 60.5375b(a)(1)(ii); the date and time of each occurrence of
returning to the initial flowback stage under Sec. 60.5375b(a)(1)(i);
and the date and time that the well was shut in and the flowback
equipment was permanently disconnected, or the startup of production;
the duration of flowback; duration of recovery and disposition of
recovery (i.e., routed to the gas flow line or collection system, re-
injected into the well or another well, used as an onsite fuel source,
or used for another useful purpose that a purchased fuel or raw
material would serve); duration of combustion; duration of venting; and
specific reasons for venting in lieu of capture or combustion. The
duration must be specified in hours. In addition, for wells where it is
technically infeasible to route the recovered gas as specified in Sec.
60.5375b(a)(1)(ii), you must record the reasons for the claim of
technical infeasibility with respect to all four options provided in
Sec. 60.5375b(a)(1)(ii).
(B) For each well affected facility required to comply with the
requirements of Sec. 60.5375b(f), you must record: Latitude and
longitude of the well in decimal degrees to an accuracy and precision
of five (5) decimals of a degree using North American Datum of 1983;
the United States Well Number; the date and time of the onset of
flowback following hydraulic fracturing or refracturing; the date and
time that the well was shut in and the flowback equipment was
permanently disconnected, or the startup of production; the duration of
flowback; duration of combustion; duration of venting; and specific
reasons for venting in lieu combustion. The duration must be specified
in hours.
(C) For each well affected facility for which you make a claim that
it meets the criteria of Sec. 60.5375b(a)(1)(iii)(A), you must
maintain the following:
(1) The latitude and longitude of the well in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using North
American Datum of 1983; the United States Well Number; the date and
time of the onset of flowback following hydraulic fracturing or
refracturing; the date and time that the well was shut in and the
flowback equipment was permanently disconnected, or the startup of
production; the duration of flowback; duration of recovery and
disposition of recovery (i.e., routed to the gas flow line or
collection system, re-injected into the well or another well, used as
an onsite fuel source, or used for another useful purpose that a
purchased fuel or raw material would serve); duration of combustion;
duration of venting; and specific reasons for venting in lieu of
capture or combustion. The duration must be specified in hours.
(2) If applicable, records that the conditions of Sec.
60.5375b(a)(1)(iii)(A) are no longer met and that the well completion
operation has been stopped and a separator installed. The records shall
include the date and time the well completion operation was stopped and
the date and time the separator was installed.
(3) A record of the claim signed by the certifying official that no
liquids collection is at the well site. The claim must include a
certification by a certifying official of truth, accuracy, and
completeness. This certification shall state that, based on information
and belief formed after reasonable inquiry, the statements and
information in the document are true, accurate, and complete.
(iv) For each well affected facility for which you claim an
exception under Sec. 60.5375b(a)(2), you must record: The latitude and
longitude of the well in decimal degrees to an accuracy and precision
of five (5) decimals of a degree using North American Datum of 1983;
the United States Well Number; the specific exception claimed; the
starting date and ending date for the period the well operated under
the exception; and an explanation of why the well meets the claimed
exception.
(v) For each well affected facility required to comply with both
Sec. 60.5375b(a)(1) and (2), if you are using a digital photograph in
lieu of the records required in paragraphs (c)(1)(i) through (iv) of
this section, you must retain the records of the digital photograph as
specified in Sec. 60.5410b(a)(4).
(vi) For each well affected facility for which you make a claim
that the well affected facility is not subject to the well completion
standards according to Sec. 60.5375b(g), you must maintain:
(A) A record of the analysis that was performed in order the make
that claim, including but not limited to, GOR values for established
leases and data from wells in the same basin and field;
(B) The latitude and longitude of the well in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using North
American Datum of 1983; the United States Well Number;
(C) A record of the claim signed by the certifying official. The
claim must include a certification by a certifying official of truth,
accuracy, and
[[Page 17118]]
completeness. This certification shall state that, based on information
and belief formed after reasonable inquiry, the statements and
information in the document are true, accurate, and complete.
(vii) For each well affected facility subject to Sec. 60.5375b(f),
a record of the well type (i.e., wildcat well, delineation well, or low
pressure well (as defined Sec. 60.5430b)) and supporting inputs and
calculations, if applicable.
(viii) For each well affected facility which makes a claim it meets
the exemption at Sec. 60.5375b(h), a record of the latitude and
longitude of the well in decimal degrees to an accuracy and precision
of five (5) decimals of a degree using North American Datum of 1983;
the United States Well Number; the date and time of the onset of
flowback following hydraulic fracturing or refracturing and a record of
the claim that the well completion operation requirements of Sec.
60.5375b(a)(1) through (3) were met.
(2) For each gas well liquids unloading operation at your well
affected facility that is subject to Sec. 60.5376b(a)(1) or (2), the
records of each gas well liquids unloading operation conducted during
the reporting period, including the information specified in paragraphs
(c)(2)(i) through (iii) of this section, as applicable.
(i) For each gas well liquids unloading operation that complies
with Sec. 60.5376b(a)(1) by performing all liquids unloading events
without venting of methane and VOC emissions to the atmosphere, comply
with the recordkeeping requirements specified in paragraphs
(c)(2)(i)(A) and (B) of this section.
(A) Identification of each well (i.e., U.S. Well ID or U.S. Well ID
associated with the well affected facility) that conducts a gas well
liquids unloading operation during the reporting period without venting
of methane and VOC emissions and the non-venting methane and VOC gas
well liquids unloading method used. If more than one non-venting method
is used, you must maintain records all of the differing non-venting
liquids unloading methods used at the well affected facility complying
with Sec. 60.5376b(a)(1).
(B) Number of events where unplanned emissions are vented to the
atmosphere during a gas well liquids unloading operation where you
complied with best management practices to minimize emissions to the
maximum extent possible.
(ii) For each gas well liquids unloading operation that complies
with Sec. 60.5376b(b) and (c) best management practices, maintain
records documenting information specified in paragraphs (c)(2)(ii)(A)
through (D) of this section.
(A) Identification of each well affected facility that conducts
liquids unloading during the reporting period that employs best
management practices to minimize emissions to the maximum extent
possible.
(B) Documentation of your best management practice plan developed
under paragraph Sec. 60.5376b(c). You may update your best management
practice plan to include additional steps which meet the criteria in
Sec. 60.5376b(c).
(C) A log of each best management practice plan step taken minimize
emissions to the maximum extent possible for each gas well liquids
unloading event.
(D) Documentation of each gas well liquids unloading event where
deviations from your best management practice plan steps occurred, the
date and time the deviation began, the duration of the deviation,
documentation of best management practice plans steps were not
followed, and the steps taken in lieu of your best management practice
plan steps during those events to minimize emissions to the maximum
extent possible.
(iii) For each well affected facility that reduces methane and VOC
emissions from well affected facility gas wells that unload liquids by
95.0 percent by routing emissions to a control device through closed
vent system under Sec. 60.5376b(g), you must maintain the records in
paragraphs (c)(2)(iii)(A) through (E) of this section.
(A) If you comply with the emission reduction standard with a
control device, the information for each control device in paragraph
(c)(11) of this section.
(B) Records of the closed vent system inspection as specified
paragraph (c)(8) of this section.
(C) Records of the cover inspections as specified in paragraph
(c)(9) of this section.
(D) If applicable, the records of bypass monitoring as specified in
paragraph (c)(10) of this section.
(E) Records of the closed vent system assessment as specified in
paragraph (c)(12) of this section.
(3) For each associated gas well, you must maintain the applicable
records specified in paragraphs (c)(3)(i) or (ii) and (c)(3)(iv) of
this section.
(i) For each associated gas well that complies with the
requirements of Sec. 60.5377b(a)(1), (2), (3), or (4), you must keep
the records specified in paragraphs (c)(3)(i)(A) and (B).
(A) Documentation of the specific method(s) in Sec.
60.5377b(a)(1), (2), (3), or (4) that is used.
(B) For instances where you temporarily route the associated gas to
a flare or control device in accordance with Sec. 60.5377b(d), you
must keep the records specified in paragraphs (c)(3)(i)(B)(1) through
(3).
(1) The reason in Sec. 60.5377b(d)(1), (2), (3), or (4) for each
incident.
(2) The date of each incident, along with the times when routing
the associated gas to the flare or control device started and ended,
along with the total duration of each incident.
(3) Documentation that all CVS requirements specified in Sec.
60.5411b(a) and (c) and all applicable flare or control device
requirements specified in Sec. 60.5412b are met during each period
when the associated gas is routed to the flare or control device.
(ii) For instances where you temporarily vent the associated gas in
accordance with Sec. 60.5377b(e), you must keep the records specified
in paragraphs (c)(3)(ii)(A) through (D). These records are required if
you are routinely complying with Sec. 60.5377b(a) or Sec. 60.5377b(f)
or temporarily complying with Sec. 60.5377b(d).
(A) The reason in Sec. 60.5377b(e)(1), (2), or (3) for each
incident.
(B) The date of each incident, along with the times when venting
the associated gas started and ended, along with the total duration of
each incident.
(C) The VOC and methane emissions that were emitted during each
incident.
(D) The cumulative duration of venting incidents and VOC and
methane emissions for all incidents in each calendar year.
(iii) For each associated gas well that complies with the
requirements of Sec. 60.5377b(f) because it has demonstrated that it
is not feasible to comply with Sec. 60.5377b(a)(1), (2), (3), and (4)
due to technical reasons in accordance with Sec. 60.5377b(g), records
of each annual demonstration and certification of the technical reason
that it is not feasible to comply with Sec. 60.5377b(a)(1), (2), (3),
and (4) in accordance with Sec. 60.5377b(g).
(iv) For each associated gas well that complies with the
requirements of Sec. 60.5377b(f), meet the recordkeeping requirements
specified in paragraphs (c)(3)(iv)(A) through (E).
(A) Identification of each instance when associated gas was vented
and not routed to a control device that reduces VOC and methane
emissions by at least 95.0 percent.
(B) If you comply with the emission reduction standard in Sec.
60.5380b with a control device, the information for each
[[Page 17119]]
control device in paragraph (c)(11) of this section.
(C) Records of the closed vent system inspection as specified
paragraph (c)(8) of this section. If you comply with an alternative GHG
and VOC standard under Sec. 60.5398b, in lieu of the information
specified in paragraph (c)(8) of this section, you must maintain
records of the information specified in Sec. 60.5424b.
(D) If applicable, the records of bypass monitoring as specified in
paragraph (c)(10) of this section.
(E) Records of the closed vent system assessment as specified in
paragraph (c)(12) of this section.
(v) Records of each deviation, the date and time the deviation
began, the duration of the deviation, and a description of the
deviation.
(4) For each centrifugal compressor affected facility, you must
maintain the records specified in paragraphs (c)(4)(i) through (iii) of
this section.
(i) For each centrifugal compressor affected facility, you must
maintain records of deviations in cases where the centrifugal
compressor was not operated in compliance with the requirements
specified in Sec. 60.5380b, including a description of each deviation,
the date and time each deviation began and the duration of each
deviation.
(ii) For each wet seal compressor complying with the emissions
reduction standard in Sec. 60.5380b(a)(1), you must maintain the
records in paragraphs (c)(4)(ii)(A) through (E) of this section. For
each wet seal compressor complying with the alternative standard in
Sec. 60.5380b(a)(3) by routing the closed vent system to a process,
you must maintain the records in paragraphs (c)(4)(ii)(B) through (E)
of this section.
(A) If you comply with the emission reduction standard in Sec.
60.5380b(a)(1) with a control device, the information for each control
device in paragraph (c)(11) of this section.
(B) Records of the closed vent system inspection as specified
paragraph (c)(8) of this section. If you comply with an alternative GHG
and VOC standard under Sec. 60.5398b, in lieu of the information
specified in paragraph (c)(8) of this section, you must maintain the
information specified in Sec. 60.5424b.
(C) Records of the cover inspections as specified in paragraph
(c)(9) of this section. If you comply with an alternative GHG and VOC
standard under Sec. 60.5398b, in lieu of the information specified in
paragraphs (c)(9) of this section, you must maintain the information
specified in Sec. 60.5424b.
(D) If applicable, the records of bypass monitoring as specified in
paragraph (c)(10) of this section.
(E) Records of the closed vent system assessment as specified in
paragraph (c)(12) of this section.
(iii) For each centrifugal compressor affected facility using a
self-contained wet seal compressor, or dry seal compressor complying
with the standard in Sec. 60.5380b(a)(4) and (5), you must maintain
the records specified in paragraphs (c)(4)(iii)(A) through (H) of this
section.
(A) Records of the cumulative number of hours of operation since
initial startup, since May 7, 2024, or since the previous volumetric
flow rate measurement, as applicable.
(B) A description of the method used and the results of the
volumetric flow rate measurement or emissions screening, as applicable.
(C) Records for all flow meters, composition analyzers and pressure
gauges used to measure volumetric flow rates as specified in paragraphs
(c)(4)(iii)(C)(1) through (6).
(1) Description of standard method published by a consensus-based
standards organization or industry standard practice.
(2) Records of volumetric flow rate emissions calculations
conducted according to paragraphs Sec. 60.5380b(a)(5), as applicable.
(3) Records of manufacturer's operating procedures and measurement
methods.
(4) Records of manufacturer's recommended procedures or an
appropriate industry consensus standard method for calibration and
results of calibration, recalibration, and accuracy checks.
(5) Records which demonstrate that measurements at the remote
location(s) can, when appropriate correction factors are applied,
reliably and accurately represent the actual temperature or total
pressure at the flow meter under all expected ambient conditions. You
must include the date of the demonstration, the data from the
demonstration, the mathematical correlation(s) between the remote
readings and actual flow meter conditions derived from the data, and
any supporting engineering calculations. If adjustments were made to
the mathematical relationships, a record and description of such
adjustments.
(6) Record of each initial calibration or a recalibration which
failed to meet the required accuracy specification and the date of the
successful recalibration.
(D) Date when performance-based volumetric flow rate is exceeded.
(E) The date of successful repair of the compressor seal, including
follow-up performance-based volumetric flow rate measurement to confirm
successful repair.
(F) Identification of each compressor seal placed on delay of
repair and explanation for each delay of repair.
(G) For each compressor seal or part needed for repair placed on
delay of repair because of replacement seal or part unavailability, the
operator must document: the date the seal or part was added to the
delay of repair list, the date the replacement seal or part was
ordered, the anticipated seal or part delivery date (including any
estimated shipment or delivery date provided by the vendor), and the
actual arrival date of the seal or part.
(H) Date of planned shutdowns that occur while there are any seals
or parts that have been placed on delay of repair.
(5) For each reciprocating compressor affected facility, you must
maintain the records in paragraphs (c)(5)(i) through (x), and (c)(8),
(c)(10) and (c)(12) of this section, as applicable. If you comply with
an alternative GHG and VOC standard under Sec. 60.5398b, in lieu of
the information specified in paragraph (c)(8) of this section, you must
provide the information specified in Sec. 60.5424b.
(i) For each reciprocating compressor affected facility, you must
maintain records of deviations in cases where the reciprocating
compressor was not operated in compliance with the requirements
specified in Sec. 60.5385b, including a description of each deviation,
the date and time each deviation began and the duration of each
deviation in hours.
(ii) Records of the date of installation of a rod packing emissions
collection system and closed vent system as specified in Sec.
60.5385b(d).
(iii) Records of the cumulative number of hours of operation since
initial startup, since May 7, 2024, or since the previous volumetric
flow rate measurement, as applicable. Alternatively, a record that
emissions from the rod packing are being routed to a process through a
closed vent system.
(iv) A description of the method used and the results of the
volumetric flow rate measurement or emissions screening, as applicable.
(v) Records for all flow meters, composition analyzers and pressure
gauges used to measure volumetric flow rates as specified in paragraphs
(c)(5)(v)(A) through (F).
(A) Description of standard method published by a consensus-based
standards organization or industry standard practice.
(B) Records of volumetric flow rate calculations conducted
according to paragraphs Sec. 60.5385b(b) or (c), as applicable.
[[Page 17120]]
(C) Records of manufacturer operating procedures and measurement
methods.
(D) Records of manufacturer's recommended procedures or an
appropriate industry consensus standard method for calibration and
results of calibration, recalibration, and accuracy checks.
(E) Records which demonstrate that measurements at the remote
location(s) can, when appropriate correction factors are applied,
reliably and accurately represent the actual temperature or total
pressure at the flow meter under all expected ambient conditions. You
must include the date of the demonstration, the data from the
demonstration, the mathematical correlation(s) between the remote
readings and actual flow meter conditions derived from the data, and
any supporting engineering calculations. If adjustments were made to
the mathematical relationships, a record and description of such
adjustments.
(F) Record of each initial calibration or a recalibration which
failed to meet the required accuracy specification and the date of the
successful recalibration.
(vi) Date when performance-based volumetric flow rate is exceeded.
(vii) The date of successful replacement or repair of reciprocating
compressor rod packing, including follow-up performance-based
volumetric flow rate measurement to confirm successful repair.
(viii) Identification of each reciprocating compressor placed on
delay of repair because of rod packing or part unavailability and
explanation for each delay of repair.
(ix) For each reciprocating compressor that is placed on delay of
repair because of replacement rod packing or part unavailability, the
operator must document: the date the rod packing or part was added to
the delay of repair list, the date the replacement rod packing or part
was ordered, the anticipated rod packing or part delivery date
(including any estimated shipment or delivery date provided by the
vendor), and the actual arrival date of the rod packing or part.
(x) Date of planned shutdowns that occur while there are any
reciprocating compressors that have been placed on delay of repair due
to the unavailability of rod packing or parts to conduct repairs.
(6) For each process controller affected facility, you must
maintain the records specified in paragraphs (c)(6)(i) through (vii) of
this section.
(i) Records identifying each process controller that is driven by
natural gas and that does not function as an emergency shutdown device.
(ii) For each process controller affected facility complying with
Sec. 60.5390b(a), you must maintain records of the information
specified in paragraphs (c)(6)(ii)(A) and (B) of this section, as
applicable.
(A) If you are complying with Sec. 60.5390b(a) by routing process
controller vapors to a process through a closed vent system, you must
report the information specified in paragraphs (c)(6)(ii)(A)(1) and (2)
of this section.
(1) An identification of all the natural gas-driven process
controllers in the process controller affected facility for which you
collect and route vapors to a process through a closed vent system.
(2) The records specified in paragraphs (c)(8), (10), and (12) of
this section. If you comply with an alternative GHG and VOC standard
under Sec. 60.5398b, in lieu of the information specified in paragraph
(c)(8) of this section, you must provide the information specified in
Sec. 60.5424b.
(B) If you are complying with Sec. 60.5390b(a) by using a self-
contained natural gas-driven process controller, you must report the
information specified in paragraphs (c)(6)(ii)(B)(1) through (3) of
this section.
(1) An identification of each process controller complying with
Sec. 60.5390b(a) by using a self-contained natural gas-driven process
controller;
(2) Dates of each inspection required under Sec. 60.5416b(b); and
(3) Each defect or leak identified during each natural gas-driven-
self-contained process controller system inspection, and date of repair
or date of anticipated repair if repair is delayed.
(iii) For each process controller affected facility complying with
the Sec. 60.5390b(b)(1) process controller bleed rate requirements,
you must maintain records of the information specified in paragraphs
(c)(6)(iii)(A) and (B) of this section.
(A) The identification of process controllers designed and operated
to achieve a bleed rate less than or equal to 6 scfh and records of the
manufacturer's specifications indicating that the process controller is
designed with a natural gas bleed rate of less than or equal to 6 scfh.
(B) Where necessary to meet a functional need, the identification
of the process controller and demonstration of why it is necessary to
use a process controller with a natural gas bleed rate greater than 6
scfh.
(iv) For each intermittent vent process controller in the affected
facility complying with the requirements in paragraphs Sec.
60.5390b(b)(2), you must keep records of the information specified in
paragraphs (c)(6)(iv)(A) through (C) of this section.
(A) The identification of each intermittent vent process
controller.
(B) Dates and results of the intermittent vent process controller
monitoring required by Sec. 60.5390b(b)(2)(ii).
(C) For each instance in which monitoring identifies emissions to
the atmosphere from an intermittent vent controller during idle
periods, the date of repair or replacement, or the date of anticipated
repair or replacement if the repair or replacement is delayed and the
date and results of the re-survey after repair or replacement.
(v) For each process controller affected facility complying with
Sec. 60.5390b(b)(3), you must maintain the records specified in
paragraphs (c)(6)(v)(A) and (B) of this section.
(A) An identification of each process controller for which
emissions are routed to a control device.
(B) Records specified in paragraphs (c)(8) and (c)(10) through (13)
of this section. If you comply with an alternative GHG and VOC standard
under Sec. 60.5398b, in lieu of the information specified in paragraph
(c)(8) of this section, you must provide the information specified in
Sec. 60.5424b.
(vi) Records of each change in compliance method, including
identification of each natural gas-driven process controller which
changes its method of compliance, the new method of compliance, and the
date of the change in compliance method.
(vii) Records of each deviation, the date and time the deviation
began, the duration of the deviation, and a description of the
deviation.
(7) For each storage vessel affected facility, you must maintain
the records identified in paragraphs (c)(7)(i) through (vii) of this
section.
(i) You must maintain records of the identification and location in
latitude and longitude coordinates in decimal degrees to an accuracy
and precision of five (5) decimals of a degree using the North American
Datum of 1983 of each storage vessel affected facility.
(ii) Records of each methane and VOC emissions determination for
each storage vessel affected facility made under Sec. 60.5365b(e)
including identification of the model or calculation methodology used
to calculate the methane and VOC emission rate.
(iii) For each instance where the storage vessel was not operated
in compliance with the requirements specified in Sec. 60.5395b a
description of the deviation, the date and time each
[[Page 17121]]
deviation began, and the duration of the deviation.
(iv) If complying with the emissions reduction standard in Sec.
60.5395b(a)(2), you must maintain the records in paragraphs
(c)(7)(iv)(A) through (E) of this section.
(A) If you comply with the emission reduction standard with a
control device, the information for each control device in paragraph
(c)(11) of this section.
(B) Records of the closed vent system inspection as specified
paragraph (c)(8) of this section. If you comply with an alternative GHG
and VOC standard under Sec. 60.5398b, in lieu of the information
specified in paragraph (c)(8) of this section, you must provide the
information specified in Sec. 60.5424b.
(C) Records of the cover inspections as specified in paragraph
(c)(9) of this section. If you comply with an alternative GHG and VOC
standard under Sec. 60.5398b, in lieu of the information specified in
paragraphs (c)(9) of this section, you must provide the information
specified in Sec. 60.5424b.
(D) If applicable, the records of bypass monitoring as specified in
paragraph (c)(10) of this section.
(E) Records of the closed vent system assessment as specified in
paragraph (c)(12) of this section.
(v) For storage vessels that are skid-mounted or permanently
attached to something that is mobile (such as trucks, railcars, barges
or ships), records indicating the number of consecutive days that the
vessel is located at a site in the crude oil and natural gas source
category. If a storage vessel is removed from a site and, within 30
days, is either returned to the site or replaced by another storage
vessel at the site to serve the same or similar function, then the
entire period since the original storage vessel was first located at
the site, including the days when the storage vessel was removed, will
be added to the count towards the number of consecutive days.
(vi) Records of the date that each storage vessel affected facility
or portion of a storage vessel affected facility is removed from
service and returned to service, as applicable.
(vii) Records of the date that liquids from the well following
fracturing or refracturing are routed to the storage vessel affected
facility; or the date that you comply with paragraph Sec.
60.5395b(a)(2), following a monthly emissions determination which
indicates that VOC emissions from your storage vessel affected facility
increase to 4 tpy or greater or methane emissions increase to 14 tpy or
greater and the increase is not associated with fracturing or
refracturing of a well feeding the storage vessel affected facility,
and records of the methane and VOC emissions rate and the model or
calculation methodology used to calculate the methane and VOC emission
rate.
(8) Records of each closed vent system inspection required under
Sec. 60.5416b(a)(1) and (2) and (b) for your well, centrifugal
compressor, reciprocating compressor, process controller, pump, storage
vessel, and process unit equipment affected facility as required in
paragraphs (c)(8)(i) through (iv) of this section.
(i) A record of each closed vent system inspection or no
identifiable emissions monitoring survey. You must include an
identification number for each closed vent system (or other unique
identification description selected by you), the date of the
inspection, and the method used to conduct the inspection (i.e.,
visual, AVO, OGI, Method 21 of appendix A-7 to this part).
(ii) For each defect or emissions detected during inspections
required by Sec. 60.5416b(a)(1) and (2), or (b) you must record the
location of the defect or emissions; a description of the defect; the
maximum concentration reading obtained if using Method 21 of appendix
A-7 to this part; the indication of emissions detected by AVO if using
AVO; the date of detection; the date of each attempt to repair the
emissions or defect; the corrective action taken during each attempt to
repair the defect; and the date the repair to correct the defect or
emissions is completed.
(iii) If repair of the defect is delayed as described in Sec.
60.5416b(b)(6), you must record the reason for the delay and the date
you expect to complete the repair.
(iv) Parts of the closed vent system designated as unsafe to
inspect as described in Sec. 60.5416b(b)(7) or difficult to inspect as
described in Sec. 60.5416b(b)(8), the reason for the designation, and
written plan for inspection of that part of the closed vent system.
(9) A record of each cover inspection required under Sec.
60.5416b(a)(3) for your centrifugal compressor, reciprocating
compressor, or storage vessel as required in paragraphs (c)(9)(i)
through (iv) of this section.
(i) A record of each cover inspection. You must include an
identification number for each cover (or other unique identification
description selected by you), the date of the inspection, and the
method used to conduct the inspection (i.e., AVO, OGI, Method 21 of
appendix A-7 to this part).
(ii) For each defect detected during the inspection you must record
the location of the defect; a description of the defect, the date of
detection, the maximum concentration reading obtained if using Method
21 of appendix A-7 to this part; the indication of emissions detected
by AVO if using AVO; the date of each attempt to repair the defect; the
corrective action taken during each attempt to repair the defect; and
the date the repair to correct the defect is completed.
(iii) If repair of the defect is delayed as described in Sec.
60.5416b(b)(6), you must record the reason for the delay and the date
you expect to complete the repair.
(iv) Parts of the cover designated as unsafe to inspect as
described in Sec. 60.5416b(b)(7) or difficult to inspect as described
in Sec. 60.5416b(b)(8), the reason for the designation, and written
plan for inspection of that part of the cover.
(10) For each bypass subject to the bypass requirements of Sec.
60.5416b(a)(4), you must maintain a record of the following, as
applicable: readings from the flow indicator; each inspection of the
seal or closure mechanism; the date and time of each instance the key
is checked out; date and time of each instance the alarm is sounded.
(11) Records for each control device used to comply with the
emission reduction standard in Sec. 60.5377b(b) for associated gas
wells, Sec. 60.5380b(a)(1) for centrifugal compressor affected
facilities, Sec. 60.5385b(d)(2) for reciprocating compressor affected
facilities, Sec. 60.5390b(b)(3) for your process controller affected
facility in Alaska, Sec. 60.5393b(b)(1) for your pump affected
facility, Sec. 60.5395b(a)(2) for your storage vessel affected
facility, Sec. 60.5376b(f) for well affected facility gas well liquids
unloading, or Sec. 60.5400b(f) or 60.5401b(e) for your process
equipment affected facility, as required in paragraphs (c)(11)(i)
through (viii) of this section. If you use an enclosed combustion
device or flare using an alternative test method approved under Sec.
60.5412b(d), keep records of the information in paragraphs (c)(11)(ix)
of this section, in lieu of the records required by paragraphs
(c)(11)(i) through (iv) and (vi) through (viii) of this section.
(i) For a control device tested under Sec. 60.5413b(d) which meets
the criteria in Sec. 60.5413b(d)(11) and (e), keep records of the
information in paragraphs (c)(11)(i)(A) through (E) of this section, in
addition to the records in paragraphs
[[Page 17122]]
(c)(11)(ii) through (ix) of this section, as applicable.
(A) Serial number of purchased device and copy of purchase order.
(B) Location of the affected facility associated with the control
device in latitude and longitude coordinates in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using the North
American Datum of 1983.
(C) Minimum and maximum inlet gas flow rate specified by the
manufacturer.
(D) Records of the maintenance and repair log as specified in Sec.
60.5413b(e)(4), for all inspection, repair, and maintenance activities
for each control device failing the visible emissions test.
(E) Records of the manufacturer's written operating instructions,
procedures, and maintenance schedule to ensure good air pollution
control practices for minimizing emissions.
(ii) For all control devices, keep records of the information in
paragraphs (c)(11)(ii)(A) through (G) of this section, as applicable.
(A) Make, model, and date of installation of the control device,
and identification of the affected facility controlled by the device.
(B) Records of deviations in accordance with Sec. 60.5417b(g)(1)
through (7), including a description of the deviation, the date and
time the deviation began, the duration of the deviation, and the cause
of the deviation.
(C) The monitoring plan required by Sec. 60.5417b(c)(2).
(D) Make and model number of each continuous parameter monitoring
system.
(E) Records of minimum and maximum operating parameter values,
continuous parameter monitoring system data (including records that the
pilot or combustion flame is present at all times), calculated averages
of continuous parameter monitoring system data, and results of all
compliance calculations.
(F) Records of continuous parameter monitoring system equipment
performance checks, system accuracy audits, performance evaluations, or
other audit procedures and results of all inspections specified in the
monitoring plan in accordance with Sec. 60.5417b(c)(2). Records of
calibration gas cylinders, if applicable.
(G) Periods of monitoring system malfunctions, repairs associated
with monitoring system malfunctions and required monitoring system
quality assurance or quality control activities Records of repairs on
the monitoring system.
(iii) For each carbon adsorption system, records of the schedule
for carbon replacement as determined by the design analysis
requirements of Sec. 60.5413b(c)(2) and (3) and records of each carbon
replacement as specified in Sec. 60.5412b(c)(1) and Sec.
60.5415b(f)(1)(viii).
(iv) For enclosed combustion devices and flares, records of visible
emissions observations as specified in paragraph (c)(11)(iv)(A) or (B)
of this section.
(A) Records of observations with Method 22 of appendix A-7 to this
part, including observations required following return to operation
from a maintenance or repair activity, which include: company,
location, company representative (name of the person performing the
observation), sky conditions, process unit (type of control device),
clock start time, observation period duration (in minutes and seconds),
accumulated emission time (in minutes and seconds), and clock end time.
You may create your own form including the above information or use
Figure 22-1 in Method 22 of appendix A-7 to this part.
(B) If you monitor visible emissions with a video surveillance
camera, location of the camera and distance to emission source, records
of the video surveillance output, and documentation that an operator
looked at the feed daily, including the date and start time of
observation, the length of observation, and length of time visible
emissions were present.
(v) For enclosed combustion devices and flares, video of the OGI
inspection conducted in accordance with Sec. 60.5415b(f)(x). Records
documenting each enclosed combustion device and flare was visibly
observed during each inspection conducted under Sec. 60.5397b using
AVO in accordance with Sec. 60.5415b(f)(x).
(vi) For enclosed combustion devices and flares, records of each
demonstration of the NHV of the inlet gas to the enclosed combustion
device or flare conducted in accordance with Sec. 60.5417b(d)(8)(iii).
For each re-evaluation of the NHV of the inlet gas, records of process
changes and explanation of the conditions that led to the need to re-
evaluation the NHV of the inlet gas. For each demonstration, record
information on whether the enclosed combustion device or flare has the
potential to receive inert gases, and if so, the highest percentage of
inert gases that can be sent to the enclosed combustion device or flare
and the highest percent of inert gases sent to the enclosed combustion
device or flare during the NHV demonstration. Records of periodic
sampling conducted under Sec. 60.5417b(d)(8)(iii)(G).
(vii) For enclosed combustion devices and flares, if you use a
backpressure regulator valve, the make and model of the valve, date of
installation, and record of inlet flow rating. Maintain records of the
engineering evaluation and manufacturer specifications that identify
the pressure set point corresponding to the minimum inlet gas flow
rate, the annual confirmation that the backpressure regulator valve set
point is correct and consistent with the engineering evaluation and
manufacturer specifications, and the annual confirmation that the
backpressure regulator valve fully closes when not in open position.
(viii) For enclosed combustion devices and flares, records of each
demonstration required under Sec. 60.5417b(d)(8)(iv).
(ix) If you use an enclosed combustion device or flare using an
alternative test method approved under Sec. 60.5412b(d), keep records
of the information in paragraphs (c)(11)(ix)(A) through (H) of this
section, in lieu of the records required by paragraphs (c)(11)(i)
through (iv) and (c)(11)(vi) through (viii) of this section.
(A) An identification of the alternative test method used.
(B) Data recorded at the intervals required by the alternative test
method.
(C) Monitoring plan required by Sec. 60.5417(i)(2).
(D) Quality assurance and quality control activities conducted in
accordance with the alternative test method.
(E) If required by Sec. 60.5412b(d)(4) to conduct visible
emissions observations, records required by paragraph (c)(11)(iv) of
this section.
(F) If required by Sec. 60.5412b(d)(5) to conduct pilot or
combustion flame monitoring, record indicating the presence of a pilot
or combustion flame and periods when the pilot or combustion flame is
absent.
(G) For each instance where there is a deviation of the control
device in accordance with Sec. 60.5417b(i)(6)(i) through (v), the date
and time the deviation began, the duration of the deviation in hours,
and cause of the deviation.
(H) Any additional information required to be recorded as specified
by the Administrator as part of the alternative test method approval
under Sec. 60.5412b(d).
(12) For each closed vent system routing to a control device or
process, the records of the assessment conducted according to Sec.
60.5411b(c):
[[Page 17123]]
(i) A copy of the assessment conducted according to Sec.
60.5411b(c)(1); and
(ii) A copy of the certification according to Sec.
60.5411b(c)(1)(i) and (ii).
(13) A copy of each performance test submitted under paragraphs
(b)(12) or (13) of this section.
(14) For the fugitive emissions components affected facility,
maintain the records identified in paragraphs (c)(14)(i) through (viii)
of this section.
(i) The date of the startup of production or the date of the first
day of production after modification for the fugitive emissions
components affected facility at a well site and the date of startup or
the date of modification for the fugitive emissions components affected
facility at a compressor station.
(ii) For the fugitive emissions components affected facility at a
well site, you must maintain records specifying what type of well site
it is (i.e., single wellhead only well site, small wellsite, multi-
wellhead only well site, or a well site with major production and
processing equipment.)
(iii) For the fugitive emissions components affected facility at a
well site where you complete the removal of all major production and
processing equipment such that the well site contains only one or more
wellheads, record the date the well site completes the removal of all
major production and processing equipment from the well site, and, if
the well site is still producing, record the well ID or separate tank
battery ID receiving the production from the well site. If major
production and processing equipment is subsequently added back to the
well site, record the date that the first piece of major production and
processing equipment is added back to the well site.
(iv) The fugitive emissions monitoring plan as required in Sec.
60.5397b(b), (c), and (d).
(v) The records of each monitoring survey as specified in
paragraphs (c)(14)(v)(A) through (I) of this section.
(A) Date of the survey.
(B) Beginning and end time of the survey.
(C) Name of operator(s), training, and experience of the
operator(s) performing the survey.
(D) Monitoring instrument or method used.
(E) Fugitive emissions component identification when Method 21 of
appendix A-7 to this part is used to perform the monitoring survey.
(F) Ambient temperature, sky conditions, and maximum wind speed at
the time of the survey. For compressor stations, operating mode of each
compressor (i.e., operating, standby pressurized, and not operating-
depressurized modes) at the station at the time of the survey.
(G) Any deviations from the monitoring plan or a statement that
there were no deviations from the monitoring plan.
(H) Records of calibrations for the instrument used during the
monitoring survey.
(I) Documentation of each fugitive emission detected during the
monitoring survey, including the information specified in paragraphs
(c)(14)(v)(I)(1) through (9) of this section.
(1) Location of each fugitive emission identified.
(2) Type of fugitive emissions component, including designation as
difficult-to-monitor or unsafe-to-monitor, if applicable.
(3) If Method 21 of appendix A-7 to this part is used for
detection, record the component ID and instrument reading.
(4) For each repair that cannot be made during the monitoring
survey when the fugitive emissions are initially found, a digital
photograph or video must be taken of that component or the component
must be tagged for identification purposes. The digital photograph must
include the date that the photograph was taken and must clearly
identify the component by location within the site (e.g., the latitude
and longitude of the component or by other descriptive landmarks
visible in the picture). The digital photograph or identification
(e.g., tag) may be removed after the repair is completed, including
verification of repair with the resurvey.
(5) The date of first attempt at repair of the fugitive emissions
component(s).
(6) The date of successful repair of the fugitive emissions
component, including the resurvey to verify repair and instrument used
for the resurvey.
(7) Identification of each fugitive emission component placed on
delay of repair and explanation for each delay of repair.
(8) For each fugitive emission component placed on delay of repair
for reason of replacement component unavailability, the operator must
document: the date the component was added to the delay of repair list,
the date the replacement fugitive component or part thereof was
ordered, the anticipated component delivery date (including any
estimated shipment or delivery date provided by the vendor), and the
actual arrival date of the component.
(9) Date of planned shutdowns that occur while there are any
components that have been placed on delay of repair.
(vi) For the fugitive emissions components affected facility
complying with an alternative means of emissions limitation under Sec.
60.5399b, you must maintain the records specified by the specific
alternative fugitive emissions standard for a period of at least 5
years.
(vii) For well closure activities, you must maintain the
information specified in paragraphs (c)(14)(vii)(A) through (G) of this
section.
(A) The well closure plan developed in accordance with Sec.
60.5397b(l) and the date the plan was submitted.
(B) The notification of the intent to close the well site and the
date the notification was submitted.
(C) The date of the cessation of production from all wells at the
well site.
(D) The date you began well closure activities at the well site.
(E) Each status report for the well closure activities reported in
paragraph (b)(9)(iv)(A) of this section.
(F) Each OGI survey reported in paragraph (b)(9)(iv)(B) of this
section including the date, the monitoring instrument used, and the
results of the survey or resurvey.
(G) The final OGI survey video demonstrating the closure of all
wells at the site. The video must include the date that the video was
taken and must identify the well site location by latitude and
longitude.
(viii) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(c)(14)(iv) and (v) of this section, you must maintain the records
specified in Sec. 60.5424b.
(15) For each pump affected facility, you must maintain the records
identified in paragraphs (c)(15)(i) through (ix) of this section.
(i) Identification of each pump that is driven by natural gas and
that is in operation 90 days or more per calendar year.
(ii) If you are complying with Sec. 60.5393b(a) or (b)(1) by
routing pump vapors to a process through a closed vent system,
identification of all the pumps in the pump affected facility for which
you collect and route vapors to a process through a closed vent system
and the records specified in paragraphs (c)(8), (10), and (12) of this
section. If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraph
(c)(8) of this section, you must provide the information specified in
Sec. 60.5424b.
(iii) If you are complying with Sec. 60.5393b(b)(1) by routing
pump vapors to control device achieving a 95.0
[[Page 17124]]
percent reduction in methane and VOC emissions, you must keep the
records specified in paragraphs (c)(8) and (10) through (c)(13) of this
section. If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraph
(c)(8) of this section, you must provide the information specified in
Sec. 60.5424b.
(iv) If you are complying with Sec. 60.5393b(b)(3) by routing pump
vapors to control device achieving less than a 95.0 percent reduction
in methane and VOC emissions, you must maintain records of the
certification that there is a control device on site but it does not
achieve a 95.0 percent emissions reduction and a record of the design
evaluation or manufacturer's specifications which indicate the
percentage reduction the control device is designed to achieve.
(v) If you have less than three natural gas-driven diaphragm pumps
in the pump affected facility, and you do not have a vapor recovery
unit or control device installed on site by the compliance date, you
must retain a record of your certification required under Sec.
60.5393b(b)(4), certifying that there is no vapor recovery unit or
control device on site. If you subsequently install a control device or
vapor recovery unit, you must maintain the records required under
paragraphs (c)(15)(ii), (iii) or (iv) of this section, as applicable.
(vi) If you determine, through an engineering assessment, that it
is technically infeasible to route the pump affected facility emissions
to a process or control device, you must retain records of your
demonstration and certification that it is technically infeasible as
required under Sec. 60.5393b(b)(5).
(vii) If the pump is routed to a control device that is
subsequently removed from the location or is no longer available such
that there is no option to route to a control device, you are required
to retain records of this change and the records required under
paragraph (c)(15)(vi) of this section.
(viii) Records of each change in compliance method, including
identification of each natural gas-driven pump which changes its method
of compliance, the new method of compliance, and the date of the change
in compliance method.
(ix) Records of each deviation, the date and time the deviation
began, the duration of the deviation, and a description of the
deviation.
(d) Electronic reporting. If you are required to submit
notifications or reports following the procedure specified in this
paragraph (d), you must submit notifications or reports to the EPA via
CEDRI, which can be accessed through the EPA's Central Data Exchange
(CDX) (https://cdx.epa.gov/). The EPA will make all the information
submitted through CEDRI available to the public without further notice
to you. Do not use CEDRI to submit information you claim as CBI.
Although we do not expect persons to assert a claim of CBI, if you wish
to assert a CBI claim for some of the information in the report or
notification, you must submit a complete file in the format specified
in this subpart, including information claimed to be CBI, to the EPA
following the procedures in paragraphs (g)(1) and (2) of this section.
Clearly mark the part or all of the information that you claim to be
CBI. Information not marked as CBI may be authorized for public release
without prior notice. Information marked as CBI will not be disclosed
except in accordance with procedures set forth in 40 CFR part 2. All
CBI claims must be asserted at the time of submission. Anything
submitted using CEDRI cannot later be claimed CBI. Furthermore, under
CAA section 114(c), emissions data is not entitled to confidential
treatment, and the EPA is required to make emissions data available to
the public. Thus, emissions data will not be protected as CBI and will
be made publicly available. You must submit the same file submitted to
the CBI office with the CBI omitted to the EPA via the EPA's CDX as
described earlier in this paragraph (d).
(1) The preferred method to receive CBI is for it to be transmitted
electronically using email attachments, File Transfer Protocol, or
other online file sharing services. Electronic submissions must be
transmitted directly to the OAQPS CBI Office at the email address
[email protected], and as described above, should include clear CBI
markings. ERT files should be flagged to the attention of the Group
Leader, Measurement Policy Group; all other files should be flagged to
the attention of the Oil and Natural Gas Sector Lead. If assistance is
needed with submitting large electronic files that exceed the file size
limit for email attachments, and if you do not have your own file
sharing service, please email [email protected] to request a file
transfer link.
(2) If you cannot transmit the file electronically, you may send
CBI information through the postal service to the following address:
U.S. EPA, Attn: OAQPS Document Control Officer, Mail Drop: C404-02, 109
T.W. Alexander Drive, P.O. Box 12055, RTP, NC 27711. ERT files should
be sent to the secondary attention of the Group Leader, Measurement
Policy Group, and all other files should be sent to the secondary
attention of the Oil and Natural Gas Sector Lead. The mailed CBI
material should be double wrapped and clearly marked. Any CBI markings
should not show through the outer envelope.
(e) Claims of EPA system outage. If you are required to
electronically submit a notification or report through CEDRI in the
EPA's CDX, you may assert a claim of EPA system outage for failure to
timely comply with that requirement. To assert a claim of EPA system
outage, you must meet the requirements outlined in paragraphs (e)(1)
through (7) of this section.
(1) You must have been or will be precluded from accessing CEDRI
and submitting a required report within the time prescribed due to an
outage of either the EPA's CEDRI or CDX systems.
(2) The outage must have occurred within the period of time
beginning five business days prior to the date that the submission is
due.
(3) The outage may be planned or unplanned.
(4) You must submit notification to the Administrator in writing as
soon as possible following the date you first knew, or through due
diligence should have known, that the event may cause or has caused a
delay in reporting.
(5) You must provide to the Administrator a written description
identifying:
(i) The date(s) and time(s) when CDX or CEDRI was accessed and the
system was unavailable;
(ii) A rationale for attributing the delay in reporting beyond the
regulatory deadline to EPA system outage;
(iii) A description of measures taken or to be taken to minimize
the delay in reporting; and
(iv) The date by which you propose to report, or if you have
already met the reporting requirement at the time of the notification,
the date you reported.
(6) The decision to accept the claim of EPA system outage and allow
an extension to the reporting deadline is solely within the discretion
of the Administrator.
(7) In any circumstance, the report must be submitted
electronically as soon as possible after the outage is resolved.
(f) Claims of force majeure. If you are required to electronically
submit a report or notification through CEDRI in the EPA's CDX, you may
assert a claim of force majeure for failure to timely comply with that
requirement. To assert a claim of force majeure, you must meet
[[Page 17125]]
the requirements outlined in paragraphs (f)(1) through (5) of this
section.
(1) You may submit a claim if a force majeure event is about to
occur, occurs, or has occurred or there are lingering effects from such
an event within the period of time beginning five business days prior
to the date the submission is due. For the purposes of this section, a
force majeure event is defined as an event that will be or has been
caused by circumstances beyond the control of the affected facility,
its contractors, or any entity controlled by the affected facility that
prevents you from complying with the requirement to submit a report
electronically within the time period prescribed. Examples of such
events are acts of nature (e.g., hurricanes, earthquakes, or floods),
acts of war or terrorism, or equipment failure or safety hazard beyond
the control of the affected facility (e.g., large scale power outage).
(2) You must submit notification to the Administrator in writing as
soon as possible following the date you first knew, or through due
diligence should have known, that the event may cause or has caused a
delay in reporting.
(3) You must provide to the Administrator:
(i) A written description of the force majeure event;
(ii) A rationale for attributing the delay in reporting beyond the
regulatory deadline to the force majeure event;
(iii) A description of measures taken or to be taken to minimize
the delay in reporting; and
(iv) The date by which you propose to report, or if you have
already met the reporting requirement at the time of the notification,
the date you reported.
(4) The decision to accept the claim of force majeure and allow an
extension to the reporting deadline is solely within the discretion of
the Administrator.
(5) In any circumstance, the reporting must occur as soon as
possible after the force majeure event occurs.
Sec. 60.5421b What are my additional recordkeeping requirements for
process unit equipment affected facilities?
You must maintain a record of each equipment leak monitoring
inspection and each leak identified under Sec. 60.5400b and Sec.
60.5401b as specified in paragraphs (b)(1) through (16) of this
section. The record must be maintained either onsite or at the nearest
local field office for at least 5 years. Any records required to be
maintained that are submitted electronically via the EPA's CEDRI may be
maintained in electronic format. This ability to maintain electronic
copies does not affect the requirement for facilities to make records,
data, and reports available upon request to a delegated air agency or
the EPA as part of an on-site compliance evaluation.
(a) You may comply with the recordkeeping requirements for multiple
process unit equipment affected facilities in one recordkeeping system
if the system identifies each record by each facility.
(b) You must maintain the monitoring inspection records specified
in paragraphs (b)(1) through (16) of this section.
(1) Equipment Identification. Note that connectors need not be
individually identified if all connectors in a designated area or
length of pipe subject to the provisions of this subpart are identified
as a group, and the number of connectors subject is indicated.
(2) Date and start and end times of the monitoring inspection.
(3) Inspector name.
(4) Leak determination method used for the monitoring inspection
(i.e., OGI, Method 21, or AVO).
(5) Monitoring instrument identification (OGI and Method 21 only).
(6) Type of equipment monitored.
(7) Process unit identification.
(8) The records specified in Section 12 of appendix K of this part,
for each monitoring inspection conducted with OGI.
(9) The records in paragraph (b)(9)(i) through (vii), for each
monitoring inspection conducted with Method 21 of appendix A-7 to this
part.
(i) Instrument reading.
(ii) Date and time of instrument calibration and initials of
operator performing the calibration.
(iii) Calibration gas cylinder identification, certification date,
and certified concentration.
(iv) Instrument scale used.
(v) A description of any corrective action taken if the meter
readout could not be adjusted to correspond to the calibration gas
value in accordance with section 10.1 of Method 21 of appendix A-7 to
this part.
(vi) Results of the daily calibration drift assessment.
(vii) If you make your own calibration gas, a description of the
procedure used.
(10) For visual inspections of pumps in light liquid service, keep
the records specified in paragraphs (b)(10)(i) through (iii), for each
monitored equipment:
(i) Date of inspection.
(ii) Inspector name.
(iii) Result of inspection (i.e., visual indications of liquids
dripping from the pump seal or no visual indications of liquids
dripping from the pump seal).
(11) For each leak detected, the records specified in paragraphs
(b)(11)(i) through (v) of this section:
(i) The instrument and operator identification numbers and the
process unit and equipment identification numbers. For leaks identified
via AVO methods, enter the specific sensory method for instrument
identification number.
(ii) The date the leak was detected.
(iii) For each attempt to repair the leak, record:
(A) The date.
(B) The repair method applied.
(C) Indication of whether a leak was still detected following each
attempt to repair the leak.
(vi) The date of successful repair of the leak and the method of
monitoring used to confirm the repair, as specified in paragraph
(b)(11)(vi)(A) through (C) of this section.
(A) If Method 21 of appendix A-7 to this part is used to confirm
the repair, maintain a record of the maximum instrument reading
measured by Method 21 of appendix A-7 to this part.
(B) If OGI conducted in accordance with appendix K of this part is
used to confirm the repair, maintain a record of video footage of the
repair confirmation.
(C) If the leak is repaired by eliminating AVO indications of a
leak, maintain a record of the specific sensory method used to confirm
that the evidence of the leak is eliminated.
(v) For each repair delayed beyond 15 calendar days after detection
of the leak, record:
(A) ``Repair delayed'' and the reason for the delay.
(B) The signature of the certifying official who made the decision
that repair could not be completed without a process shutdown.
(C) The expected date of successful repair of the leak.
(D) Dates of process unit shutdowns that occur while the equipment
is unrepaired.
(12) A list of identification numbers for equipment that are
designated for no detectable emissions complying with the provisions of
Sec. 60.5401b.
(13) A list of identification numbers for valves, pumps, and
connectors that are designated as unsafe-to-monitor, an explanation for
each valve, pump, or connector stating why the valve, pump, or
connector is unsafe-to-monitor, and the plan for monitoring each valve,
pump, or connector.
(14) A list of identification numbers for valves that are
designated as difficult-to-monitor, an explanation for each valve
stating why the valve is difficult-to-monitor, and the schedule for
monitoring each valve.
[[Page 17126]]
(15) A list of identification numbers for equipment that is in
vacuum service.
(16) A list of identification numbers for equipment you designate
as having the potential to emit methane or VOC less than 300 hr/yr.
(17) A list of identification numbers for valves where it was
infeasible to replace leaking valves with low-e valves or repack
existing valves with low-e packing technology, including the reasoning
for why it was infeasible.
Sec. 60.5422b What are my additional reporting requirements for
process unit equipment affected facilities?
(a) You must submit semiannual reports using the appropriate
electronic report template on the CEDRI website for this subpart and
following the procedure specified in Sec. 60.5420b(d). If the
reporting form specific to this subpart is not available on the CEDRI
website at the time that the report is due, submit the report to the
Administrator at the appropriate address listed in Sec. 60.4. Once the
form has been available on the CEDRI website for at least 90 calendar
days, you must begin submitting all subsequent reports via CEDRI. The
date reporting forms become available will be listed on the CEDRI
website. Unless the Administrator or delegated state agency or other
authority has approved a different schedule for submission of reports,
the report must be submitted within 45 days after the end of the
semiannual reporting period, regardless of the method in which the
report is submitted.
(b) The initial semiannual report must include the following
information:
(1) The general information specified in paragraph (c)(1) of this
section.
(2) For each process unit:
(i) Process unit identification.
(ii) Number of valves subject to the monitoring requirements of
Sec. Sec. 60.5400b(b) and 60.5401b(f).
(iii) Number of pumps subject to the monitoring requirements of
Sec. Sec. 60.5400b(b) and 60.5401b(b).
(iv) Number of connectors subject to the monitoring requirements of
Sec. Sec. 60.5400b(b) and 60.5401b(h).
(v) Number of pressure relief devices subject to the monitoring
requirements of Sec. Sec. 60.5400b(b) and 60.5401b(c).
(vi) The information in paragraphs (c)(3) and (4) of this section.
(c) All subsequent semiannual reports must include the following
information:
(1) The general information specified in paragraphs (c)(1)(i)
through (iii) of this section.
(i) The company name, facility site name, and address of the
affected facility.
(ii) Beginning and ending dates of the reporting period.
(iii) A certification by a certifying official of truth, accuracy,
and completeness. This certification shall state that, based on
information and belief formed after reasonable inquiry, the statements
and information in the document are true, accurate, and complete. If
your report is submitted via CEDRI, the certifier's electronic
signature during the submission process replaces the requirement in
this paragraph (c)(1)(iii).
(2) Process unit identification for each process unit.
(3) For each month during the semiannual reporting period for each
process unit report:
(i) Number of valves for which leaks were detected as described in
Sec. 60.5400b(b) or Sec. 60.5401b(f).
(ii) Number of valves for which leaks were not repaired as required
in Sec. 60.5400b(h) or Sec. 60.5401b(i), the number of instances
where it was technically infeasible to replace leaking valves with low-
e valves or repack existing valves with low-e packing technology,
including the reasoning for why it was technically infeasible.
(iii) Number of pumps for which leaks were detected as described
Sec. 60.5400b(b) or Sec. 60.5401b(b).
(iv) Number of pumps for which leaks were not repaired as required
in Sec. 60.5400b(h) or Sec. 60.5401b(i).
(v) Number of connectors for which leaks were detected as described
in Sec. 60.5400b(b) or Sec. 60.5401b(h).
(vi) Number of connectors for which leaks were not repaired as
required in Sec. 60.5400b(h) or Sec. 60.5401b(i).
(vii) Number of pressure relief devices for which leaks were
detected as described in Sec. 60.5400b(b) or Sec. 60.5401b(c).
(viii) Number of pressure relief devices for which leaks were not
repaired as required in Sec. 60.5400b(h) or Sec. 60.5401b(i).
(ix) Number of open-ended valves or lines for which leaks were
detected as described in Sec. 60.5400b(e) or Sec. 60.5401b(d).
(x) Number of open-ended valves or lines for which leaks were not
repaired as required in Sec. 60.5400b(h) or Sec. 60.5401b(i).
(xi) Number of pumps, valves, or connectors in heavy liquid service
or pressure relief device in light liquid or heavy liquid service for
which leaks were detected as described in Sec. 60.5400b(g) or Sec.
60.5401b(g).
(xii) Number of pumps, valves, or connectors in heavy liquid
service or pressure relief device in light liquid or heavy liquid
service for which leaks were not repaired as required in Sec.
60.5400b(h) or Sec. 60.5401b(i).
(xiii) The facts that explain each delay of repair and, where
appropriate, why a process unit shutdown was technically infeasible.
(4) Dates of process unit shutdowns which occurred within the
semiannual reporting period.
(5) Revisions to items reported according to paragraph (b) of this
section if changes have occurred since the initial report or subsequent
revisions to the initial report.
Sec. 60.5423b What are my additional recordkeeping and reporting
requirements for sweetening unit affected facilities?
(a) You must retain records of the calculations and measurements
required in Sec. Sec. 60.5405b(a) and (b) and 60.5407b(a) through (g)
for at least 2 years following the date of the measurements. This
requirement is included under Sec. 60.7(f) of the General Provisions.
(b) In your initial annual report submitted in accordance with the
procedures and schedule in Sec. 60.5420b(b), include the information
in paragraphs (b)(1) and (2) of this section.
(1) For each run of the initial performance test required by Sec.
60.8(b):
(i) The average sulfur feed rate in Mg/D, determined according to
Sec. 60.5406b(b).
(ii) The average volumetric flow rate of acid gas from the
sweetening unit, in dscm/day.
(iii) The H2S concentration in the acid gas feed from
the sweetening unit, percent by volume.
(iv) The emission rate of sulfur in kg/hr.
(v) The sulfur production rate in kg/hr.
(vi) The emission reduction efficiency achieved by the sulfur
recovery technology, determined according to Sec. 60.5406b(c).
(vii) The required initial SO2 emission reduction
efficiency, as determined from table 3 to this subpart based on the
sulfur feed rate and the sulfur content of the acid gas of the affected
facility.
(2) The required minimum SO2 emission reduction
efficiency you must achieve on a continuous basis, as determined from
table 4 to this subpart based on the sulfur feed rate and the sulfur
content of the acid gas of the affected facility.
(c) You must submit the performance test report in accordance with
the requirements of Sec. 60.5420b(b)(12).
(d) You must submit a report of excess emissions to the
Administrator in your annual report if you had excess
[[Page 17127]]
emissions during the reporting period. The procedures and schedule for
submitting annual reports are located in Sec. 60.5420b(b). For the
purpose of these reports, excess emissions are defined as specified in
paragraphs (d)(1) and (2) of this section. The report must contain the
information specified in paragraph (d)(3) of this section.
(1) Any 24-hour period (at consistent intervals) during which the
average sulfur emission reduction efficiency (R) is less than the
minimum required efficiency (Z).
(2) For any affected facility electing to comply with the
provisions of Sec. 60.5407b(b)(2), any 24-hour period during which the
average temperature of the gases leaving the combustion zone of an
incinerator is less than the appropriate operating temperature as
determined during the most recent performance test in accordance with
the provisions of Sec. 60.5407b(b)(3). Each 24-hour period must
consist of at least 96 temperature measurements equally spaced over the
24 hours.
(3) For each period of excess emissions during the reporting
period, include the following information in your report:
(i) The date and time of commencement and completion of each period
of excess emissions;
(ii) The required minimum efficiency (Z) and the actual average
sulfur emissions reduction (R) for periods defined in paragraph (d)(1)
of this section; and
(iii) The appropriate operating temperature and the actual average
temperature of the gases leaving the combustion zone for periods
defined in paragraph (d)(2) of this section.
(e) To certify that a facility is exempt from the control
requirements of these standards, for each facility with a design
capacity less than 2 LT/D of H2S in the acid gas (expressed
as sulfur) you must keep, for the life of the facility, an analysis
demonstrating that the facility's design capacity is less than 2 LT/D
of H2S expressed as sulfur.
(f) If you elect to comply with Sec. 60.5407b(e) you must keep,
for the life of the facility, a record demonstrating that the
facility's design capacity is less than 150 LT/D of H2S
expressed as sulfur.
(g) The requirements of paragraph (d) of this section remain in
force until and unless the EPA, in delegating enforcement authority to
a state under section 111(c) of the Act, approves reporting
requirements or an alternative means of compliance surveillance adopted
by such state. In that event, affected sources within the state will be
relieved of obligation to comply with paragraph (d) of this section,
provided they comply with the requirements established by the state.
Electronic reporting to the EPA cannot be waived, and as such, the
provisions of this paragraph do not relieve owners or operators of
affected facilities of the requirement to submit the electronic reports
required in this section to the EPA.
Sec. 60.5424b What are my additional recordkeeping and reporting
requirements if I comply with the alternative GHG and VOC standards for
fugitive emissions components affected facilities and covers and closed
vent systems?
This section provides notification, reporting, and recordkeeping
requirements for owners and operators who choose to comply with an
alternative GHG and VOC standard as specified in Sec. 60.5398b for
fugitive emissions components affected facilities and the alternative
continuous inspection and monitoring requirements for covers and closed
vent systems. You must submit an annual report in accordance with the
schedule in Sec. 60.5420b(b) which includes the information in
paragraphs (a)(1), (b), and (d) of this section, as applicable. You
must submit the notification in paragraph (a)(2) of this section and
maintain the records in paragraphs (c) and (e) of this section, as
applicable.
(a) Notifications. If you choose to comply with an alternative GHG
and VOC standard as specified in Sec. 60.5398b for fugitive emissions
components affected facilities and the alternative continuous
inspection and monitoring requirements for covers and closed vent
systems, you must submit the notification in paragraph (a)(1) of this
section. If you are required by Sec. 60.5398b(c)(8) to develop a mass
emission rate reduction plan, you must submit the notification in
paragraph (a)(2) of this section.
(1) A notification to the Administrator of adoption of the
alternative standards in the annual report required by Sec.
60.5420b(b)(4) through (11).
(2) A notification, which includes the submittal of the mass
emission rate reduction plan required by Sec. 60.5398b(c)(8). You must
submit the mass emission rate reduction plan to the Administrator
within 60 days of the initial exceedance of the action level.
(b) Information submittal. If you comply with the periodic
screening requirements of Sec. 60.5398b(b), you must submit the
information in paragraphs (b)(1) through (6) of this section in the
annual report required by Sec. 60.5420b(b)(4) through (11).
(1) Date of each periodic screening during the reporting period and
date that results of the periodic screening were received.
(2) Alternative test method and technology used for each screening
and the spatial resolution of the technology (i.e., facility-level,
area-level, or component-level).
(3) Any deviations from the monitoring plan developed under Sec.
60.5398b(b)(2) or a statement that there were no deviations from the
monitoring plan.
(4) Results from each periodic screening during the reporting
period. If the results of the periodic screening indicate a confirmed
detection of emissions from an affected facility, you must submit the
information in paragraphs (b)(4)(i) through (iv) of this section.
(i) The date that the monitoring survey of your entire or the
required portion of your fugitive emissions components affected
facility was conducted.
(ii) The date that you completed the instrument inspections of all
required covers and closed vent systems(s).
(iii) The date that you conducted the visual inspection for
emissions of all required covers and closed vent systems.
(iv) For each fugitive emission from a fugitive emissions
components affected facility and all emissions or defects of each cover
and closed vent system, you must submit the information in paragraphs
(b)(4)(iv)(A) through (D) of this section.
(A) Number and type of components for which fugitive emissions were
detected.
(B) Each emission or defect identified during the inspection for
each cover and closed vent system.
(C) Date of repair for each fugitive emission from a fugitive
emissions components affected facility or each emission or defect for
each cover and closed vent system.
(D) Number and type of fugitive emission components and
identification of each cover or closed vent system placed on delay of
repair and an explanation for each delay of repair.
(5) The information in paragraphs (b)(5)(i) through (iv) of this
section if you are required to conduct OGI surveys in accordance with
Sec. 60.5398b(b)(1)(i) or if you replace a periodic screening event
with an OGI survey in accordance with Sec. 60.5398b(b)(1)(iv).
(i) The date of the OGI survey.
(ii) Number and type of components for which fugitive emissions
were detected.
(iii) Number and type of fugitive emissions components that were
not repaired as required in Sec. 60.5397b(h).
[[Page 17128]]
(iv) Number and type of fugitive emission components placed on
delay of repair and an explanation for each delay of repair.
(6) Any additional information regarding the performance of the
periodic screening technology as specified by the Administrator, as
part of the alternative test method approval described in Sec.
60.5398b(d).
(c) Maintain records. If you comply with the periodic screening
requirements of Sec. 60.5398b(b), you must maintain the records in
paragraphs (c)(1) through (11) of this section in addition to the
records as specified in Sec. 60.5420b(c)(3) through (9) and (c)(14)
and (15).
(1) The monitoring plan as required in Sec. 60.5398b(b)(2).
(2) Date of each periodic screening and date that results of the
periodic screening were received.
(3) Name of screening operator.
(4) Alternative test method and technology used for screening, as
well as the aggregate detection threshold for the technology and the
spatial resolution of the technology (i.e., facility-level, area-level,
or component-level).
(5) Records of calibrations for technology used during the
screening if calibration is required by the alternative test method
approved in accordance with Sec. 60.5398b(d).
(6) Results from periodic screening. If the results of the periodic
screening indicate a confirmed detection of emissions from an affected
facility, you must maintain the records in paragraphs (c)(6)(i) through
(v) of this section.
(i) The date of the inspection of the fugitive emissions components
and inspection of covers and closed vent system, as specified in Sec.
60.5398b(b)(5).
(ii) Name of operator(s) performing the survey or inspection.
(iii) For surveys and instrument inspections, identification of the
monitoring instrument(s) used.
(iv) Records of calibrations for the instrument(s) used during the
survey or instrument inspection, as applicable.
(v) For each fugitive emission from a fugitive emissions components
affected facility and each leak or defect for each cover and closed
vent system inspection, you must maintain the records in paragraphs
(c)(6)(v)(A) through (F) of this section.
(A) The location of the fugitive emissions identified using a
unique identifier for the source of the emissions and the type of
fugitive emissions component.
(B) The location of the emission or defect from a cover or closed
vent system using a unique identifier for the source of the emission or
defect.
(C) If a defect of a closed vent system, cover, or control device
is identified, a description of the defect.
(D) The date of repair for each fugitive emission from a fugitive
emissions components affected facility or each emission or defect for
each cover and closed vent system.
(E) Number and type of fugitive emission components and
identification of each cover or closed vent system placed on delay of
repair and an explanation for each delay of repair.
(F) For each fugitive emission component placed on delay of repair
for reason of replacement component unavailability, the operator must
document: the date the component was added to the delay of repair list,
the date the replacement fugitive component or part thereof was
ordered, the anticipated component delivery date (including any
estimated shipment or delivery date provided by the vendor), and the
actual arrival date of the component.
(7) The date the investigative analysis was initiated, and the
result of the investigative analysis conducted in accordance with Sec.
60.5398b(b)(5)(vi) and (vii), as applicable.
(8) Dates of implementation and completion of action(s) taken as a
result of the investigative analysis and a description of the action(s)
taken in accordance with Sec. 60.5398b(b)(5)(vi) and (vii), as
applicable.
(9) The information in paragraphs (c)(9)(i) through (vii) of this
section if you are required to conduct OGI surveys in accordance with
Sec. 60.5398b(b)(1)(i) or if you replace a periodic screening event
with an OGI survey in accordance with Sec. 60.5398b(b)(1)(iv).
(i) The date of the OGI survey.
(ii) Location of each fugitive emission identified.
(iii) Type of fugitive emissions component for which fugitive
emissions were detected.
(iv) The date of first attempt at repair of the fugitive emissions
component(s).
(v) The date of successful repair of the fugitive emissions
component(s), including the resurvey to verify the repair.
(vi) Identification of each fugitive emissions component placed on
delay of repair and an explanation for each delay of repair.
(vii) For each fugitive emission component placed on delay of
repair for reason of replacement component unavailability, the operator
must document: the date the component was added to the delay of repair
list, the date the replacement fugitive component or part thereof was
ordered, the anticipated component delivery date (including any
estimated shipment or delivery date provided by the vendor), and the
actual arrival date of the component.
(10) Any deviations from the monitoring plan or a statement that
there were no deviations from the monitoring plan.
(11) All records required by the alternative approved in accordance
with Sec. 60.5398b(d).
(d) Information submittal. If you comply with the continuous
monitoring system requirements of Sec. 60.5398b(c), you must submit
the information in paragraphs (d)(1) through (6) of this section in the
annual report required by Sec. 60.5420b(b)(4) through (11).
(1) The start date and end date for each period where the emissions
rate determined in accordance with Sec. 60.5398b(c)(6) exceeded one of
the action levels determined in accordance with Sec. 60.5398b(c)(4).
Include which action level was exceeded (the 7-day or 90-day rolling
average), the numerical value of the action level, and the mass
emission rate calculated by the continuous monitoring system in the
report.
(2) The date the investigative analysis was initiated, and the
result of the investigative analysis conducted in accordance with Sec.
60.5398b(c)(7), as applicable.
(3) Dates of implementation and completion of action(s) taken to
reduce the mass emission rate and a description of the action(s) taken
in accordance with Sec. 60.5398b(c)(7), as applicable.
(4) If there are no instances reported under paragraph (d)(1) of
this section, report your numerical action levels and the highest 7-day
rolling average and highest 90-day rolling average determined by your
continuous monitoring system during the reporting period.
(5) The start date for each instance where the 12-month rolling
average operational downtime of the system exceeded 10 percent and the
value of the 12-month rolling average operational downtime during the
period. If there were no instances during the reporting period where
the 12-month rolling average operational downtime of the system
exceeded 10 percent, report the highest value of the 12-month rolling
average operational downtime during the reporting period.
(6) Any additional information regarding the performance of the
continuous monitoring system as specified by the Administrator, as part
of the alternative test method approval described in Sec. 60.5398b(d).
(e) Maintain records. If you comply with the continuous monitoring
system
[[Page 17129]]
requirements of Sec. 60.5398b(c), you must maintain the records in
paragraphs (e)(1) through (15) of this section.
(1) The monitoring plan required by Sec. 60.5398b(c)(2).
(2) Date of commencement of continuous monitoring with your
continuous monitoring system.
(3) The detection threshold of the continuous monitoring system.
(4) The results of checks for power and function in accordance with
Sec. 60.5398b(c)(1)(ii).
(5) The beginning and end of each period of operational downtime
for the system.
(6) Each rolling 12-month average operational downtime for the
system, calculated in accordance with Sec. 60.5398b(c)(1)(ii)(D).
(7) The 7-day rolling average and 90-day rolling average action
levels for the site determined in accordance with Sec. 60.5398b(c)(4).
(8) The information in paragraphs (e)(8)(i) through (v) of this
section each time you establish site-specific baseline emissions in
accordance with Sec. 60.5398b(c)(5).
(i) Records of inspections of fugitive emissions components,
covers, and closed vent systems required by Sec. 60.5398b(c)(5)(i),
including the date of inspection, location of each emission or defect
identified, date of successful repair of each fugitive emissions
component, cover, or closed vent system.
(ii) Records of inspections of control devices required by Sec.
60.5398b(c)(5)(ii), including the date of the inspection and the
results of the inspection.
(iii) The start date and time and end date and time of any
maintenance activities that occurred during the 30 operating day
period.
(iv) The site-level emission rate for each day during the 30
operating day period.
(v) The calculated site-specific baseline emission rate.
(9) Each methane mass emission rate reading determined by the
system.
(10) Each daily, 7-day, and 90-day average mass emission rate which
was determined in accordance with Sec. 60.5398b(c)(6). If you exceed
the 90-day action level, you must also keep records of the 30-day
average mass emission rate following completion of the initial actions
to reduce the average mass emission rate, in accordance with Sec.
60.5398b(c)(8)(i).
(11) The results of each comparison of the emissions rate
determined in accordance with Sec. 60.5398b(c)(6) to the action level
determined in accordance with Sec. 60.5398b(c)(4).
(12) The date the investigative analysis was initiated, and the
result of the investigative analysis conducted in accordance with Sec.
60.5398b(c)(7), as applicable.
(13) Dates of implementation and completion of action(s) taken to
reduce the mass emission rate below the action level and a description
of the action(s) taken in accordance with Sec. 60.5398b(c)(7), as
applicable.
(14) Each mass emission rate reduction plan developed in accordance
with Sec. 60.5398b(c)(8), as applicable. You must keep records of the
actions taken in accordance with the plan and the date such actions are
taken.
(15) Any additional information regarding the performance of the
continuous monitoring technology as specified by the Administrator, as
part of the alternative test method approval described in Sec.
60.5398b(d).
Sec. 60.5425b What parts of the General Provisions apply to me?
Table 5 to this subpart shows which parts of the General Provisions
in Sec. Sec. 60.1 through 60.19 apply to you.
Sec. 60.5430b What definitions apply to this subpart?
As used in this subpart, all terms not defined herein shall have
the meaning given them in the Act or in subpart A of this part; and the
following terms shall have the specific meanings given them.
Access to electrical power means commercial line power is available
onsite, with sufficient capacity to support the required power loading
of onsite equipment, and which provides reliable and consistent power.
Acid gas means a gas stream of hydrogen sulfide (H2S)
and carbon dioxide (CO2) that has been separated from sour
natural gas by a sweetening unit.
Alaskan North Slope means the approximately 69,000 square-mile area
extending from the Brooks Range to the Arctic Ocean.
API Gravity means the weight per unit volume of hydrocarbon liquids
as measured by a system recommended by the American Petroleum Institute
(API) and is expressed in degrees.
Artificial lift equipment means mechanical pumps including, but not
limited to, rod pumps and electric submersible pumps used to flowback
fluids from a well.
Associated gas means the natural gas from wells operated primarily
for oil production that is released from the liquid hydrocarbon during
the initial stage of separation after the wellhead. Associated gas
production begins at the startup of production after the flow back
period ends. Gas from wildcat or delineation wells is not associated
gas.
Average aggregate detection threshold means:
(1) For the purposes of Sec. 60.5398b, the average of all site-
level detection thresholds from a single deployment (e.g., a singular
flight that surveys multiple well sites, centralized production
facility, and/or compressor stations) of a technology; and
(2) For the purposes of Sec. 60.5371b, the average of all site-
level detection thresholds from a single deployment in the same basin
and field.
Bleed rate means the rate in standard cubic feet per hour at which
natural gas is continuously vented (bleeds) from a process controller.
Capital expenditure means, as an alternative to the definition in
40 CFR 60.2, an expenditure for a physical or operational change to an
existing facility that:
(1) Exceeds P, the product of the facility's replacement cost, R,
and an adjusted annual asset guideline repair allowance, A, as
reflected by the following equation: P = R x A, where:
(i) The adjusted annual asset guideline repair allowance, A, is the
product of the percent of the replacement cost, Y, and the applicable
basic annual asset guideline repair allowance, B, divided by 100 as
reflected by the following equation: A = Y x (B / 100);
(ii) The percent Y is determined from the following equation: Y =
(CPI of date of construction/most recently available CPI of date of
project), where the ``CPI-U, U.S. city average, all items'' must be
used for each CPI value; and
(iii) The applicable basic annual asset guideline repair allowance,
B, is 4.5.
(2) [Reserved]
Centralized production facility means one or more storage vessels
and all equipment at a single surface site used to gather, for the
purpose of sale or processing to sell, crude oil, condensate, produced
water, or intermediate hydrocarbon liquid from one or more offsite
natural gas or oil production wells. This equipment includes, but is
not limited to, equipment used for storage, separation, treating,
dehydration, artificial lift, combustion, compression, pumping,
metering, monitoring, and flowline. Process vessels and process tanks
are not considered storage vessels or storage tanks. A centralized
production facility is located upstream of the natural gas processing
plant or the crude oil pipeline breakout station and is a part of
producing operations.
Centrifugal compressor means any machine for raising the pressure
of a natural gas by drawing in low pressure natural gas and discharging
significantly
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higher-pressure natural gas by means of mechanical rotating vanes or
impellers. Screw, sliding vane, and liquid ring compressors are not
centrifugal compressors for the purposes of this subpart.
Centrifugal compressor equipped with sour seal oil separator and
capture system means a wet seal centrifugal compressor system which has
an intermediate closed process that degasses most of the gas entrained
in the sour seal oil and sends that gas to either another process or
combustion device (i.e., degassed emissions are recovered). The de-gas
emissions are routed back to a process or combustion device directly
from the intermediate closed degassing process; after the intermediate
closed process the oil is ultimately recycled for recirculation in the
seals to the lube oil tank where any small amount of residual gas is
released through a vent.
Certifying official means one of the following:
(1) For a corporation: A president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business
function, or any other person who performs similar policy or decision-
making functions for the corporation, or a duly authorized
representative of such person if the representative is responsible for
the overall operation of one or more manufacturing, production, or
operating facilities with an affected facility subject to this subpart
and either:
(i) The facilities employ more than 250 persons or have gross
annual sales or expenditures exceeding $25 million (in second quarter
1980 dollars); or
(ii) The Administrator is notified of such delegation of authority
prior to the exercise of that authority. The Administrator reserves the
right to evaluate such delegation;
(2) For a partnership (including but not limited to general
partnerships, limited partnerships, and limited liability partnerships)
or sole proprietorship: A general partner or the proprietor,
respectively. If a general partner is a corporation, the provisions of
paragraph (1) of this definition apply;
(3) For a municipality, state, Federal, or other public agency:
Either a principal executive officer or ranking elected official. For
the purposes of this part, a principal executive officer of a Federal
agency includes the chief executive officer having responsibility for
the overall operations of a principal geographic unit of the agency
(e.g., a Regional Administrator of EPA); or
(4) For affected facilities:
(i) The designated representative in so far as actions, standards,
requirements, or prohibitions under title IV of the CAA or the
regulations promulgated thereunder are concerned; or
(ii) The designated representative for any other purposes under
this part.
Closed vent system means a system that is not open to the
atmosphere and that is composed of hard-piping, ductwork, connections,
and, if necessary, flow-inducing devices that transport gas or vapor
from a piece or pieces of equipment to a control device or back to a
process.
Coil tubing cleanout means the process where an operator runs a
string of coil tubing to the packed proppant within a well and jets the
well to dislodge the proppant and provide sufficient lift energy to
flow it to the surface. Coil tubing cleanout includes mechanical
methods to remove solids and/or debris from a wellbore.
Collection system means any infrastructure that conveys gas or
liquids from the well site to another location for treatment, storage,
processing, recycling, disposal or other handling.
Completion combustion device means any ignition device, installed
horizontally or vertically, used in exploration and production
operations to combust otherwise vented emissions from completions.
Completion combustion devices include pit flares.
Compressor mode means the operational and pressurized status of a
compressor. For both centrifugal compressors and reciprocating
compressors, ``mode'' refers to either: Operating-mode, standby-
pressurized-mode, or not-operating-depressurized-mode.
Compressor station means any permanent combination of one or more
compressors that move natural gas at increased pressure through
gathering or transmission pipelines, or into or out of storage. This
includes but is not limited to gathering and boosting stations and
transmission compressor stations. The combination of one or more
compressors located at a well site, centralized production facility, or
an onshore natural gas processing plant, is not a compressor station
for purposes of Sec. 60.5365b(e) and Sec. 60.5397b.
Condensate means hydrocarbon liquid separated from natural gas that
condenses due to changes in the temperature, pressure, or both, and
remains liquid at standard conditions.
Connector means flanged, screwed, or other joined fittings used to
connect two pipe lines or a pipe line and a piece of process equipment
or that close an opening in a pipe that could be connected to another
pipe. Joined fittings welded completely around the circumference of the
interface are not considered connectors for the purpose of this
regulation.
Continuous bleed means a continuous flow of pneumatic supply
natural gas to a process controller.
Crude oil and natural gas source category means:
(1) Crude oil production, which includes the well and extends to
the point of custody transfer to the crude oil transmission pipeline or
any other forms of transportation; and
(2) Natural gas production, processing, transmission, and storage,
which include the well and extend to, but do not include, the local
distribution company custody transfer station.
Custody meter means the meter where natural gas or hydrocarbon
liquids are measured for sales, transfers, and/or royalty
determination.
Custody meter assembly means an assembly of fugitive emissions
components, including the custody meter, valves, flanges, and
connectors necessary for the proper operation of the custody meter.
Custody transfer means the transfer of crude oil or natural gas
after processing and/or treatment in the producing operations, or from
storage vessels or automatic transfer facilities or other such
equipment, including product loading racks, to pipelines or any other
forms of transportation.
Dehydrator means a device in which an absorbent directly contacts a
natural gas stream and absorbs water in a contact tower or adsorption
column (absorber).
Delineation well means a well drilled in order to determine the
boundary of a field or producing reservoir.
Deviation means any instance in which an affected source subject to
this subpart, or an owner or operator of such a source:
(1) Fails to meet any requirement or obligation established by this
subpart including, but not limited to, any emission limit, operating
limit, or work practice standard;
(2) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit; or
(3) Fails to meet any emission limit, operating limit, or work
practice standard of this subpart during startup, shutdown, or
malfunction, regardless of whether or not such failure is permitted by
this subpart.
Distance piece means an open or enclosed casing through which the
piston rod travels, separating the compressor cylinder from the
crankcase.
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Double block and bleed system means two block valves connected in
series with a bleed valve or line that can vent the line between the
two block valves.
Duct work means a conveyance system such as those commonly used for
heating and ventilation systems. It is often made of sheet metal and
often has sections connected by screw or crimping. Hard-piping is not
ductwork.
Emergency shutdown device means a device which functions
exclusively to protect personnel and/or prevent physical damage to
equipment by shutting down equipment or gas flow during unsafe
conditions resulting from an unexpected event, such as a pipe break or
fire. For the purposes of this subpart, an emergency shutdown device is
not used for routine control of operating conditions.
Equipment, as used in the standards and requirements of this
subpart relative to the process unit equipment affected facility at
onshore natural gas processing plants, means each pump, pressure relief
device, open-ended valve or line, valve, and flange or other connector
that has the potential to emit methane or VOC and any device or system
required by those same standards and requirements of this subpart.
Field gas means feedstock gas entering the natural gas processing
plant.
Field gas gathering means the system used transport field gas from
a field to the main pipeline in the area.
First attempt at repair means an action taken for the purpose of
stopping or reducing fugitive emissions to the atmosphere. First
attempts at repair include, but are not limited to, the following
practices where practicable and appropriate: Tightening bonnet bolts;
replacing bonnet bolts; tightening packing gland nuts; or injecting
lubricant into lubricated packing.
Flare means a thermal oxidation system using an open (without
enclosure) flame. Completion combustion devices as defined in this
section are not considered flares.
Flow line means a pipeline used to transport oil and/or gas to a
processing facility or a mainline pipeline.
Flowback means the process of allowing fluids and entrained solids
to flow from a well following a treatment, either in preparation for a
subsequent phase of treatment or in preparation for cleanup and
returning the well to production. The term flowback also means the
fluids and entrained solids that emerge from a well during the flowback
process. The flowback period begins when material introduced into the
well during the treatment returns to the surface following hydraulic
fracturing or refracturing. The flowback period ends when either the
well is shut in and permanently disconnected from the flowback
equipment or at the startup of production. The flowback period includes
the initial flowback stage and the separation flowback stage.
Screenouts, coil tubing cleanouts, and plug drill-outs are not
considered part of the flowback process.
Fuel gas means gases that are combusted to derive useful work or
heat.
Fuel gas system means the offsite and onsite piping and flow and
pressure control system that gathers gaseous stream(s) generated by
onsite operations, may blend them with other sources of gas, and
transports the gaseous stream for use as fuel gas in combustion devices
or in-process combustion equipment, such as furnaces and gas turbines,
either singly or in combination.
Fugitive emissions means, for the purposes of Sec. 60.5397b, any
indication of emissions observed from a fugitive emissions component
using AVO, an indication of visible emissions observed from an OGI
instrument, or an instrument reading of 500 ppmv or greater using
Method 21 of appendix A-7 to this part.
Fugitive emissions component means any component that has the
potential to emit fugitive emissions of methane or VOC at a well site,
centralized production facility, or compressor station, such as valves
(including separator dump valves), connectors, pressure relief devices,
open-ended lines, flanges, covers and closed vent systems not subject
to Sec. 60.5411b, thief hatches or other openings on a storage vessel
not subject to Sec. 60.5395b, compressors, instruments, meters, and
yard piping.
Gas to oil ratio (GOR) means the ratio of the volume of gas at
standard temperature and pressure that is produced from a volume of oil
when depressurized to standard temperature and pressure.
Hard-piping means pipe or tubing that is manufactured and properly
installed using good engineering judgment and standards such as ASME
B31.3, Process Piping (available from the American Society of
Mechanical Engineers, P.O. Box 2300, Fairfield, NJ 07007-2300).
Hydraulic fracturing means the process of directing pressurized
fluids containing any combination of water, proppant, and any added
chemicals to penetrate tight formations, such as shale or coal
formations, that subsequently require high rate, extended flowback to
expel fracture fluids and solids during completions.
Hydraulic refracturing means conducting a subsequent hydraulic
fracturing operation at a well that has previously undergone a
hydraulic fracturing operation.
In gas/vapor service means that the piece of equipment contains
process fluid that is in the gaseous state at operating conditions.
In heavy liquid service means that the piece of equipment is not in
gas/vapor service or in light liquid service.
In light liquid service means that the piece of equipment contains
a liquid that meets the conditions specified in Sec. 60.5402b(d)(2) or
Sec. 60.5403b.
In vacuum service means that equipment is operating at an internal
pressure which is at least 5 kilopascals (kPa) (0.7 psia) below ambient
pressure.
In wet gas service means that a compressor or piece of equipment
contains or contacts the field gas before the extraction step at a gas
processing plant process unit.
Initial calibration value as used in the standards and requirements
of this subpart relative to the process unit equipment affected
facility at onshore natural gas processing plants means the
concentration measured during the initial calibration at the beginning
of each day required in Sec. 60.5403b, or the most recent calibration
if the instrument is recalibrated during the day (i.e., the calibration
is adjusted) after a calibration drift assessment.
Initial flowback stage means the period during a well completion
operation which begins at the onset of flowback and ends at the
separation flowback stage.
Intermediate hydrocarbon liquid means any naturally occurring,
unrefined petroleum liquid.
Intermittent vent natural gas-driven process controller means a
process controller that is not designed to have a continuous bleed rate
but is instead designed to only release natural gas to the atmosphere
as part of the actuation cycle.
Liquefied natural gas unit means a unit used to cool natural gas to
the point at which it is condensed into a liquid which is colorless,
odorless, non-corrosive and non-toxic.
Liquid collection system means tankage and/or lines at a well site
to contain liquids from one or more wells or to convey liquids to
another site.
Liquids dripping means any visible leakage from the seal, including
spraying, misting, clouding, and ice formation.
Liquids unloading means the unloading of liquids that have
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accumulated over time in gas wells, which are impeding or halting
production. Routine well maintenance activities, including workovers,
screenouts, coil tubing cleanouts, or any other activity that requires
a rig or other machinery are not considered liquids unloading.
Local distribution company (LDC) custody transfer station means a
metering station where the LDC receives a natural gas supply from an
upstream supplier, which may be an interstate transmission pipeline or
a local natural gas producer, for delivery to customers through the
LDC's intrastate transmission or distribution lines.
Low-e valve means a valve (including its specific packing assembly)
for which the manufacturer has issued a written warranty or performance
guarantee that it will not emit fugitives at greater than 100 ppm in
the first five years. A valve may qualify as a low-e valve if it is as
an extension of another valve that has qualified as a low-e valve.
Low-e packing means a valve packing product for which the
manufacturer has issued a written warranty or performance guarantee
that it will not emit fugitives at greater than 100 ppm in the first
five years. Low-e injectable packing is a type of low-e packing product
for which the manufacturer has also issued a written warranty or
performance guarantee and that can be injected into a valve during a
``drill-and-tap'' repair of the valve.
Low pressure well means a well that satisfies at least one of the
following conditions:
(1) The static pressure at the wellhead following fracturing but
prior to the onset of flowback is less than the flow line pressure;
(2) The pressure of flowback fluid immediately before it enters the
flow line, as determined under Sec. 60.5432b, is less than the flow
line pressure; or
(3) Flowback of the fracture fluids will not occur without the use
of artificial lift equipment.
Major production and processing equipment means reciprocating or
centrifugal compressors, glycol dehydrators, heater/treaters,
separators, control devices, natural gas-driven process controllers,
natural gas-driven pumps, and storage vessels or tank batteries
collecting crude oil, condensate, intermediate hydrocarbon liquids, or
produced water, for the purpose of determining whether a well site is a
wellhead only well site.
Maximum average daily throughput means the following:
(1) The earliest calculation of daily average throughput,
determined as described in paragraph (2) or (3) of this definition, to
a tank battery over the days that production is routed to that tank
battery during the 30-day PTE evaluation period employing generally
accepted methods specified in Sec. 60.5365b(e)(2).
(2) If throughput to the tank battery is measured on a daily basis
(e.g., via level gauge automation or daily manual gauging), the maximum
average daily throughput is the average of all daily throughputs for
days on which throughput was routed to the tank battery during the 30-
day evaluation period; or
(3) If throughput to the tank battery is not measured on a daily
basis (e.g., via manual gauging at the start and end of loadouts), the
maximum average daily throughput is the highest, of the average daily
throughputs, determined for any production period to that tank battery
during the 30-day evaluation period, as determined by averaging total
throughput to that tank battery over each production period. A
production period begins when production begins to be routed to a tank
battery and ends either when throughput is routed away from that tank
battery or when a loadout occurs from that tank battery, whichever
happens first. Regardless of the determination methodology, operators
must not include days during which throughput is not routed to the tank
battery when calculating maximum average daily throughput for that tank
battery.
Multi-wellhead only well site means a well site that contains two
or more wellheads and no major production and processing equipment.
Natural gas-driven diaphragm pump means a positive displacement
pump powered by pressurized natural gas that uses the reciprocating
action of flexible diaphragms in conjunction with check valves to pump
a fluid. A pump in which a fluid is displaced by a piston driven by a
diaphragm is not considered a diaphragm pump for purposes of this
subpart. A lean glycol circulation pump that relies on energy exchange
with the rich glycol from the contactor is not considered a diaphragm
pump.
Natural gas-driven piston pump means a positive displacement pump
powered by pressurized natural gas that moves and pressurizes fluid by
using one or more reciprocating pistons. A pump in which a fluid is
displaced by a piston driven by a diaphragm is considered a piston pump
for purposes of this subpart. A lean glycol circulation pump that
relies on energy exchange with the rich glycol from the contactor is
not considered a piston pump.
Natural gas-driven process controller means a process controller
powered by pressurized natural gas.
Natural gas liquids means the hydrocarbons, such as ethane,
propane, butane, and pentane that are extracted from field gas.
Natural gas processing plant (gas plant) means any processing site
engaged in the extraction of natural gas liquids from field gas,
fractionation of mixed natural gas liquids to natural gas products, or
both. A Joule-Thompson valve, a dew point depression valve, or an
isolated or standalone Joule-Thompson skid is not a natural gas
processing plant.
Natural gas transmission means the pipelines used for the long-
distance transport of natural gas (excluding processing). Specific
equipment used in natural gas transmission includes the land, mains,
valves, meters, boosters, regulators, storage vessels, dehydrators,
compressors, and their driving units and appurtenances, and equipment
used for transporting gas from a production plant, delivery point of
purchased gas, gathering system, storage area, or other wholesale
source of gas to one or more distribution area(s).
No detectable emissions means, for the purposes of Sec. 60.5401b
and Sec. 60.5403b, that the equipment is operating with an instrument
reading of less than 500 ppmv above background, as determined by Method
21 of appendix A-7 to this part.
No identifiable emissions means, for the purposes of covers, closed
vent systems, and self-contained natural gas-driven process controllers
and as determined according to the provisions of Sec. 60.5416b, that
no emissions are detected by AVO means when inspections are conducted
by AVO; no emissions are imaged with an OGI camera when inspections are
conducted with OGI; and equipment is operating with an instrument
reading of less than 500 ppmv above background, as determined by Method
21 of appendix A-7 to this part when inspections are conducted with
Method 21.
Nonfractionating plant means any gas plant that does not
fractionate mixed natural gas liquids into natural gas products.
Non-natural gas-driven process controller means an instrument that
is actuated using other sources of power than pressurized natural gas;
examples include solar, electric, and instrument air.
Onshore means all facilities except those that are located in the
territorial seas or on the outer continental shelf.
Open-ended valve or line or open-ended vent line means any valves,
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except safety relief valves, having one side of the valve seat in
contact with process fluid and one side open to the atmosphere, either
directly or through open piping.
Plug drill-out means the removal of a plug (or plugs) that was used
to isolate different sections of the well.
Process controller means an automated instrument used for
maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature.
Pressure release means the emission of materials resulting from
system pressure being greater than set pressure of the pressure relief
device.
Pressure vessel means a storage vessel that is used to store
liquids or gases and is designed not to vent to the atmosphere as a
result of compression of the vapor headspace in the pressure vessel
during filling of the pressure vessel to its design capacity.
Pressurized mode means when the compressor contains natural gas
that is maintained at a pressure higher than the atmospheric pressure.
Process improvement means routine changes made for safety and
occupational health requirements, for energy savings, for better
utility, for ease of maintenance and operation, for correction of
design deficiencies, for bottleneck removal, for changing product
requirements, or for environmental control.
Process unit means components assembled for the extraction of
natural gas liquids from field gas, the fractionation of the liquids
into natural gas products, or other operations associated with the
processing of natural gas products. A process unit can operate
independently if supplied with sufficient feed or raw materials and
sufficient storage facilities for the products.
Process unit shutdown means a work practice or operational
procedure that stops production from a process unit or part of a
process unit during which it is technically feasible to clear process
material from a process unit or part of a process unit consistent with
safety constraints and during which repairs can be accomplished. The
following are not considered process unit shutdowns:
(1) An unscheduled work practice or operational procedure that
stops production from a process unit or part of a process unit for less
than 24 hours.
(2) An unscheduled work practice or operational procedure that
would stop production from a process unit or part of a process unit for
a shorter period of time than would be required to clear the process
unit or part of the process unit of materials and start up the unit,
and would result in greater emissions than delay of repair of leaking
components until the next scheduled process unit shutdown.
(3) The use of spare equipment and technically feasible bypassing
of equipment without stopping production.
Produced water means water that is extracted from the earth from an
oil or natural gas production well, or that is separated from crude
oil, condensate, or natural gas after extraction.
Qualified Professional Engineer means an individual who is licensed
by a state as a Professional Engineer to practice one or more
disciplines of engineering and who is qualified by education, technical
knowledge, and experience to make the specific technical certifications
required under this subpart. Professional engineers making these
certifications must be currently licensed in at least one state in
which the certifying official is located.
Quarter means a 3-month period. For purposes of standards for
process unit equipment affected facilities at onshore natural gas
processing plants, the first quarter concludes on the last day of the
last full month during the 180 days following initial startup.
Reciprocating compressor means a piece of equipment that increases
the pressure of a process gas by positive displacement, employing
linear movement of the driveshaft.
Reciprocating compressor rod packing means a series of flexible
rings in machined metal cups that fit around the reciprocating
compressor piston rod to create a seal limiting the amount of
compressed natural gas that escapes to the atmosphere, or other
mechanism that provides the same function.
Recovered gas means gas recovered through the separation process
during flowback.
Recovered liquids means any crude oil, condensate or produced water
recovered through the separation process during flowback.
Reduced emissions completion means a well completion following
fracturing or refracturing where gas flowback that is otherwise vented
is captured, cleaned, and routed to the gas flow line or collection
system, re-injected into the well or another well, used as an onsite
fuel source, or used for other useful purpose that a purchased fuel or
raw material would serve, with no direct release to the atmosphere.
Reduced sulfur compounds means H2S, carbonyl sulfide
(COS), and carbon disulfide (CS2).
Removed from service means that a storage vessel affected facility
has been physically isolated and disconnected from the process for a
purpose other than maintenance in accordance with Sec. 60.5395b(c)(1).
Repaired means the following:
(1) For the purposes of fugitive emissions components affected
facilities, that fugitive emissions components are adjusted, replaced,
or otherwise altered, in order to eliminate fugitive emissions and
resurveyed as specified in Sec. 60.5397b(h)(4) and it is verified that
emissions from the fugitive emissions components are below the
applicable fugitive emissions definition.
(2) For the purposes of process unit equipment affected facilities,
that equipment is adjusted, or otherwise altered, in order to eliminate
a leak as defined in Sec. Sec. 60.5400b and 60.5401b and is re-
monitored as specified in Sec. 60.5400b(b) introductory text and
(b)(1) or Sec. 60.5403b, respectively, to verify that emissions from
the equipment are below the applicable leak definition. Pumps in light
liquid service subject to Sec. 60.5400b(c)(2) or Sec.
60.5401b(b)(1)(ii) are not subject to re-monitoring.
Replacement cost means the capital needed to purchase all the
depreciable components in a facility.
Returned to service means that a storage vessel affected facility
that was removed from service has been:
(1) Reconnected to the original source of liquids or has been used
to replace any storage vessel affected facility; or
(2) Installed in any location covered by this subpart and
introduced with crude oil, condensate, intermediate hydrocarbon liquids
or produced water.
Routed to a process or route to a process means the emissions are
conveyed via a closed vent system to any enclosed portion of a process
that is operational where the emissions are predominantly recycled and/
or consumed in the same manner as a material that fulfills the same
function in the process and/or transformed by chemical reaction into
materials that are not regulated materials and/or incorporated into a
product; and/or recovered.
Salable quality gas means natural gas that meets the flow line or
collection system operator specifications, regardless of whether such
gas is sold.
Screenout means an attempt to clear proppant from the wellbore to
dislodge the proppant out of the well.
Self-contained process controller means a natural gas-driven
process controller that releases gas into the downstream piping and not
to the atmosphere, resulting in zero methane and VOC emissions.
[[Page 17134]]
Self-contained wet seal centrifugal compressor means:
(1) A wet seal centrifugal compressor system that is a closed
process that ports the degassing emissions into the natural gas line at
the compressor suction (i.e., degassed emissions are recovered) or
which has an intermediate closed process that degasses most of the gas
entrained in the seal oil and sends that gas to another process. The
de-gas emissions are routed back to suction or process directly from
the closed or intermediate closed degassing process; after the closed
or intermediate closed degassing process the oil is ultimately recycled
for recirculation in the seals to the lube oil tank where any small
amount of residual gas is released through a vent.
(2) A wet seal centrifugal compressor equipped with mechanical wet
seals, where
(i) A differential pressure is maintained on the system and there
is no off gassing of the lube oil, and
(ii) The mechanical seal is integrated into the compressor housing.
Sensor means a device that measures a physical quantity or the
change in a physical quantity such as temperature, pressure, flow rate,
pH, or liquid level.
Separation flowback stage means the period during a well completion
operation when it is technically feasible for a separator to function.
The separation flowback stage ends either at the startup of production,
or when the well is shut in and permanently disconnected from the
flowback equipment.
Separator dump valve means, for purposes of the fugitive emission
standards in Sec. Sec. 60.5397b and 60.5398b, a liquid-control valve
in a separator that controls the liquid level within the separator
vessel.
Single wellhead only well site means a wellhead only well site that
contains only one wellhead and no major production and processing
equipment.
Small well site means, for purposes of the fugitive emissions
standards in Sec. Sec. 60.5397b and 60.5398b, a well site that
contains a single wellhead, no more than one piece of certain major
production and processing equipment, and associated meters and yard
piping. Small well sites cannot include any controlled storage vessels
(or controlled tank batteries), control devices, natural gas-driven
process controllers, or natural gas-driven pumps.
Startup of production means the beginning of initial flow following
the end of flowback when there is continuous recovery of salable
quality gas and separation and recovery of any crude oil, condensate,
or produced water, except as otherwise provided in this definition. For
the purposes of the fugitive monitoring requirements of Sec. 60.5397b,
startup of production means the beginning of the continuous recovery of
salable quality gas and separation and recovery of any crude oil,
condensate, or produced water.
Storage vessel means a tank or other vessel that contains an
accumulation of crude oil, condensate, intermediate hydrocarbon
liquids, or produced water, and that is constructed primarily of
nonearthen materials (such as wood, concrete, steel, fiberglass, or
plastic) which provide structural support. A well completion vessel
that receives recovered liquids from a well after startup of production
following flowback for a period which exceeds 60 days is considered a
storage vessel under this subpart. A tank or other vessel shall not be
considered a storage vessel if it has been removed from service in
accordance with the requirements of Sec. 60.5395b(c)(1) until such
time as such tank or other vessel has been returned to service. For the
purposes of this subpart, the following are not considered storage
vessels:
(1) Vessels that are skid-mounted or permanently attached to
something that is mobile (such as trucks, railcars, barges or ships),
and are intended to be located at a site for less than 180 consecutive
days. If you do not keep or are not able to produce records, as
required by Sec. 60.5420b(c)(5)(iv), showing that the vessel has been
located at a site for less than 180 consecutive days, the vessel
described herein is considered to be a storage vessel from the date the
original vessel was first located at the site. This exclusion does not
apply to a well completion vessel as described above.
(2) Process vessels such as surge control vessels, bottoms
receivers or knockout vessels.
(3) Pressure vessels designed to operate in excess of 204.9
kilopascals and without emissions to the atmosphere.
Sulfur production rate means the rate of liquid sulfur accumulation
from the sulfur recovery unit.
Sulfur recovery unit means a process device that recovers element
sulfur from acid gas.
Surface site means any combination of one or more graded pad sites,
gravel pad sites, foundations, platforms, or the immediate physical
location upon which equipment is physically affixed.
Sweetening unit means a process device that removes hydrogen
sulfide and/or carbon dioxide from the sour natural gas stream.
Tank battery means a group of all storage vessels that are
manifolded together for liquid transfer. A tank battery may consist of
a single storage vessel if only one storage vessel is present.
Total Reduced Sulfur (TRS) means the sum of the sulfur compounds
hydrogen sulfide, methyl mercaptan, dimethyl sulfide, and dimethyl
disulfide as measured by Method 16 of appendix A-6 to this part.
Total SO2 equivalents means the sum of volumetric or
mass concentrations of the sulfur compounds obtained by adding the
quantity existing as SO2 to the quantity of SO2
that would be obtained if all reduced sulfur compounds were converted
to SO2 (ppmv or kg/dscm (lb/dscf)).
UIC Class I oilfield disposal well means a well with a UIC Class I
permit that meets the definition in 40 CFR 144.6(a)(2) and receives
eligible fluids from oil and natural gas exploration and production
operations.
UIC Class II oilfield disposal well means a well with a UIC Class
II permit where wastewater resulting from oil and natural gas
production operations is injected into underground porous rock
formations not productive of oil or gas, and sealed above and below by
unbroken, impermeable strata.
Underground storage vessel means a storage vessel stored below
ground.
Well means a hole drilled for the purpose of producing oil or
natural gas, or a well into which fluids are injected.
Well completion means the process that allows for the flowback of
petroleum or natural gas from newly drilled wells to expel drilling and
reservoir fluids and tests the reservoir flow characteristics, which
may vent produced hydrocarbons to the atmosphere via an open pit or
tank.
Well completion operation means any well completion with hydraulic
fracturing or refracturing occurring at a well completion affected
facility.
Well completion vessel means a vessel that contains flowback during
a well completion operation following hydraulic fracturing or
refracturing. A well completion vessel may be a lined earthen pit, a
tank or other vessel that is skid-mounted or portable. A well
completion vessel that receives recovered liquids from a well after
startup of production following flowback for a period which exceeds 60
days is considered a storage vessel under this subpart.
Well site means one or more surface sites that are constructed for
the drilling and subsequent operation of any oil well, natural gas
well, or injection well. For the purposes of the fugitive
[[Page 17135]]
emissions standards at Sec. 60.5397b, a well site does not include:
(1) UIC Class II oilfield disposal wells and disposal facilities;
(2) UIC Class I oilfield disposal wells; and
(3) The flange immediately upstream of the custody meter assembly
and equipment, including fugitive emissions components, located
downstream of this flange.
Wellhead means the piping, casing, tubing and connected valves
protruding above the earth's surface for an oil and/or natural gas
well. The wellhead ends where the flow line connects to a wellhead
valve. The wellhead does not include other equipment at the well site
except for any conveyance through which gas is vented to the
atmosphere.
Wellhead only well site means, for the purposes of the fugitive
emissions standards at Sec. 60.5397b and the standards in Sec.
60.5398b, a well site that contains one or more wellheads and no major
production and processing equipment.
Wildcat well means a well outside known fields or the first well
drilled in an oil or gas field where no other oil and gas production
exists.
Yard piping means hard-piping at a well site, centralized
production facility, or compressor station that is not part of a closed
vent system.
Sec. 60.5432b How do I determine whether a well is a low pressure
well using the low pressure well equation?
(a) To determine that your well is a low pressure well subject to
Sec. 60.5375b(f), you must determine whether the characteristics of
the well are such that the well meets the definition of low pressure
well in Sec. 60.5430b. To determine that the well meets the definition
of low pressure well in Sec. 60.5430b, you must use the low pressure
well equation:
[GRAPHIC] [TIFF OMITTED] TR08MR24.011
Where:
(1) PL is the pressure of flowback fluid immediately before it
enters the flow line, expressed in pounds force per square inch
(psia), and is to be calculated using the equation above;
(2) PR is the pressure of the reservoir containing oil, gas, and
water at the well site, expressed in psia;
(3) L is the true vertical depth of the well, expressed in feet
(ft);
(4) qo is the flow rate of oil in the well, expressed in cubic feet/
second (cu ft/sec);
(5) qg is the flow rate of gas in the well, expressed in cu ft/sec;
(6) qw is the flow rate of water in the well, expressed in cu ft/
sec;
(7) ro is the density of oil in the well, expressed in pounds mass
per cubic feet (lbm/cu ft).
(b) You must determine the four values in paragraphs (a)(4) through
(7) of this section, using the calculations in paragraphs (b)(1)
through (15) of this section.
(1) Determine the value of the bottom hole pressure, PBH (psia),
based on available information at the well site, or by calculating it
using the reservoir pressure, PR (psia), in the following equation:
[GRAPHIC] [TIFF OMITTED] TR08MR24.012
(2) Determine the value of the bottom hole temperature, TBH (F),
based on available information at the well site, or by calculating it
using the true vertical depth of the well, L (ft), in the following
equation:
[GRAPHIC] [TIFF OMITTED] TR08MR24.013
(3) Calculate the value of the applicable natural gas specific
gravity that would result from a separator pressure of 100 psig,
[gamma]gs, using the following equation with: Separator at standard
conditions (pressure, p = 14.7 (psia), temperature, T = 60 (F)); the
oil API gravity at the well site, [gamma]0; and the gas
specific gravity at the separator under standard conditions, [gamma]gp
= 0.75:
[GRAPHIC] [TIFF OMITTED] TR08MR24.014
[[Page 17136]]
(4) Calculate the value of the applicable dissolved GOR, Rs (scf/
STBO), using the following equation with: The bottom hole pressure, PBH
(psia), determined in (b)(1) of this section; the bottom hole
temperature, TBH (F), determined in (b)(2) of this section; the gas
gravity at separator pressure of 100 psig, [gamma]gs, calculated in
(b)(3) of this section; the oil API gravity, [gamma]o, at the well
site; and the constants, C1, C2, and C3, found in Table 1 to this
paragraph(b)(4):
[GRAPHIC] [TIFF OMITTED] TR08MR24.015
Table 1 to Paragraph (b)(4)--Coefficients for the Correlation for Rs
------------------------------------------------------------------------
[gamma] <= 30 [gamma] > 30
Constant
------------------------------------------------------------------------
C1...................................... 0.0362 0.0178
C2...................................... 1.0937 1.1870
C3...................................... 25.7240 23.931
------------------------------------------------------------------------
(5) Calculate the value of the oil formation volume factor, Bo
(bbl/STBO), using the following equation with: The bottom hole
temperature, TBH (F), determined in paragraph (b)(2) of this section;
the gas gravity at separator pressure of 100 psig, [gamma]gs,
calculated in paragraph (b)(3) of this section; the dissolved GOR, Rs
(scf/STBO), calculated in paragraph (b)(4) of this section; the oil API
gravity, [gamma]o, at the well site; and the constants, C1, C2, and C3,
found in Table 2 to this paragraph (b)(5):
[GRAPHIC] [TIFF OMITTED] TR08MR24.016
Table 2 to Paragraph (b)(5)--Coefficients for the Correlation for B
------------------------------------------------------------------------
[gamma] <= 30 [gamma] > 30
Constant
------------------------------------------------------------------------
C1..................................... 4.677 x 10-4 4.670 x 10-4
C2..................................... 1.751 x 10-5 1.100 x 10-5
C3..................................... -1.811 x 10-8 1.337 x 10-9
------------------------------------------------------------------------
(6) Calculate the density of oil at the wellhead,
[GRAPHIC] [TIFF OMITTED] TR08MR24.017
using the following equation with the value of the oil API gravity,
[gamma]o, at the well site:
[GRAPHIC] [TIFF OMITTED] TR08MR24.018
(7) Calculate the density of oil at bottom hole conditions,
[GRAPHIC] [TIFF OMITTED] TR08MR24.019
using the following equation with: the dissolved GOR, Rs (scf/STBO),
calculated in paragraph (b)(4) of this section; the oil formation
volume factor, Bo (bbl/STBO), calculated in paragraph (b)(5) of this
section; the oil density at the wellhead,
[GRAPHIC] [TIFF OMITTED] TR08MR24.020
calculated in paragraph (b)(6) of this section; and the dissolved gas
gravity, [gamma]gd = 0.77:
[GRAPHIC] [TIFF OMITTED] TR08MR24.021
(8) Calculate the density of oil in the well,
[GRAPHIC] [TIFF OMITTED] TR08MR24.022
using the following equation with the density of oil at the wellhead,
[GRAPHIC] [TIFF OMITTED] TR08MR24.023
calculated in paragraph (b)(6) of this section; and the density of oil
at bottom hole conditions,
[GRAPHIC] [TIFF OMITTED] TR08MR24.024
calculated in paragraph (b)(7) of this section:
[[Page 17137]]
[GRAPHIC] [TIFF OMITTED] TR08MR24.025
(9) Calculate the oil flow rate, qo (cu ft/sec,) using
the following equation with: the oil formation volume factor, Bo (bbl/
STBO), as calculated in paragraph (b)(5) of this section; and the
estimated oil production rate at the well head, Qo (STBO/day):
[GRAPHIC] [TIFF OMITTED] TR08MR24.026
(10) Calculate the critical pressure, Pc (psia), and
critical temperature, Tc (R), using the equations below
with: Gas gravity at standard conditions (pressure, P = 14.7 (psia),
temperature, T = 60 (F)), [gamma] = 0.75; and where the mole fractions
of nitrogen, carbon dioxide and hydrogen sulfide in the gas are
XN2 = 0.168225, XCO2 = 0.013163, and
XH2S = 0.013680, respectively:
Pc(psia) = 678 - 50 [middot] ([gamma]g -0.5) - 206.7 [middot]
XN2 + 440 [middot] XCO2 + 606.7 [middot]
XH2S
Tc(R) = 326 + 315.7 [middot] ([gamma]g - 0.5) - 240 [middot]
XN2 - 88.3 [middot] XCO2 + 133.3 [middot]
XH2S
(11) Calculate reduced pressure, Pr, and reduced
temperature, Tr, using the following equations with: the
bottom hole pressure, PBH, as determined in paragraph (b)(1) of this
section; the bottom hole temperature, TBH (F), as determined in
paragraph (b)(2) of this section in the following equations:
[GRAPHIC] [TIFF OMITTED] TR08MR24.027
(12)(i) Calculate the gas compressibility factor, Z, using the
following equation with the reduced pressure, Pr, calculated
in paragraph (b)(11) of this section:
[GRAPHIC] [TIFF OMITTED] TR08MR24.028
(ii) The values for A, B, C, D in the above equation, are
calculated using the following equations with the reduced pressure,
Pr, and reduced temperature, Tr, calculated in
paragraph (b)(11) of this section:
[GRAPHIC] [TIFF OMITTED] TR08MR24.029
[[Page 17138]]
(13) Calculate the gas formation volume factor,
[GRAPHIC] [TIFF OMITTED] TR08MR24.030
using the bottom hole pressure, PBH (psia), as determined in paragraph
(b)(1) of this section; and the bottom hole temperature, TBH (F), as
determined in paragraph (b)(2) of this section:
[GRAPHIC] [TIFF OMITTED] TR08MR24.031
(14) Calculate the gas flow rate,
[GRAPHIC] [TIFF OMITTED] TR08MR24.032
using the following equation with: the value of gas formation volume
factor,
[GRAPHIC] [TIFF OMITTED] TR08MR24.033
calculated in paragraph (b)(13) of this section; the estimated gas
production rate, Qg (scf/day); the estimated oil production rate, Qo
(STBO/day); and the dissolved GOR, Rs (scf/STBO), as calculated in
paragraph (b)(4) of this section:
[GRAPHIC] [TIFF OMITTED] TR08MR24.034
(15) Calculate the flow rate of water in the well, qw (cu ft/sec),
using the following equation with the water production rate Qw (bbl/
day) at the well site:
[GRAPHIC] [TIFF OMITTED] TR08MR24.035
Sec. Sec. 60.5433b -60.5439b [Reserved]
Table 1 to Subpart OOOOb of Part 60--Alternative Technology Periodic
Screening Frequency at Well Sites, Centralized Production Facilities,
and Compressor Stations Subject to AVO Inspections With Quarterly OGI or
EPA Method 21 Monitoring
------------------------------------------------------------------------
Minimum detection threshold
Minimum screening frequency of screening technology *
(kg/hr)
------------------------------------------------------------------------
Quarterly.................................. <=1
Bimonthly.................................. <=2
Bimonthly + Annual OGI..................... <=10
Monthly.................................... <=5
[[Page 17139]]
Monthly + Annual OGI....................... <=15
------------------------------------------------------------------------
* Based on a probability of detection of 90%.
Table 2 to Subpart OOOOb of Part 60--Alternative Technology Periodic
Screening Frequency at Well Sites and Centralized Production Facilities
Subject to AVO Inspections and/or Semiannual OGI or EPA Method 21
Monitoring
------------------------------------------------------------------------
Minimum detection threshold
Minimum screening frequency of screening technology *
(kg/hr)
------------------------------------------------------------------------
Semiannual................................. <=1
Triannual.................................. <=2
Triannual + Annual OGI..................... <=10
Quarterly.................................. <=5
Quarterly + Annual OGI..................... <=15
Bimonthly.................................. <=15
------------------------------------------------------------------------
* Based on a probability of detection of 90%
Table 3 to Subpart OOOOb of Part 60--Required Minimum Initial SO2 Emission Reduction Efficiency (Zi)
----------------------------------------------------------------------------------------------------------------
Sulfur feed rate (X), LT/D
H2S content of acid gas (Y), % ----------------------------------------------------------------------------
2.0 < X < 5.0 5.0 < X < 15.0 15.0 < X < 300.0 X > 300.0
----------------------------------------------------------------------------------------------------------------
Y > 50............................. 79.0 88.51X\0.0101\Y\0.0125\ or 99.9, whichever is smaller.
------------------------------------------------------------
20 < Y < 50........................ 79.0 88.51X\0.0101\Y\0.0125\ or 97.9, whichever is 97.9
smaller
------------------------------------------------------------
10 < Y < 20........................ 79.0 88.51X\0.0101\Y\0.0125\ or 93.5 93.5
93.5, whichever is
smaller.
Y < 10............................. 79.0 79.0...................... 79.0 79.0
----------------------------------------------------------------------------------------------------------------
Table 4 to Subpart OOOOb of Part 60--Required Minimum SO2 Emission Reduction Efficiency (Zc)
----------------------------------------------------------------------------------------------------------------
Sulfur feed rate (X), LT/D
H2S content of acid gas (Y), % ----------------------------------------------------------------------------
2.0 < X < 5.0 5.0 < X < 15.0 15.0 < X < 300.0 X > 300.0
----------------------------------------------------------------------------------------------------------------
Y > 50............................. 74.0 85.35X\0.0144\Y\0.0128\ or 99.9, whichever is smaller.
------------------------------------------------------------
20 < Y < 50........................ 74.0 85.35X\0.0144\Y\0.0128\ or 97.5, whichever is 97.5
smaller
----------------------------
10 < Y < 20........................ 74.0 85.35X\0.0144\Y\0.0128\ or 90.8 90.8
90.8, whichever is
smaller.
Y < 10............................. 74.0 74.0...................... 74.0 74.0
----------------------------------------------------------------------------------------------------------------
X = The sulfur feed rate from the sweetening unit (i.e., the
H2S in the acid gas), expressed as sulfur, Mg/D(LT/D),
rounded to one decimal place.
Y = The sulfur content of the acid gas from the sweetening unit,
expressed as mole percent H2S (dry basis) rounded to one
decimal place.
Z = The minimum required sulfur dioxide (SO2) emission
reduction efficiency, expressed as percent carried to one decimal
place. Zi refers to the reduction efficiency required at
the initial performance test. Zc refers to the reduction
efficiency required on a continuous basis after compliance with
Zi has been demonstrated.
Table 5 to Subpart OOOOb of Part 60--Applicability of General Provisions to Subpart OOOOb
----------------------------------------------------------------------------------------------------------------
General provisions citation Subject of citation Applies to subpart? Explanation
----------------------------------------------------------------------------------------------------------------
Sec. 60.1........................ General applicability Yes.....................
of the General
Provisions.
Sec. 60.2........................ Definitions.......... Yes..................... Additional terms defined
in Sec. 60.5430b.
Sec. 60.3........................ Units and Yes.....................
abbreviations.
Sec. 60.4........................ Address.............. Yes.....................
[[Page 17140]]
Sec. 60.5........................ Determination of Yes.....................
construction or
modification.
Sec. 60.6........................ Review of plans...... Yes.....................
Sec. 60.7........................ Notification and Yes..................... Except that Sec. 60.7
record keeping. only applies as specified
in Sec. Sec.
60.5417b(c) and
60.5420b(a).
Sec. 60.8........................ Performance tests.... Yes..................... Except that the format and
submittal of performance
test reports is described
in Sec. 60.5420b(b) and
(d). Performance testing
is required for control
devices used on storage
vessels, centrifugal
compressors, process
controllers, and pumps
complying with Sec.
60.5393b(b)(1), except
that performance testing
is not required for a
control device used
solely on pump(s).
Sec. 60.9........................ Availability of Yes.....................
information.
Sec. 60.10....................... State authority...... Yes.....................
Sec. 60.11....................... Compliance with No...................... Requirements are specified
standards and in subpart OOOOb.
maintenance
requirements.
Sec. 60.12....................... Circumvention........ Yes.....................
Sec. 60.13....................... Monitoring Yes.....................
requirements.
Sec. 60.14....................... Modification......... Yes..................... To the extent any
provision in Sec. 60.14
conflicts with specific
provisions in subpart
OOOOb, it is superseded
by subpart OOOOb
provisions.
Sec. 60.15....................... Reconstruction....... Yes..................... Except that Sec.
60.15(d) does not apply
to wells (i.e., well
completions, well liquids
unloading, associated gas
wells), process
controllers, pumps,
centrifugal compressors,
reciprocating
compressors, storage
vessels, or fugitive
emissions components
affected facilities.
Sec. 60.16....................... Priority list........ Yes.....................
Sec. 60.17....................... Incorporations by Yes.....................
reference.
Sec. 60.18....................... General control Yes.....................
device and work
practice
requirements.
Sec. 60.19....................... General notification Yes.....................
and reporting
requirement.
----------------------------------------------------------------------------------------------------------------
0
33. Add subpart OOOOc to part 60 to read as follows:
Subpart OOOOc--Emissions Guidelines for Greenhouse Gas Emissions
From Existing Crude Oil and Natural Gas Facilities
Introduction
60.5360c What is the purpose of this subpart?
60.5361c Which pollutants are regulated by this subpart?
60.5362c Am I affected by this subpart?
60.5363c What must I include in my state or Tribal plan?
60.5364c How do I apply to use my state standards as part of my
state or Tribal plan submission?
60.5365c How do I apply for a less stringent standard taking into
consideration the remaining useful life of a designated facility and
other factors?
60.5366c [Reserved]
60.5367c Is there an approval process for my state or Tribal plan?
60.5368c What if my state or Tribal plan is not approvable?
60.5369c Is there an approval process for a negative declaration
letter?
60.5370c What compliance schedule must I include in my state or
Tribal plan?
60.5371c What requirements apply to revisions to my state or Tribal
plan?
60.5372c In lieu of a state or Tribal plan submittal, are there
other acceptable option(s) for a state to meet its Clean Air Act
section 111(d) obligations?
60.5373c What authorities will not be delegated to state, local, or
Tribal agencies?
60.5374c Does this subpart directly affect designated facility
owners and operators in my state?
Applicability of State or Tribal Plans
60.5375c What designated facilities must I address in my state or
Tribal plan?
Use of Model Rule
60.5376c What is the ``model rule'' in this subpart?
60.5377c How does the model rule relate to the required elements of
my state or Tribal plan?
60.5378c What are the principal components of the model rule?
Model Rule--Increments of Progress
60.5379c What are my requirements for meeting increments of progress
and achieving final compliance?
60.5380c What if I do not meet the final control plan increment of
progress compliance date?
60.5381c How do I comply with the increment of progress for
submittal of a final compliance control plan?
Model Rule--Applicability
60.5385c What is the purpose of this subpart?
60.5386c Am I subject to this subpart?
60.5387c When must I comply with this subpart?
Model Rule--Emission and Work Practice Standards
60.5388c What standards apply to super-emitter events?
60.5390c What GHG standards apply to gas well liquids unloading
operations at well designated facilities?
60.5391c What GHG standards apply to associated gas wells at well
designated facilities?
60.5392c What GHG standards apply to centrifugal compressor
designated facilities?
60.5393c What GHG standards apply to reciprocating compressor
designated facilities?
60.5394c What GHG standards apply to process controller designated
facilities?
60.5395c What GHG standards apply to pump designated facilities?
60.5396c What GHG standards apply to storage vessel designated
facilities?
60.5397c What GHG standards apply to fugitive emissions components
designated facilities?
60.5398c What alternative GHG standards apply to fugitive emissions
components designated facilities and what monitoring and inspection
requirements apply to covers and closed vent systems when using an
alternative technology?
60.5400c What GHG standards apply to process unit equipment
designated facilities?
60.5401c What are the alternative GHG standards for process unit
equipment designated facilities?
[[Page 17141]]
60.5402c What are the exceptions to the GHG standards for process
unit equipment designated facilities?
Model Rule--Test Methods and Performance Testing
60.5405c What test methods and procedures must I use for my
centrifugal compressor and reciprocating compressor designated
facilities?
60.5406c What test methods and procedures must I use for my process
unit equipment designated facilities?
Model Rule--Initial Compliance Requirements
60.5410c How do I demonstrate initial compliance with the standards
for each of my designated facilities?
60.5411c What additional requirements must I meet to determine
initial compliance for my covers and closed vent systems?
60.5412c What additional requirements must I meet for determining
initial compliance of my control devices?
60.5413c What are the performance testing procedures for control
devices?
Model Rule--Continuous Compliance Requirements
60.5415c How do I demonstrate continuous compliance with the
standards for each of my designated facilities?
60.5416c What are the initial and continuous cover and closed vent
system inspection and monitoring requirements?
60.5417c What are the continuous monitoring requirements for my
control devices?
Model Rule--Recordkeeping and Reporting
60.5420c What are my notification, reporting, and recordkeeping
requirements?
60.5421c What are my additional recordkeeping requirements for
process unit equipment designated facilities?
60.5422c What are my additional reporting requirements for process
unit equipment designated facilities?
60.5424c What are my additional recordkeeping and reporting
requirements if I comply with the alternative GHG standards for
fugitive emissions components designated facilities and covers and
closed vent systems?
60.5425c What parts of the General Provisions apply to me?
Model Rule--Definitions
60.5430c What definitions apply to this subpart?
60.5431c-60.5439c [Reserved]
Table 1 to Subpart OOOOc of Part 60--Designated Facility Presumptive
Standards and Regulated Entity Compliance Dates
Table 2 to Subpart OOOOc of Part 60--Alternative Technology Periodic
Screening Frequency at Well Sites, Centralized Production
Facilities, and Compressor Stations Subject to AVO Inspections With
Quarterly OGI or EPA Method 21 Monitoring
Table 3 to Subpart OOOOc of Part 60--Alternative Technology Periodic
Screening Frequency at Well Sites and Centralized Production
Facilities Subject to AVO Inspections and/or Semiannual OGI or EPA
Method 21 Monitoring
Table 4 to Subpart OOOOc of Part 60--Applicability of General
Provisions to Subpart OOOOc
Introduction
Sec. 60.5360c What is the purpose of this subpart?
This subpart establishes emission guidelines and compliance
schedules for the control of greenhouse gas (GHG) emissions from
designated facilities in the crude oil and natural gas source category
as defined in the Model Rule at Sec. 60.5430c, in accordance with
section 111(d) of the Clean Air Act and subpart Ba of this part. The
designated facilities, standards section reference and compliance dates
are listed in table 1 to this subpart. To the extent any requirement of
this subpart is inconsistent with the requirements of subpart A or Ba
of this part, the requirements of this subpart will apply.
Sec. 60.5361c Which pollutants are regulated by this subpart?
(a) Scope. The pollutants regulated by this subpart are greenhouse
gases (GHG). The greenhouse gas standards in this subpart are in the
form of a limitation on emissions of methane from designated facilities
in the crude oil and natural gas source category that commenced
construction, modification, or reconstruction on or before December 6,
2022.
(b) PSD and title V Thresholds for Greenhouse Gases. (1) For the
purposes of 40 CFR 51.166(b)(49)(ii), with respect to GHG emissions
from facilities, the ``pollutant that is subject to any standard
promulgated under section 111 of the Act'' shall be considered to be
the pollutant that otherwise is subject to regulation under the Act as
defined in 40 CFR 51.166(b)(48) and in any State Implementation Plan
(SIP) approved by the EPA that is interpreted to incorporate, or
specifically incorporates, 40 CFR 51.166(b)(48).
(2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to
GHG emissions from facilities regulated in the plan, the ``pollutant
that is subject to any standard promulgated under section 111 of the
Act'' shall be considered to be the pollutant that otherwise is subject
to regulation under the Act as defined in 40 CFR 52.21(b)(49).
(3) For the purposes of 40 CFR 70.2, with respect to GHG emissions
from facilities regulated in the plan, the ``pollutant that is subject
to any standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in 40 CFR 70.2.
(4) For the purposes of 40 CFR 71.2, with respect to GHG emissions
from facilities regulated in the plan, the ``pollutant that is subject
to any standard promulgated under section 111 of the Act'' shall be
considered to be the pollutant that otherwise is ``subject to
regulation'' as defined in 40 CFR 71.2 40 CFR.
Sec. 60.5362c Am I affected by this subpart?
(a) If you are the Administrator of an air pollution control agency
in a state or United States protectorate with one or more designated
facilities that commenced construction, modification, or reconstruction
on or before December 6, 2022, you must submit a state or Tribal plan
to the U.S. Environmental Protection Agency (EPA) that implements the
emission guidelines contained in this subpart. The submission of such
plan shall be made in electronic format according to subpart Ba of this
part.
(b) If you are the Administrator of an air pollution control agency
in a state or United States protectorate with no designated facilities
for which construction commenced on or before December 6, 2022, you
must submit a negative declaration letter in place of the state or
Tribal plan. The submission of such negative declaration letter shall
be made in electronic format according to subpart Ba of this part.
(c) You must submit the state or Tribal plan or negative
declaration letter to EPA by the date March 9, 2026.
Sec. 60.5363c What must I include in my state or Tribal plan?
(a) You must include the ten items described in paragraphs (a)(1)
through (10) of this section in your state or Tribal plan.
(1) Inventory of designated facilities. For purposes of this
subpart, Sec. 60.25a(a) does not apply.
(2) Inventory of emissions from designated facilities in your
state. For purposes of this subpart, Sec. 60.25a(a) does not apply.
(3) Compliance schedules for each designated facility or logical
grouping of designated facilities.
(4) Standards of performance for designated facilities that are at
least as stringent as the emission guidelines contained in this
subpart, unless otherwise provided for under Sec. 60.5365c. Standards
for performance for designated facilities must apply at all times,
including periods of startup, shutdown, and malfunction.
[[Page 17142]]
(5) Performance testing, monitoring, recordkeeping, and reporting
requirements.
(6) Documentation of meaningful engagement on such plan or plan
revisions as specified in Sec. 60.23a(i).
(7) Certification that the required hearing on the state or Tribal
plan was held, a list of witnesses and their organizational
affiliations, if any, appearing at the hearing, and a brief written
summary of each presentation or written submission as specified in
Sec. 60.23a(c) through (e).
(8) Provision for state progress reports to EPA.
(9) Identification of enforceable state mechanisms that you
selected for implementing the emission guidelines of this subpart.
(10) Demonstration of your state's legal authority to carry out the
Clean Air Act section 111(d) state or Tribal plan.
(b) Unless superseded by this subpart, you must follow the
requirements of subpart Ba of this part (Adoption and Submittal of
State Plans for Designated Facilities) in your state or Tribal plan.
Sec. 60.5364c How do I apply to use my state standards as part of my
state or Tribal plan submission?
In order for you to apply to use your state standards as part of
your state or Tribal plan submission your state requirements for
designated facilities must meet the standards of performance criteria
specified in paragraph (a) of this section and you must provide the
supporting documentation that you met those criteria as specified in
paragraph (b) of this section.
(a) You must demonstrate that the state standards of performance
established for a designated facility in your state or Tribal plan meet
the equivalency criteria specified in paragraphs (a)(1) through (6) of
this section when compared to the designated facility presumptive
standards specified in EG OOOOc.
(1) Designated facility,
(2) Designated pollutant,
(3) Standard type/format of standard,
(4) Emission reductions (considering applicability thresholds and
exemptions) unless relying on Sec. 60.5365c,
(5) Compliance determination method, and
(6) Ongoing compliance assurance requirements (e.g., monitoring,
recordkeeping and reporting requirements).
(b) You must provide the supporting documentation that you met the
equivalency criteria specified in paragraph (a) of this section as
specified in paragraphs (b)(1) through (3) of this section.
(1) Your state or Tribal plan should identify the designated
facility requirements of your state program that you are submitting for
approval to become federally enforceable requirements under the plan.
(2) You must include a detailed explanation and analysis of how the
relied upon state standards are at least as stringent as the
requirements of the final EG based on each of the criteria specified in
paragraph (a) of this section, or comply with Sec. 60.5365c for
paragraph (a)(4) of this section.
(3) You must include a copy of the actual state law/regulation or
document submitted for approval and incorporation into the state or
Tribal plan.
Sec. 60.5365c How do I apply for a less stringent standard taking
into consideration the remaining useful life of a designated facility
and other factors?
You may apply a standard of performance to a designated facility
that is less stringent than otherwise required by the emission
guidelines, provided you meet the requirements specified in Sec.
60.24a.
Sec. 60.5366c [Reserved.]
Sec. 60.5367c Is there an approval process for my state or Tribal
plan?
Yes. The EPA will review your state or Tribal plan according to
Sec. 60.27a.
(a) The EPA will determine the completeness of your plan submission
according Sec. 60.27a(g).
(b) The EPA will act on your plan submission according to Sec.
60.27a.
Sec. 60.5368c What if my state or Tribal plan is not approvable?
If you do not submit a state or Tribal plan (or a negative
declaration letter) by March 9, 2026, or if EPA disapproves your state
plan, EPA will develop a Federal plan according to Sec. 60.27a(c)
through (f) to implement the emission guidelines contained in this
subpart.
Sec. 60.5369c Is there an approval process for a negative declaration
letter?
No. The EPA has no formal review process for negative declaration
letters. Once your negative declaration letter has been received, the
EPA will place a copy in the public docket and publish a notice in the
Federal Register. If, at a later date, a designated facility for which
construction commenced on or before December 6, 2022, is found in your
state, that designated facility must be subject to a state, Tribal, or
Federal plan in accordance with the requirements of this subpart and
subpart Ba.
Sec. 60.5370c What compliance schedule must I include in my state or
Tribal plan?
(a) For designated facilities that commenced construction,
modification or reconstruction on or before December 6, 2022, your
state or Tribal plan must include compliance schedules that require
designated facilities to achieve final compliance as expeditiously as
practicable after approval of the state or Tribal plan but not later
than the dates specified in Sec. 60.5360c of this subpart, as
applicable to each designated facility.
(b) The plan must include legally enforceable increments of
progress to achieve compliance for each designated facility or category
of facilities, as specified in Sec. Sec. 60.5380c through 60.5382c.
Sec. 60.5371c What requirements apply to revisions to my state or
Tribal plan?
(a) Any significant revision to a state or Tribal plan shall be
adopted and submitted as specified in Sec. 60.28a.
(b) A revision of a plan, or any portion thereof, shall not be
considered part of an applicable plan until approved by the
Administrator in accordance with this subpart and subpart Ba of this
part.
Sec. 60.5372c In lieu of a state or Tribal plan submittal, are there
other acceptable option(s) for a state to meet its Clean Air Act
section 111(d) obligations?
Yes, a state may meet its Clean Air Act section 111(d) obligations
by submitting an acceptable written request for delegation of an
applicable Federal plan that meets the requirements of this section.
This is the only other option for a state to meet its section 111(d)
obligations.
(a) An acceptable Federal plan delegation request must include the
following:
(1) A demonstration of adequate resources and legal authority to
administer and enforce the Federal plan.
(2) The items under Sec. 60.5363c(a)(1), (a)(2), and (a)(8) of
this subpart.
(3) Certification that the hearing on the state delegation request,
similar to the hearing for a state or Tribal plan submittal, was held,
a list of witnesses and their organizational affiliations, if any,
appearing at the hearing, and a brief written summary of each
presentation or written submission.
(4) A commitment to enter into a Memorandum of Agreement with the
Regional Administrator that sets forth the terms, conditions, and
effective date of the delegation and that serves as the mechanism for
the transfer of authority. Additional guidance and information is given
in EPA's Delegation Manual, Item 7-139, Implementation and Enforcement
of 111(d)(2) and 111(d)/(2)/129 (b)(3) Federal plans.
[[Page 17143]]
(b) A state with an already approved oil and natural gas designated
facility Clean Air Act section 111(d) state or Tribal plan is not
precluded from receiving the EPA's approval of a delegation request for
any revised Federal plan, provided the requirements of paragraph (a) of
this section are met, and at the time of the delegation request, the
state also requests withdrawal of the EPA's previous state or Tribal
plan approval.
(c) A state's Clean Air Act section 111(d) obligations are separate
from its obligations under title V of the Clean Air Act.
Sec. 60.5373c What authorities will not be delegated to state, local,
or Tribal agencies?
The authorities that will not be delegated to state, local, or
Tribal agencies are specified in paragraphs (a) through (h) of this
section.
(a) Approval of alternatives to the emission limits and standards
in tables 1, 2, and 3 to this subpart and operating limits established
under Sec. 60.5412c, Sec. 60.5415c, or Sec. 60.5417c.
(b) Approval of major alternatives to test methods.
(c) Approval of major alternatives to monitoring.
(d) Approval of major alternatives to recordkeeping and reporting.
(e) Approval of an alternative to any electronic reporting required
by this subpart.
(f) [Reserved.]
(g) [Reserved.]
(h) Performance test and data reduction waivers under Sec.
60.8(b).
Sec. 60.5374c Does this subpart directly affect designated facility
owners and operators in my state?
(a) No. This subpart does not directly affect designated facility
owners and operators in your state. However, designated facility owners
and operators must comply with the state or Tribal plan you develop to
implement the emission guidelines contained in this subpart. States may
choose to incorporate the model rule text directly in their state or
Tribal plan.
(b) If you do not submit a plan to implement and enforce the
guidelines contained in this subpart by the date 24 months after
promulgation of this subpart, or if EPA disapproves your plan, the EPA
will implement and enforce a Federal plan, as provided in Sec.
60.5367c of this subpart, to ensure that each designated facility
within your state that commenced construction, modification or
reconstruction on or before December 6, 2022, reaches compliance with
all the provisions of this subpart by the dates specified in Sec.
60.5360c of this subpart.
Applicability of State or Tribal Plans
Sec. 60.5375c What designated facilities must I address in my state
or Tribal plan?
(a) Your state or Tribal plan must address designated facilities
that meet all three criteria described in paragraphs (a)(1) through (3)
of this section.
(1) Designated facilities in your state that commenced
construction, modification, or reconstruction on or before December 6,
2022.
(2) Designated facilities that are listed in table 1 to this
subpart.
(3) Designated facilities not exempt under Sec. 60.14c.
(b) If the owner or operator of a designated facility makes changes
that meet the definition of modification after December 6, 2022, the
designated facility becomes subject to subpart OOOOb of this part, and
the state or Tribal plan no longer applies to that facility.
(c) If the owner or operator of a designated facility makes
physical or operational changes to a designated facility for which
construction commenced on or before September 9, 2024, primarily to
comply with your state or Tribal plan, subpart OOOOb of this part, does
not apply to that designated facility. Such changes do not qualify as
modifications under subpart OOOOb of this part.
Use of Model Rule
Sec. 60.5376c What is the ``model rule'' in this subpart?
(a) The model rule is the portion of these emission guidelines
(Sec. Sec. 60.5385c through 60.5430c of this subpart) that includes
the presumptive standards for designated facilities as well as
associated measures to assure compliance including monitoring,
recordkeeping, and reporting. The model rule is organized in regulation
format. You must develop a state or Tribal plan that is at least as
protective as the model rule, or comply with Sec. 60.5365c. You may
use the model rule language as part of your state or Tribal plan.
Alternative language may be used in your state or Tribal plan if you
demonstrate that the alternative language is at least as protective as
the model rule contained in this subpart, or comply with Sec.
60.5365c.
(b) In the model rule of Sec. Sec. 60.5385c through 60.5430c,
``Administrator'' has the meaning specified in Sec. 60.2.
Sec. 60.5377c How does the model rule relate to the required elements
of my state or Tribal plan?
You may use the model rule to satisfy the state or Tribal plan
requirements specified in Sec. 60.5363c(a)(3) through (a)(5).
Sec. 60.5378c What are the principal components of the model rule?
The model rule contains the nine major components listed in
paragraphs (a) through (i) of this section.
(a) Increments of progress toward compliance.
(b) Operator training and qualification.
(c) Emission limits, emission standards, and operating limits.
(d) Initial compliance requirements.
(e) Continuous compliance requirements.
(f) Performance testing, monitoring, and calibration requirements.
(g) Recordkeeping and reporting.
(h) Definitions.
(i) Tables.
Model Rule--Increments of Progress
Sec. 60.5379c What are my requirements for meeting increments of
progress and achieving final compliance?
You must meet one increment of progress as specified in paragraph
(a) of this section and you must submit the Notification of Compliance
report as specified in paragraph (b) of this section.
(a) Submit a final compliance control plan on or before 28 months
after the state plan submittal deadline specified in Sec. 60.5362c(c).
(b) Submit a Notification of Compliance report on or before 60 days
after the state plan compliance date as specified in Sec. 60.5420c.
Sec. 60.5380c What if I do not meet the final control plan increment
of progress compliance date?
If you fail to meet the final compliance control plan increment of
progress report compliance date, you must submit a notification to the
Administrator postmarked within 10 business days after the required
submittal date for that increment of progress. You must inform the
Administrator that you did not meet the increment, and you must
continue to submit reports each subsequent calendar month until the
increment of progress is met.
Sec. 60.5381c How do I comply with the increment of progress for
submittal of a final compliance control plan?
For your final compliance control plan increment of progress
report, you must satisfy the requirements specified
[[Page 17144]]
in paragraphs (a) through (c) of this section.
(a) Your final control plan must include the information specified
paragraphs (a)(1) and (2) of this section.
(1) A description of the designated facilities covered under your
plan.
(2) The emissions control methods that you plan to implement for
each designated facility covered under your plan.
(b) A company is allowed to submit one plan that covers all of the
company's designated facilities in a state in lieu of submitting a plan
for each designated facility.
(c) Maintain an onsite copy of the final control plan.
Model Rule--Applicability
Sec. 60.5385c What is the purpose of this subpart?
(a) Scope. This subpart establishes emission standards and
compliance schedules for the control of the pollutant greenhouse gases
(GHG). The greenhouse gas standard in this subpart is in the form of a
limitation on emissions of methane from designated facilities in the
crude oil and natural gas source category that commence construction,
modification, or reconstruction on or before December 6, 2022.
(b) Prevention of Significant Deterioration (PSD) and title V
thresholds for Greenhouse Gases. (1) For the purposes of 40 CFR
51.166(b)(49)(ii), with respect to GHG emissions from designated
facilities, the ``pollutant that is subject to the standard promulgated
under section 111 of the Act'' shall be considered the pollutant that
otherwise is subject to regulation under the Act as defined in 40 CFR
51.166(b)(48) and in any State Implementation Plan (SIP) approved by
the EPA that is interpreted to incorporate, or specifically
incorporates, 40 CFR 51.166(b)(48).
(2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to
GHG emissions from designated facilities, the ``pollutant that is
subject to the standard promulgated under section 111 of the Act''
shall be considered the pollutant that otherwise is subject to
regulation under the Clean Air Act as defined in 40 CFR 52.21(b)(49).
(3) For the purposes of 40 CFR 70.2, with respect to GHG emissions
from designated facilities, the ``pollutant that is subject to any
standard promulgated under section 111 of the Act'' shall be considered
the pollutant that otherwise is ``subject to regulation'' as defined in
40 CFR 70.2.
(4) For the purposes of 40 CFR 71.2, with respect to GHG emissions
from designated facilities, the ``pollutant that is subject to any
standard promulgated under section 111 of the Act'' shall be considered
the pollutant that otherwise is ``subject to regulation'' as defined in
40 CFR 71.2.
(c) Exemption. You are exempt from the obligation to obtain a
permit under 40 CFR part 70 or 40 CFR part 71, provided you are not
otherwise required by law to obtain a permit under 40 CFR 70.3(a) or 40
CFR 71.3(a). Notwithstanding the previous sentence, you must continue
to comply with the provisions of this subpart.
Sec. 60.5386c Am I subject to this subpart?
You are subject to the applicable provisions of this subpart if you
are the owner or operator of one or more of the onshore designated
facilities listed in paragraphs (a) through (h) of this section, that
is located within the Crude Oil and Natural Gas source category, as
defined in Sec. 60.5430c, for which you commence construction,
modification, or reconstruction on or before December 6, 2022.
Facilities located inside and including the Local Distribution Company
(LDC) custody transfer station are not subject to this subpart.
(a) Each well designated facility, which is a single well drilled
for the purpose of producing oil or natural gas.
(b) Each centrifugal compressor designated facility, which is a
single centrifugal compressor. A centrifugal compressor located at a
well site is not a designated facility under this subpart. A
centrifugal compressor located at a centralized production facility is
a designated facility under this subpart.
(c) Each reciprocating compressor designated facility, which is a
single reciprocating compressor. A reciprocating compressor located at
a well site is not a designated facility under this subpart. A
reciprocating compressor located at a centralized production facility
is a designated facility under this subpart.
(d) Each process controller designated facility, which is the
collection of natural gas-driven process controllers at a well site,
centralized production facility, onshore natural gas processing plant,
or a compressor station. Natural gas-driven process controllers that
function as emergency shutdown devices and process controllers that are
not driven by natural gas are exempt from the designated facility.
(e)(1) Each storage vessel designated facility, which is a tank
battery that has the potential for methane emissions equal to or
greater than 20 tpy as specified in paragraph (e)(2) of this section. A
tank battery with the potential for methane emissions below 20 tpy is
not a storage vessel designated facility provided the owner or operator
keeps records of the potential for emissions calculation for the life
of the storage vessel or until such time the tank battery becomes a
storage vessel designated facility because the potential for methane
emissions meets or exceeds 20 tpy.
(2) The potential for methane emissions must be calculated as the
cumulative emissions from all storage vessels within the tank battery
as specified by the applicable requirements in paragraphs (e)(2)(i)
through (iii) of this section. The determination may take into account
requirements under a legally and practicably enforceable limit in an
operating permit or other requirement established under a Federal,
state, local, or Tribal authority.
(i) For purposes of determining the applicability of a storage
vessel tank battery as a designated facility, a legally and practicably
enforceable limit must include the elements provided in paragraphs
(e)(2)(i)(A) through (F) of this section.
(A) A quantitative production limit and quantitative operational
limit(s) for the equipment, or quantitative operational limits for the
equipment;
(B) An averaging time period for the production limit in
(e)(2)(i)(A), if a production-based limit is used, that is equal to or
less than 30 days;
(C) Established parametric limits for the production and/or
operational limit(s) in (e)(1)(i)(A), and where a control device is
used to achieve an operational limit, an initial compliance
demonstration (i.e., performance test) for the control device that
establishes the parametric limits;
(D) Ongoing monitoring of the parametric limits in (e)(2)(i)(C)
that demonstrates continuous compliance with the production and/or
operational limit(s) in (e)(2)(i)(A);
(E) Recordkeeping by the owner or operator that demonstrates
continuous compliance with the limit(s) in (e)(2)(i)(A) through (D);
and
(F) Periodic reporting that demonstrates continuous compliance.
(ii) For each tank battery located at a well site or centralized
production facility, you must determine the potential for methane
emissions within 60 days after the effective date of the approved state
or Tribal plan, except as provided in paragraph (e)(4)(iv) of this
section. The potential for methane emissions must be calculated using a
generally accepted model or calculation methodology that accounts for
flashing, working, and breathing losses, based on the maximum average
daily throughput
[[Page 17145]]
to the tank battery determined for a 30-day period of production.
(iii) For each tank battery not located at a well site or
centralized production facility, including each tank battery located at
a compressor station or onshore natural gas processing plant, you must
determine the potential for methane emissions within 60 days after the
effective date of the approved state or Tribal plan, using either
method described in paragraph (e)(2)(iii)(A) or (B) of this section.
(A) Determine the potential for methane emissions using a generally
accepted model or calculation methodology that accounts for flashing,
working, and breathing losses, and based on the throughput to the tank
battery established in a legally and practicably enforceable limit in
an operating permit or other requirement established under a Federal,
state, local, or Tribal authority; or
(B) Determine the potential for methane emissions using a generally
accepted model or calculation methodology that accounts for flashing,
working and breathing losses, based on projected maximum average daily
throughput. Maximum average daily throughput is determined using a
generally accepted engineering model (e.g., volumetric condensate rates
from the tank battery based on the maximum gas throughput capacity of
each producing facility) to project the maximum average daily
throughput for the tank battery.
(3) A storage vessel designated facility that subsequently has its
potential for methane emissions decrease to less than 20 tpy shall
remain a designated facility under this subpart.
(4) For storage vessels not subject to a legally and practicably
enforceable limit in an operating permit or other requirement
established under Federal, state, local, or Tribal authority, any vapor
from the storage vessel that is recovered and routed to a process
through a vapor recovery unit designed and operated as specified in
this section is not required to be included in the determination of
potential for methane emissions for purposes of determining designated
facility status, provided you comply with the requirements of
paragraphs (e)(4)(i) through (iv) of this section.
(i) You meet the cover requirements specified in Sec. 60.5411c(b).
(ii) You meet the closed vent system requirements specified in
Sec. 60.5411c(a)(2) through (4) and (c).
(iii) You must maintain records that document compliance with
paragraphs (e)(4)(i) and (ii) of this section.
(iv) In the event of removal of apparatus that recovers and routes
vapor to a process, or operation that is inconsistent with the
conditions specified in paragraphs (e)(4)(i) and (ii) of this section,
you must determine the storage vessel's potential for methane emissions
according to this section within 30 days of such removal or operation.
(5) The requirements of this paragraph (e)(5) apply to each storage
vessel designated facility immediately upon return to service. A
storage vessel designated facility or portion of a storage vessel
designated facility that is reconnected to the original source of
liquids remains a storage vessel designated facility subject to the
same requirements that applied before being removed from service. Any
storage vessel that is used to replace a storage vessel designated
facility or portion of a storage vessel designated facility, or used to
expand a storage vessel designated facility assumes the designated
facility status of the storage vessel designated facility being
replaced or expanded.
(6) A storage vessel with a capacity greater than 100,000 gallons
used to recycle water that has been passed through two stage separation
is not a storage vessel designated facility.
(f) Each process unit equipment designated facility, which is the
group of all equipment within a process unit at an onshore natural gas
processing plant is a designated facility. Equipment associated with a
compressor station, dehydration unit, sweetening unit, underground
storage vessel, field gas gathering system, or liquefied natural gas
unit is covered by Sec. Sec. 60.5400c, 60.5401c, 60.5402c, 60.5421c,
and 60.5422c if it is located at an onshore natural gas processing
plant. Equipment not located at the onshore natural gas processing
plant site is exempt from the provisions of Sec. Sec. 60.5400c,
60.5401c, 60.5402c, 60.5421c, and 60.5422c.
(g) Each pump designated facility, which is the collection of
natural gas-driven diaphragm and piston pumps at a well site,
centralized production facility, onshore natural gas processing plant,
or a compressor station. Pumps that are not driven by natural gas and
that are not in operation 90 days or more per calendar year are not
included in the pump designated facility.
(h) Each fugitive emissions components designated facility, which
is the collection of fugitive emissions components at a well site,
centralized production facility, or a compressor station.
Sec. 60.5387c When must I comply with this subpart?
Table 1 of this subpart specifies the final compliance date.
Model Rule--Emission and Work Practice Standards
Sec. 60.5388c What standards apply to super-emitter events?
This section applies to super-emitter events. For purposes of this
section, a super-emitter event is defined as any emissions event that
is located at an oil and natural gas facility (e.g., individual well
site, centralized production facility, natural gas processing plant, or
compressor station) and that is detected using remote detection methods
and has a quantified emission rate of 100 kg/hr of methane or greater.
Upon receiving a notification of a super emitter event issued by the
EPA under Sec. 60.5371b(c) in subpart OOOOb of this part, owners or
operators must take the actions listed in paragraphs (a) and (b) of
this section. Within 5 calendar days of receiving a notification from
the EPA of a super-emitter event, the owner or operator of an oil and
natural gas facility (e.g., a well site, centralized production
facility, natural gas processing plant, or compressor station) must
initiate a super-emitter event investigation.
(a) Identification of super-emitter events. (1) If you do not own
or operate an oil and natural gas facility within 50 meters from the
latitude and longitude provided in the notification subject to the
regulation under this subpart, report this result to the EPA under
paragraph (e) of this section. Your super-emitter event investigation
is deemed complete under this subpart.
(2) If you own or operate an oil and natural gas facility within 50
meters from the latitude and longitude provided in the notification,
and there is a designated facility or associated equipment subject to
this subpart onsite, you must investigate to determine the source of
the super-emitter event in accordance with this paragraph (a) and
report the results in accordance with paragraph (b) of this section.
(3) The investigation required by paragraph (a)(2) of this section
may include but is not limited to the actions specified below in
paragraphs (a)(2)(i) through (v) of this section.
(i) Review any maintenance activities (e.g., liquids unloading) or
process activities from the designated facilities subject to regulation
under this subpart, starting from the date of detection of the super-
emitter event as identified in the notification, until the date of
investigation, to determine if the activities indicate any potential
[[Page 17146]]
source(s) of the super-emitter event emissions.
(ii) Review all monitoring data from control devices (e.g., flares)
from the designated facilities subject to regulation under this subpart
from the initial date of detection of the super-emitter event as
identified in the notification, until the date of receiving the
notification from the EPA to identify malfunctions of control devices
or periods when the control devices were not in compliance with
applicable requirements and that indicate a potential source of the
super-emitter event emissions.
(iii) If you conducted a fugitive emissions survey or periodic
screening event in accordance with Sec. 60.5397c or Sec. 60.5398c(b)
between the initial date of detection of the super-emitter event as
identified in the notification and the date the notification from the
EPA was received, review the results of the survey to identify any
potential source(s) of the super-emitter event emissions.
(iv) If you use conduct continuous monitoring with advanced methane
detection technology in accordance with Sec. 60.5398c(c), review the
monitoring data collected on or after the initial date of detection of
the super-emitter event as identified in the notification, until the
date of receiving the notification from the EPA.
(v) Screen the entire well site, centralized production facility,
or compressor station with OGI, Method 21 of appendix A-7 to this part,
or an alternative test method(s) approved per Sec. 60.5398c(d), to
determine if a super-emitter event is present.
(4) If the source of the super-emitter event was found to be from
fugitive emission components at a well site, centralized production
facility, or compressor station subject to this subpart, you must
comply with the repair requirements under Sec. 60.5397c and the
associated recordkeeping and reporting requirements under Sec.
60.5420c(b)(8) and Sec. 60.5420c(c)(13).
(b) Super-emitter event report. You must submit the results of the
super-emitter event investigation conducted under paragraph (a) of this
section to the EPA in accordance with paragraph (b)(1) of this section.
If the super-emitter event (i.e., emission at 100 kg/hr of methane or
more) is ongoing at the time of the initial report, submit the
additional information in accordance with paragraph (b)(2) of this
section. You must attest to the information included in the report as
specified in paragraph (b)(3) of this section.
(1) Within 15 days of receiving a notification from the EPA under
Sec. 60.5371b(c), you must submit a report of the super-emitter event
investigation conducted under paragraph (a) of this section through the
Super-Emitter Program Portal, at www.epa.gov/super-emitter. You must
include the applicable information in paragraphs (b)(1)(i) through
(viii) of this section in the report. If you have identified a
demonstrable error in the notification, the report may include a
statement of the demonstrable error.
(i) Notification Report ID of the super-emitter event notification.
(ii) Identification of whether you are the owner or operator of an
oil and natural gas facility that is located within 50 meters from the
latitude and longitude provided in the EPA notification. If you do not
own or operate an oil and natural gas facility within 50 meters from
the latitude and longitude provided in the EPA notification, you are
not required to report the information in paragraphs (b)(1)(iii)
through (viii) of this section.
(iii) General identification information for the facility,
including, facility name, the physical address, applicable ID Number
(e.g., EPA ID Number, API Well ID Number), the owner or operator or
responsible official (where applicable) and their email address.
(iv) Identification of whether there is a designated facility or
associated equipment subject to regulation under this subpart at this
oil and natural gas facility.
(v) Indication of whether you were able to identify the source of
the super-emitter event. If you indicate you were unable to identify
the source of the super-emitter event, you must certify that all
applicable investigations specified in paragraphs (a)(3)(i) through (v)
of this section have been conducted for all designated facilities and
associated equipment subject to regulation under this subpart that are
at this oil and natural gas facility, and you have determined that the
designated facilities and associated equipment are not the source of
the super-emitter event. If you indicate that you were not able to
identify the source of the super-emitter event, you are not required to
report the information in paragraphs (b)(1)(vi) through (viii) of this
section.
(vi) The source(s) of the super-emitter event.
(vii) Identification of whether the source of the super-emitter
event is a designated facility or associated equipment subject to
regulation under of this subpart. If the source of the super-emitter
event is a designated facility or associated equipment subject to
regulation under this subpart, identify the applicable regulation(s)
under this subpart.
(viii) Indication of whether the super-emitter event is ongoing at
the time of the initial report submittal (i.e., emission at 100 kg/hr
of methane or more).
(A) If the super-emitter event is not ongoing at the time of the
initial report submittal, provide the actual (or if not known,
estimated) date and time the super-emitter event ended.
(B) If the super-emitter event is ongoing at the time of the
initial report submittal, provide a short narrative of your plan to end
the super-emitter event, including the targeted end date for the
efforts to be completed and the super-emitter event ended.
(2) If the super-emitter event is ongoing at the time of the
initial report submittal, within 5 business days of the date the super-
emitter event ends you must update your initial report through the
Super-Emitter Program Portal to provide the end date and time of the
super-emitter event.
(3) You must sign the following attestation when submitting data
into the Super-Emitter Program Portal: ``I certify that the information
provided in this report regarding the specified super-emitter event was
prepared under my direction or supervision. I further certify that the
investigations were conducted, and this report was prepared pursuant to
the requirements of Sec. 60.5371c (a) and (b). Based on my
professional knowledge and experience, and inquiry of personnel
involved in the assessment, the certification submitted herein is true,
accurate, and complete. I am aware that knowingly false statements may
be punishable by fine or imprisonment.''
Sec. 60.5390c What GHG standards apply to gas well liquids unloading
operations at well designated facilities?
(a) General requirements. You must comply with the requirements of
this section for each gas well liquids unloading operation at your gas
well designated facility as specified by paragraphs (a)(1) and (2) of
this section. You have a general duty to safely maximize resource
recovery and minimize releases to the atmosphere during gas well
liquids unloading operations.
(1) If a gas well liquids unloading operation technology or
technique employed does not result in venting of methane emissions to
the atmosphere, you must comply with the requirements specified in
paragraphs (a)(1)(A) and (B) of this section. If an unplanned venting
event occurs, you must meet the
[[Page 17147]]
requirements specified in paragraphs (c) through (f) of this section.
(A) Comply with the recordkeeping requirements specified in Sec.
60.5420c(c)(1)(i).
(B) Submit the information specified in Sec. 60.5420c(b)(1) and
(2)(i) in the annual report.
(2) If a gas well liquids unloading operation technology or
technique vents methane emissions to the atmosphere, you must comply
with the requirements specified in paragraphs (b) and (c), or paragraph
(g) of this section.
(b) Work Practice Standards. If a gas well liquids unloading
operation employs a technology or technique that vents methane
emissions to the atmosphere, you must comply with the requirements in
paragraphs (b)(1) through (3) and paragraphs (c) through (f) of this
section.
(1) Employ best management practices to minimize venting of methane
emissions as specified in paragraph (c) of this section for each gas
well liquids unloading operation.
(2) Comply with the recordkeeping requirements specified in Sec.
60.5420c(c)(1)(ii).
(3) Submit the information specified in Sec. 60.5420c(b)(1) and
(2)(ii) in the annual report.
(c) Best management practice requirements. For each gas well
liquids unloading operation complying with paragraphs (a)(2) and (b) of
this section, you must develop, maintain, and follow a best management
practice plan to minimize venting of methane emissions to the maximum
extent possible from each gas well liquids unloading operation. This
best management practice plan must meet the minimum criteria specified
in paragraphs (c)(1) through (4) of this section.
(1) Include steps that create a differential pressure to minimize
the need to vent a well to unload liquids,
(2) Include steps to reduce wellbore pressure as much as possible
prior to opening the well to the atmosphere,
(3) Unload liquids through the separator where feasible, and
(4) Close all wellhead vents to the atmosphere and return the well
to production as soon as practicable.
(d) Initial compliance. You must demonstrate initial compliance
with the standards that apply to well liquids unloading operations at
your well designated facilities as required by Sec. 60.5410c(a).
(e) Continuous compliance. You must demonstrate continuous
compliance with the standards that apply to well liquids unloading
operations at your well designated facilities as required by Sec.
60.5415c(a).
(f) Recordkeeping and recording. You must perform the required
notification, recordkeeping and reporting requirements as specified in
Sec. 60.5420c(b)(2) and (c)(1).
(g) Other compliance options. Reduce methane emissions from well
designated facilities gas wells that unload liquids by 95.0 percent by
complying with the requirements specified in paragraphs (g)(1) and (2)
of this section and meeting the initial and continuous compliance and
recordkeeping and reporting requirements specified in paragraphs (g)(3)
through (5) of this section.
(1) You must route emissions through a closed vent system to a
control device that meets the conditions specified in Sec. 60.5412c.
(2) You must route emissions through a closed vent system that
meets the requirements of Sec. 60.5411c(a) and (c).
(3) You must demonstrate initial compliance with standards that
apply to well designated facility gas well liquids unloading as
required by Sec. 60.5410c(b).
(4) You must demonstrate continuous compliance with standards that
apply to well designated facility gas well liquids unloading as
required by Sec. 60.5415c(b).
(5) You must perform the reporting as required by Sec.
60.5420c(b)(1), (2), and (10) through (12), as applicable; and the
recordkeeping as required by Sec. 60.5420c(c)(1), (7), and (9) through
(12), as applicable.
Sec. 60.5391c What GHG standards apply to associated gas wells at
well designated facilities?
(a) You must comply with either paragraph (a)(1), (2), (3), or (4)
of this section for each associated gas well, except as provided in
paragraphs (b), (c), and (d) of this section. You must also comply with
paragraphs (f), (g), and (h) of this section.
(1) Recover the associated gas from the separator and route the
recovered gas into a gas gathering flow line or collection system to a
sales line.
(2) Recover the associated gas from the separator and use the
recovered gas as an onsite fuel source.
(3) Recover the associated gas from the separator and use the
recovered gas for another useful purpose that a purchased fuel or raw
material would serve.
(4) Recover the associated gas from the separator and reinject the
recovered gas into the well or inject the recovered gas into another
well.
(b) If you meet one of the conditions in paragraphs (b)(1) or (2)
of this section, you may route the associated gas to a control device
that reduces methane emissions by at least 95.0 percent instead of
complying with paragraph (a) of this section. The associated gas must
be routed through a closed vent system that meets the requirements of
Sec. 60.5411c(a) and (c) and the control device must meet the
conditions specified in Sec. 60.5412c(a), (b), and (c).
(1) If the annual methane contained in the associated gas from your
oil well is 40 tons per year or less at the initial compliance date,
determined in accordance with paragraph (e) of this section.
(2) If you demonstrate and certify that it is not feasible to
comply with paragraph (a)(1), (2), (3), and (4) of this section due to
technical reasons by providing a detailed analysis documenting and
certifying the technical reasons for this infeasibility in accordance
with paragraphs (b)(2)(i) through (iv) of this section.
(i) In order to demonstrate that it is not feasible to comply with
paragraph (a)(1), (2), (3), and (4) of this section, you must provide a
detailed analysis documenting and certifying the technical reasons for
this infeasibility. The demonstration must address the technical
infeasibility for all options identified in (a)(1), (2), (3), and (4)
of this section. Documentation of these demonstrations must be
maintained in accordance with Sec. 60.5420c(c)(2)(ii).
(ii) This demonstration must be certified by a professional
engineer or another qualified individual with expertise in the uses of
associated gas. The following certification, signed and dated by the
qualified professional engineer or other qualified individual shall
state: ``I certify that the assessment of technical and safety
infeasibility was prepared under my direction or supervision. I further
certify that the assessment was conducted, and this report was prepared
pursuant to the requirements of Sec. 60.5391c(b)(1). Based on my
professional knowledge and experience, and inquiry of personnel
involved in the assessment, the certification submitted herein is true,
accurate, and complete.''
(iii) This demonstration and certification are valid for no more
than 12 months. You must re-analyze the feasibility of complying with
paragraphs (a)(1), (2), (3), and (4) of this section and finalize a new
demonstration and certification each year.
(iv) Documentation of these demonstrations, along with the
certifications, must be maintained in accordance with Sec.
60.5420c(c)(3)(ii) and submitted in annual reports in accordance with
Sec. 60.5420c(b)(3).
(c) If you are complying with paragraph (a) of this section, you
may
[[Page 17148]]
temporarily route the associated gas to a flare or control device in
the situations and for the durations identified in paragraphs (c)(1),
(2), (3), or (4) of this section. The associated gas must be routed
through a closed vent system that meets the requirements of Sec.
60.5411c(a) and (c) and the control device must meet the conditions
specified in Sec. 60.5412c(a), (b) and (c). If you are routing to a
flare, you must demonstrate that the Sec. 60.18 flare requirements are
met during the period when the associated gas is routed to the flare.
Records must be kept of all temporary flaring instances in accordance
with Sec. 60.5420c(c)(3) and reported in the annual report in
accordance with Sec. 60.5420c(b)(3).
(1) For equal to or less than 24 hours during a deviation caused by
malfunction causing the need to flare.
(2) For equal to or less than 24 hours during repair, maintenance
including blow downs, a bradenhead test, a packer leakage test, a
production test, or commissioning.
(3) For (a)(1) and (b)(1) of this section, through the duration of
a temporary interruption in service from the gathering or pipeline
system, or 30 days, whichever is less.
(4) For 72 hours from the time that the associated gas does not
meet pipeline specifications, or until the associated gas meets
pipeline specifications, whichever is less.
(d) If you are complying with paragraph (a), (b), or (c) of this
section, you may vent the associated gas in the situations and for the
durations identified in paragraphs (d)(1), (2), or (3) of this section.
Records must be kept of all venting instances in accordance with Sec.
60.5420c(c)(3) and reported in the annual report in accordance with
Sec. 60.5420c(b)(3).
(1) For up to 12 hours to protect the safety of personnel.
(2) For up to 30 minutes during bradenhead monitoring.
(3) For up to 30 minutes during a packer leakage test.
(e) Calculate the methane content in associated gas as specified in
paragraph (e)(1) of this section and comply with paragraphs (e)(2) and
(e)(3) of this section.
(1) Calculate the methane content in associated gas from your oil
well using the following equation
[GRAPHIC] [TIFF OMITTED] TR08MR24.036
Where:
AGmethane = Amount of methane in associated gas from the
oil well, tons methane per year
GOR = Gas to oil ratio for the well in standard cubic feet of gas
per barrel of oil; oil here refers to hydrocarbon liquids produced
of all API gravities. GOR is to be determined for the well using
available data, an appropriate standard method published by a
consensus-based standards organization which include, but are not
limited to, the following: ASTM International, the American National
Standards Institute (ANSI), the American Gas Association (AGA), the
American Society of Mechanical Engineers (ASME), the American
Petroleum Institute (API), and the North American Energy Standards
Board (NAESB), or in industry standard practice.
V = Volume of oil produced in the calendar year preceding the
initial compliance date, in barrels per year.
Mmethane = mole fraction of methane in the associated
gas.
0.0192 = density of methane gas at 60 [deg]F and 14.7 psia in
kilograms per cubic foot
907.2 = conversion of kilograms to tons, kilograms per ton
(2) You must maintain records of the calculation of the methane in
associated gas from your oil well results in accordance with Sec.
60.5410c(c)(3), and submit the information, as well as the background
information, in the next annual report in accordance with Sec.
60.5410c(b)(3).
(3) If a process change occurs that could increase the methane
content in the associated gas, you must recalculate the methane content
in accordance with paragraph (a)(d)(1) of this section.
(f) You must demonstrate initial compliance with the standards that
apply to associated gas wells at well designated facilities as required
by Sec. 60.5410c(b).
(g) You must demonstrate continuous compliance with the standards
that apply to associated gas wells at well designated facilities as
required by Sec. 60.5415c(b)(3).
(h) You must perform the required recordkeeping and reporting as
required by Sec. 60.5420c(b)(3), (10) and (11), as applicable, and
Sec. 60.5420c(c)(2) and (7) and (9) through (12), as applicable.
Sec. 60.5392c What GHG standards apply to centrifugal compressor
designated facilities?
Each centrifugal compressor designated facility must comply with
the GHG standards in paragraphs (a) through (d) of this section.
(a) Each centrifugal compressor designated facility that is a wet
seal centrifugal compressor, each self-contained wet seal centrifugal
compressor, and each Alaska North Slope centrifugal compressor equipped
with sour seal oil separator and capture system, must comply with the
GHG standards, using volumetric flow rate as a surrogate, as specified
in paragraphs (a)(1) and (2) of this section. Each centrifugal
compressor designated facility that is a dry seal centrifugal
compressor must comply with the GHG standards, using volumetric flow
rate as a surrogate, as specified in paragraphs (a)(1) and (2) of this
section, and either paragraph (a)(4) or (5) of this section.
Alternatively, you have the option of complying with the GHG standards
for your wet seal and dry seal centrifugal compressor by meeting the
requirements specified in paragraph (a)(3), and either paragraph (a)(4)
or (5) of this section.
(1) If you utilize a centrifugal compressor, you must comply with
the GHG standards in paragraph (a)(1)(i) through (iii) of this section,
and the seal repair requirements of paragraph (a)(1)(iv) of this
section.
(i) You must conduct volumetric flow rate measurements from each
wet seal centrifugal compressor (including each self-contained wet seal
centrifugal compressor) vent using the methods specified in paragraph
(a)(2) of this section and in accordance with the schedule specified in
paragraphs (a)(1)(i)(A) and (B) of this section. The volumetric flow
rate, measured in accordance with paragraph (a)(2) of this section,
must not exceed 3 standard cubic feet per minute (scfm) per seal. If
the individual seals are manifolded to a single open-vented line, the
volumetric flow rate must not exceed the sum of the individual seals
multiplied by 3 scfm. If the volumetric flow rate exceeds 3 scfm
multiplied by the number of seals connected to the vent, the seals
connected to the measured vent must be repaired as provided in
paragraph (a)(1)(iv) of this section.
[[Page 17149]]
(A) You must conduct your first volumetric flow rate measurement
from your wet seal centrifugal compressor (including self-contained wet
seal centrifugal compressors) vents on or before 8,760 hours of
operation 36 months after the state plan submittal deadline (as
specified in Sec. 60.5362c(c)), or on or before 8,760 hours of
operation after startup, whichever date is later.
(B) You must conduct subsequent volumetric flow rate measurements
from your wet seal centrifugal compressor (including self-contained wet
seal centrifugal compressor) vents on or before 8,760 hours of
operation after the previous measurement.
(ii) You must conduct volumetric flow rate measurements from each
Alaska North Slope centrifugal compressor equipped with sour seal oil
separator and capture system using the methods specified in paragraph
(a)(2) of this section and in accordance with the schedule specified in
paragraphs (a)(1)(ii)(A) and (B) of this section. The volumetric flow
rate, measured in accordance with paragraph (a)(2) of this section,
must not exceed 9 standard cubic feet per minute (scfm) per seal. If
the individual seals are manifolded to a single open-vented line, the
volumetric flow rate must not exceed the sum of the individual seals
multiplied by 9 scfm. If the volumetric flow rate exceeds 9 scfm
multiplied by the number of seals connected to the vent, the seals
connected to the measured vent must be repaired as provided in
paragraph (a)(1)(iv) of this section.
(A) You must conduct your first volumetric flow rate measurement
from your centrifugal compressor equipped with sour seal oil separator
and capture system utilized in Alaska wet seal vent on or before 8,760
hours of operation 36 months after the state plan submittal deadline
(as specified in Sec. 60.5362c(c)), or on or before 8,760 hours of
operation after startup, whichever date is later.
(B) You must conduct subsequent volumetric flow rate measurements
from your centrifugal compressor wet seal vents on or before 8,760
hours of operation after the previous measurement.
(iii) You must conduct volumetric flow rate vent measurements from
each centrifugal compressor equipped with dry seals using the methods
specified in paragraph (a)(2) of this section and in accordance with
the schedule specified in paragraphs (a)(1)(iii)(A) and (B) of this
section. The volumetric flow rate, measured in accordance with
paragraph (a)(2) of this section, must not exceed 10 standard cubic
feet per minute (scfm) per seal. If the individual seals are manifolded
to a single open-vented line, the volumetric flow rate must not exceed
the sum of the individual seals multiplied by 10 scfm. If the
volumetric flow rate exceeds 10 scfm multiplied by the number of seals
connected to the vent, the seals connected to the measured vent must be
repaired as provided in paragraph (a)(1)(iv) of this section.
(A) You must conduct your first volumetric flow rate vent
measurement from your centrifugal compressor equipped with a dry seal
on or before 8,760 hours of operation 36 months after the state plan
submittal deadline (as specified in Sec. 60.5362c(c)), or on or before
8,760 hours of operation after startup, whichever date is later.
(B) You must conduct subsequent volumetric flow rate vent
measurements from your centrifugal compressor equipped with a dry seal
on or before 8,760 hours of operation after the previous measurement.
(iv) The seal must be repaired within 90 calendar days after the
date of the volumetric emissions measurement that exceeds the
applicable required flow rate per seal. You must conduct follow-up
volumetric flow rate measurements from seal vents using the methods
specified in paragraph (a)(2) of this section within 15 days after the
repair to document that the rate has been reduced to less than the
applicable required flow rate per seal. If the individual seals are
manifolded to a single open-ended line or vent, the volumetric flow
rate must be reduced to less than the sum of the individual seals
multiplied by the applicable required flow rate per seal specified in
paragraph (a)(1)(i) through (iii) of this section, as applicable. Delay
of repair will be allowed if the conditions in paragraphs (a)(1)(iv)(A)
or (B) of this section are met.
(A) If the repair of the wet or dry seal is technically infeasible,
would require a vent blowdown, a compressor station shutdown, or would
be unsafe to repair during operation of the unit, the repair must be
completed during the next scheduled compressor station shutdown for
maintenance, after a scheduled vent blowdown, or within 2 years of the
date of the volumetric emissions measurement that exceeds the
applicable required flow rate per seal, whichever is earliest. A vent
blowdown is the opening of one or more blowdown valves to depressurize
major production and processing equipment, other than a storage vessel.
(B) If the repair requires replacement of the compressor seal or a
part thereof, but the replacement seal or part cannot be acquired and
installed within the repair timelines specified under this section due
to the condition specified in paragraph (a)(1)(iv)(B)(1) of this
section, the repair must be completed in accordance with paragraph
(a)(1)(iv)(B)(2) of this section and documented in accordance with
Sec. 60.5420c(c)(3)(iii)(F) through (H).
(1) Seal or part thereof supplies had been sufficiently stocked but
are depleted at the time of the required repair.
(2) The required replacement seal or part must be ordered no later
than 10 calendar days after the centrifugal compressor is added to the
delay of repair list due to parts unavailability. The repair must be
completed as soon as practicable, but no later than 30 calendar days
after receipt of the replacement seal or part, unless the repair
requires a compressor station shutdown. If the repair requires a
compressor station shutdown, the repair must be completed in accordance
with the timeframe specified in paragraph (a)(1)(iv)(A) of this
section.
(2) You must determine the volumetric flow rates from your
centrifugal compressor dry or wet seal vents as specified in paragraph
(a)(2)(i) or (ii) of this section.
(i) For each dry or wet seal centrifugal compressor in operating-
mode or in standby-pressurized-mode, determine volumetric flow rate at
standard conditions from each dry or wet seal vent using one of the
methods specified in paragraphs (a)(2)(i)(A) through (C) of this
section.
(A) You may choose to use any of the methods set forth in Sec.
60.5405c(a) to screen for leaks/emissions. For the purposes of this
paragraph, when using any of the methods in Sec. 60.5405c(a),
emissions are detected whenever a leak is detected according to the
method. If emissions are detected using the methods set forth in Sec.
60.5405c(a), then you must use one of the methods specified in
paragraph (a)(2)(i)(B) or (C) of this section to determine the
volumetric flow rate. If emissions are not detected using the methods
in Sec. 60.5405c(a), then you may assume that the volumetric flow rate
is zero.
(B) Use a temporary or permanent flow meter according to methods
set forth in Sec. 60.5405c(b).
(C) Use a high-volume sampler according to the methods set forth in
Sec. 60.5405c(c).
(ii) For conducting measurements on manifolded groups of dry or wet
seal centrifugal compressors, you must determine the volumetric flow
rate from the compressor dry or wet seal as specified in paragraph
(a)(2)(ii)(A) or (B) of this section.
[[Page 17150]]
(A) Measure at a single point in the manifold downstream of all dry
or wet seal compressor inputs and, if practical, prior to comingling
with other non-compressor emission sources.
(B) Determine the volumetric flow rate at standard conditions from
the common stack using one of the methods specified in paragraph
(a)(2)(i)(A) through (C) of this section.
(3) As an alternative to meeting the requirements of paragraphs
(a)(1) and (2) of this section for compressors with wet seals and dry
seals, you have the option of reducing methane emissions from each
centrifugal compressor wet seal fluid degassing system by 95.0 percent
by meeting the requirements of paragraph (a)(4) of this section, or the
option of routing the emissions from each centrifugal compressor wet
seal fluid degassing system or dry seal system to a process by meeting
the requirements of paragraph (a)(5) of this section.
(4) If you use a control device to reduce methane emissions by 95.0
percent, you must equip the wet seal fluid degassing system with a
cover that meets the requirements of Sec. 60.5411c(b). The cover must
be connected through a closed vent system that meets the requirements
of Sec. 60.5411c(a) and (c) and the closed vent system must be routed
to a control device that meets the conditions specified in Sec.
60.5412c.
(5) If you route the emissions to a process, you must equip the wet
seal fluid degassing system or dry seal system with a cover that meets
the requirements of Sec. 60.5411c(b). The cover must be connected
through a closed vent system that meets the requirements of Sec.
60.5411c(a) and (c).
(b) You must demonstrate initial compliance with the standards that
apply to centrifugal compressor designated facilities as required by
Sec. 60.5410c(c).
(c) You must demonstrate continuous compliance with the standards
that apply to centrifugal compressor designated facilities as required
by Sec. 60.5415c(c).
(d) You must perform the reporting as required by Sec.
60.5420c(b)(1) and (4) and (b)(10) through (12), as applicable; and the
recordkeeping as required by Sec. 60.5420c(c)(3) and (c)(7) through
(12), as applicable.
Sec. 60.5393c What GHG standards apply to reciprocating compressor
designated facilities?
Each reciprocating compressor designated facility must comply with
the GHG standards, using volumetric flow rate as a surrogate, in
paragraphs (a) through (c) of this section, or the GHG standards in
paragraph (d) of this section. You must also comply with the
requirements in paragraphs (e) through (g) of this section.
(a) The volumetric flow rate of each cylinder, measured in
accordance with paragraph (b) or (c) of this section, must not exceed 2
scfm per individual cylinder. If the individual cylinders are
manifolded to a single open-ended vent line, the volumetric flow rate
must not exceed the sum of the individual cylinders multiplied by 2
scfm. You must conduct measurements of the volumetric flow rate in
accordance with the schedule specified in paragraphs (a)(1) and (2) of
this section and determine the volumetric flow rate per cylinder in
accordance with paragraph (b) or (c) of this section. If the volumetric
flow rate, measured in accordance with paragraph (b) or (c) of this
section, for a cylinder exceeds 2 scfm per cylinder (or a combined
volumetric flow rate greater than the number of compression cylinders
multiplied by 2 scfm), the rod packing or packings must be repaired or
replaced as provided in paragraph (a)(3) of this section.
(1) You must conduct your first volumetric flow rate measurements
from your reciprocating compressor rod packing vent on or before 8,760
hours of operation after the effective date of an approved state or
Tribal plan, on or before 8,760 hours of operation after last rod
packing replacement, or on or before 8,760 hours of operation after
startup, whichever date is later.
(2) You must conduct subsequent volumetric flow rate measurements
from your reciprocating compressor rod packing vent on or before 8,760
hours of operation after the previous measurement which demonstrates
compliance with the applicable volumetric flow rate of 2 scfm per
cylinder (or a combined cylinder volumetric flow rate greater than the
number of compression cylinders multiplied by 2 scfm), or on or before
8,760 hours of operation after last rod packing replacement, whichever
date is later.
(3) The rod packing must be repaired or replaced within 90 calendar
days after the date of the volumetric emissions measurement that
exceeded 2 scfm per cylinder. You must conduct follow-up volumetric
flow rate measurements from compressor vents using the methods
specified in paragraph (b) of this section within 15 days after the
repair (or rod packing replacement) to document that the rate has been
reduced to less than 2 scfm per cylinder. Delay of repair will be
allowed if the conditions in paragraphs (a)(3)(i) or (ii) of this
section are met.
(i) If the repair (or rod packing replacement) is technically
infeasible, would require a vent blowdown, a compressor station
shutdown, or would be unsafe to repair during operation of the unit,
the repair (or rod packing replacement) must be completed during the
next scheduled compressor station shutdown for maintenance, after a
scheduled vent blowdown, or within 2 years of the date of the
volumetric emissions measurement that exceeds the applicable required
flow rate per cylinder, whichever is earliest. A vent blowdown is the
opening of one or more blowdown valves to depressurize major production
and processing equipment, other than a storage vessel.
(ii) If the repair requires replacement of the rod packing or a
part, but the replacement cannot be acquired and installed within the
repair timelines specified under this section due to the condition
specified in paragraph (a)(3)(ii)(A) of this section, the repair must
be completed in accordance with paragraph (a)(3)(ii)(B) of this section
and documented in accordance with Sec. 60.5420c(c)(4)(viii) through
(x).
(A) Rod packing or part supplies had been sufficiently stocked but
are depleted at the time of the required repair.
(B) The required rod packing or part replacement must be ordered no
later than 10 calendar days after the reciprocating compressor is added
to the delay of repair list due to parts unavailability. The repair
must be completed as soon as practicable, but no later than 30 calendar
days after receipt of the replacement rod packing or part, unless the
repair requires a compressor station shutdown. If the repair requires a
compressor station shutdown, the repair must be completed in accordance
with the timeframe specified in paragraph (a)(3)(i) of this section.
(b) You must determine the volumetric flow rate per cylinder from
your reciprocating compressor as specified in paragraph (b)(1) or (2)
of this section.
(1) For reciprocating compressor rod packing equipped with an open-
ended vent line on compressors in operating or standby pressurized
mode, determine the volumetric flow rate of the rod packing using one
of the methods specified in paragraphs (b)(1)(i) through (iii) of this
section.
(i) Determine the volumetric flow rate at standard conditions from
the open-ended vent line using a high-volume sampler according to
methods set forth in Sec. 60.5405c(c).
[[Page 17151]]
(ii) Determine the volumetric flow rate at standard conditions from
the open-ended vent line using a temporary or permanent meter,
according to methods set forth in Sec. 60.5405c(b).
(iii) Any of the methods set forth in Sec. 60.5405c(a) to screen
for leaks and emissions. For the purposes of this paragraph, emissions
are detected whenever a leak is detected according to any of the
methods in Sec. 60.5405c(a). If emissions are detected using the
methods set forth in Sec. 60.5405c(a), then you must use one of the
methods specified in paragraph (b)(1)(i) and (ii) of this section to
determine the volumetric flow rate per cylinder. If emissions are not
detected using the methods in Sec. 60.5405c(a), then you may assume
that the volumetric flow rate is zero.
(2) For reciprocating compressor rod packing not equipped with an
open-ended vent line on compressors in operating or standby pressurized
mode, you must determine the volumetric flow rate of the rod packing
using the methods specified in paragraphs (b)(2)(i) and (ii) of this
section.
(i) You must use the methods described in Sec. 60.5405c(a) to
conduct leak detection of emissions from the rod packing case into an
open distance piece, or, for compressors with a closed distance piece,
you must conduct annual leak detection of emissions from the rod
packing vent, distance piece vent, compressor crank case breather cap,
or other vent emitting gas from the rod packing.
(ii) You must measure emissions found in paragraph (b)(2)(i) of
this section using a meter or high-volume sampler according to methods
set forth in Sec. 60.5405c(b) or (c).
(c) For conducting measurements on manifolded groups of
reciprocating compressor designated facilities, you must determine the
volumetric flow rate from reciprocating compressor rod packing vent as
specified in paragraph (c)(1) and (2) of this section.
(1) Measure at a single point in the manifold downstream of all
compressor vent inputs and, if practical, prior to comingling with
other non-compressor emission sources.
(2) Determine the volumetric flow rate per cylinder at standard
conditions from the common stack using one of the methods specified in
paragraph (c)(2)(i) through (iv) of this section.
(i) A temporary or permanent flow meter according to the methods
set forth in Sec. 60.5405c(b).
(ii) A high-volume sampler according to methods set forth Sec.
60.5405c(c).
(iii) An alternative method, as set forth in Sec. 60.5405c(d).
(iv) Any of the methods set forth in Sec. 60.5405c(a) to screen
for emissions. For the purposes of this paragraph, emissions are
detected whenever a leak is detected when using any of the methods in
Sec. 60.5405c(a). If emissions are detected using the methods set
forth in Sec. 60.5405c(a), then you must use one of the methods
specified in paragraph (c)(2)(i) through (iii) of this section to
determine the volumetric flow rate per cylinder. If emissions are not
detected using the methods in Sec. 60.5405c(a), then you may assume
that the volumetric flow rate is zero.
(d) As an alternative to complying with the GHG standards in
paragraphs (a) through (c) of this section, owners or operators can
meet the requirements specified in paragraph (d)(1), (2), or (3) of
this section.
(1) Collect the methane emissions from your reciprocating
compressor rod packing using a rod packing emissions collection system
that is operated to route the rod packing emissions to a process. In
order to comply with this option, you must equip the reciprocating
compressor with a cover that meets the requirements of Sec.
60.5411c(b). The cover must be connected through a closed vent system
that meets the requirements of Sec. 60.5411c(a) and (c).
(2) Reduce methane emissions from each rod packing emissions
collection system by using a control device that reduces methane
emissions by 95.0 percent. In order to comply with this option, you
must equip the reciprocating compressor with a cover that meets the
requirements of Sec. 60.5411c(b). The cover must be connected through
a closed vent system that meets the requirements of Sec. 60.5411c(a)
and (c) and the closed vent system must be routed to a control device
that meets the conditions specified in Sec. 60.5412c.
(3) As an alternative to conducting the required volumetric flow
rate measurements under paragraph (a) of this section, an owner or
operator can choose to comply by replacing the rod packing on or before
8,760 hours of operation after the effective date of the final rule, on
or before 8,760 hours of operation after the previous flow rate
measurement, or on or before 8,760 hours of operation after the date of
the most recent compressor rod packing replacement, whichever date is
later.
(e) You must demonstrate initial compliance with standards that
apply to reciprocating compressor designated facilities as required by
Sec. 60.5410c(d).
(f) You must demonstrate continuous compliance with standards that
apply to reciprocating compressor designated facilities as required by
Sec. 60.5415c(f).
(g) You must perform the reporting requirements as specified in
Sec. 60.5420c(b)(1), (5), (10), and (11), as applicable; and the
recordkeeping requirements as specified in Sec. 60.5420c(c)(4) and (7)
through (11), as applicable.
Sec. 60.5394c What GHG standards apply to process controller
designated facilities?
Each process controller designated facility must comply with the
GHG standards in this section.
(a) You must design and operate each process controller designated
facility with zero methane emissions to the atmosphere, except as
provided in paragraph (b) of this section.
(1) If you comply by routing the emissions to a process, emissions
must be routed to a process through a closed vent system.
(2) If you comply by using a self-contained natural gas-driven
process controller, you must design and operate each self-contained
natural gas-driven process controller with no identifiable emissions,
as demonstrated by Sec. 60.5416c(b).
(b) For each process controller designated facility located at a
site in Alaska that does not have access to electrical power, you may
comply with either paragraphs (b)(1) and (2) of this section or with
paragraph (b)(3) of this section, instead of complying with paragraph
(a) of this section.
(1) With the exception of natural gas-driven continuous bleed
controllers that meet the condition in paragraph (b)(1)(i) of this
section and that comply with paragraph (b)(1)(ii) of this section, each
natural gas-driven continuous bleed process controller in the process
controller designated facility must have a bleed rate less than or
equal to 6 standard cubic feet per hour (scfh).
(i) A natural gas-driven continuous bleed process controller with a
bleed rate higher than 6 scfh may be used if the requirements of
paragraph (b)(1)(ii) of this section are met.
(ii) You demonstrate that a natural gas-driven continuous bleed
controller with a bleed rate higher than 6 scfh is required. The
demonstration must be based on the specific functional need, including
but not limited to response time, safety, or positive actuation.
(2) Each natural gas-driven intermittent vent process controller in
the process controller designated facility must comply with the
requirements in paragraphs (b)(2)(i) and (ii) of this section.
(i) Each natural gas-driven intermittent vent process controller
[[Page 17152]]
must not emit to the atmosphere during idle periods.
(ii) You must monitor each natural gas-driven intermittent vent
process controller to ensure that it is not emitting to the atmosphere
during idle periods, as specified in paragraphs (b)(2)(ii)(A) through
(C) of this section.
(A) Monitoring must be conducted at the same frequency as specified
for fugitive emissions components designated facilities located at the
same type of site, as specified in Sec. 60.5397c(g).
(B) You must include the monitoring of each natural gas-driven
intermittent vent process controller in the monitoring plan required in
Sec. 60.5397c(b).
(C) When monitoring identifies emissions to the atmosphere from a
natural gas-driven intermittent vent controller during idle periods,
you must take corrective action by repairing or replacing the natural
gas-driven intermittent vent process controller within 5 calendar days
of the date the emissions to the atmosphere were detected. After the
repair or replacement of a natural gas-driven intermittent vent process
controller, you must re-survey the natural gas-driven intermittent vent
process controller within five days to verify that it is not venting
emissions during idle periods.
(3) You must reduce methane emissions from all controllers in the
process controller designated facility by 95.0 percent. You must route
emissions through a closed vent system to a control device through a
closed vent system that meets the conditions specified in Sec.
60.5412c.
(c) If you route process controller emissions to a process or a
control device, you must route the process controller designated
facility emissions through a closed vent system that meets the
requirements of Sec. 60.5411c(a) and (c).
(d) You must demonstrate initial compliance with standards that
apply to process controller designated facilities as required by Sec.
60.5410c(e).
(e) You must demonstrate continuous compliance with standards that
apply to process controller designated facilities as required by Sec.
60.5415c(g).
(f) You must perform the reporting as required by Sec.
60.5420c(b)(1), (6) and (10) through (12), as applicable, and the
recordkeeping as required by Sec. 60.5420c(c)(5), (7), and (9) through
(12), as applicable.
Sec. 60.5395c What GHG standards apply to pump designated
facilities?
Each pump designated facility, you must comply with the GHG
standards in this section.
(a) For each pump designated facility meeting the criteria
specified in paragraphs (a)(1) or (2) of this section, you must design
and operate the pump designated facility with zero methane emissions to
the atmosphere. If you comply by routing the pump designated facility
emissions to a process, the emissions must be routed to the process
through a closed vent system.
(1) The pump designated facility is located at a site that has
access to electrical power.
(2) The pump designated facility is located at a site that does not
have access to electrical power and also has three or more natural gas-
driven diaphragm pumps.
(b)(1) For each pump designated facility located at a site that
does not have access to electrical power and that also has fewer than
three natural gas-driven diaphragm pumps, you must comply with
paragraph (b)(2) or (3) of this section, except as provided in
paragraphs (b)(4) through (8) of this section.
(2) Emissions from the pump designated facility must be routed
through a closed vent system to a process if a vapor recovery unit is
onsite.
(3) If a vapor recovery unit is not onsite, you must reduce methane
emissions from the pump designated facility by 95.0 percent. You must
route designated pump facility emissions through a closed vent system
to a control device meeting the conditions specified in Sec. 60.5412c.
(4) You are not required to install an emissions control device or
a vapor recovery unit, if such a unit is necessary to enable emissions
to be routed to a process, solely for the purpose of complying with the
requirements of paragraphs (b)(2) or (3) of this section. If no control
device capable of achieving a 95.0 percent emissions reduction and no
vapor recovery unit is present on site, you must comply with paragraph
(b)(5) or (6) of this section, as applicable. For the purposes of this
section, boilers and process heaters are not considered to be control
devices.
(5) If an emissions control device is on site but is unable to
achieve a 95.0 percent emissions reduction, you must route the pump
designated facility emissions through a closed vent system to that
control device. You must certify that there is no vapor recovery unit
on site and that there is no control device capable of achieving a 95.0
percent emissions reduction on site.
(6) If there is no vapor recovery unit on site and no emission
control device is on site, you must certify that there is no vapor
recovery unit or emissions control device on site. If you subsequently
install a control device or vapor recovery unit, you must meet the
requirements of paragraphs (b)(6)(i) and (ii) of this section.
(i) You must be in compliance with the requirements of paragraphs
(b)(1) through (3) of this section, as applicable, within 30 days of
startup of the control device or vapor recovery unit.
(ii) You must maintain the records in Sec. 60.5420c(c)(14)(ii) and
(v), as applicable. You are no longer required to maintain the records
in Sec. 60.5420c(c)(14)(vi).
(7) If an owner or operator complying with paragraph (b)(1) of this
section determines, through an engineering assessment, that routing the
pump designated facility emissions to a control device or to a process
is technically infeasible, the requirements specified in paragraphs
(b)(7)(i) through (iii) of this section must be met.
(i) The owner or operator must conduct the assessment of technical
infeasibility in accordance with the criteria in paragraph (b)(7)(ii)
of this section and have it certified by either a qualified
professional engineer or an in-house engineer with expertise on the
design and operation of the pump designated facility and the control
device or processes at the site in accordance with paragraph
(b)(7)(iii) of this section.
(ii) The assessment of technical infeasibility to route emissions
from the pump designated facility to an existing control device or
process must include, but is not limited to, safety considerations,
distance from the control device or process, pressure losses and
differentials in the closed vent system, and the ability of the control
device or process to handle the pump designated facility emissions
which are routed to them. The assessment of technical infeasibility
must be prepared under the direction or supervision of the qualified
professional engineer or in-house engineer who signs the certification
in accordance with paragraph (b)(7)(iii) of this section.
(iii) The following certification, signed and dated by the
qualified professional engineer or in-house engineer, must state: ``I
certify that the assessment of technical infeasibility was prepared
under my direction or supervision. I further certify that the
assessment was conducted and this report was prepared pursuant to the
[[Page 17153]]
requirements of Sec. 60.5395c(b)(5)(ii). Based on my professional
knowledge and experience, and inquiry of personnel involved in the
assessment, the certification submitted herein is true, accurate, and
complete.''
(8) If the pump designated facility emissions are routed to a
control device or process and the control device or process is
subsequently removed from the location or is no longer available such
that there is no option to route to a control device or process, you
are no longer required to be in compliance with the requirements of
paragraph (b)(2) or (3) of this section, and instead must comply with
paragraph (b)(6) of this section.
(c) If you use a control device or route to a process to reduce
emissions, you must route the pump designated facility emissions
through a closed vent system that meets the requirements of Sec.
60.5411c(a) and (c).
(d) You must demonstrate initial compliance with standards that
apply to pump designated facilities as required by Sec. 60.5410c(f).
(e) You must demonstrate continuous compliance with the standards
that apply to pump designated facilities as required by Sec.
60.5415c(d).
(f) You must perform the reporting as required by Sec.
60.5420c(b)(1), (9), and (b)(10) through (12), as applicable, and the
recordkeeping as required by Sec. 60.5420c(c)(7), (c)(9) through (12),
and (14), as applicable.
Sec. 60.5396c What GHG standards apply to storage vessel designated
facilities?
Each storage vessel designated facility must comply with the GHG
standards in this section, except as provided in paragraph (e) of this
section.
(a) General requirements. You must comply with the requirements of
paragraphs (a)(1) and (2) of this section. After 12 consecutive months
of compliance with paragraph (a)(2) of this section, you may continue
to comply with paragraph (a)(2) of this section, or you may comply with
paragraph (a)(3) of this section, if applicable. If you choose to meet
the requirements of paragraph (a)(3) of this section, you are not
required to comply with the requirements of paragraph (a)(2) of this
section except as provided in paragraphs (a)(3)(i) and (ii) of this
section.
(1) Determine the potential for methane emissions in accordance
with Sec. 60.5386c(e)(2).
(2) Reduce methane emissions by 95.0 percent.
(3) Maintain the uncontrolled actual methane emissions from the
storage vessel designated facility at less than 14 tpy without
considering control in accordance with paragraphs (a)(3)(i) through
(iii) of this section. Prior to using the uncontrolled actual methane
emission rates for compliance purposes, you must demonstrate that the
uncontrolled actual methane emissions have remained less than 14 tpy as
determined monthly for 12 consecutive months. After such demonstration,
you must determine the uncontrolled actual rolling 12-month
determination methane emissions rates each month. The uncontrolled
actual methane emissions must be calculated using a generally accepted
model or calculation methodology which account for flashing, working,
and breathing losses, and the calculations must be based on the actual
average throughput, temperature, and separator pressure for the month.
You may no longer comply with this paragraph and must instead comply
with paragraph (a)(2) of this section if your storage vessel designated
facility meets the conditions specified in paragraphs (a)(3)(i) or (ii)
of this section.
(i) If a well feeding the storage vessel designated facility
undergoes fracturing or refracturing, you must comply with paragraph
(a)(2) of this section as soon as liquids from the well following
fracturing or refracturing are routed to the storage vessel designated
facility.
(ii) If the rolling 12-month emissions determination required in
this section indicates that methane emissions increase to 14 tpy or
greater from your storage vessel designated facility and the increase
is not associated with fracturing or refracturing of a well feeding the
storage vessel designated facility, you must comply with paragraph
(a)(2) of this section within 30 days of the monthly determination.
(b) Control requirements. (1) Except as required in paragraph
(b)(2) of this section, if you use a control device to reduce methane
emissions from your storage vessel designated facility, you must meet
all of the design and operational criteria specified in paragraphs
(b)(1)(i) through (iv) of this section.
(i) Each storage vessel in the tank battery must be equipped with a
cover that meets the requirements of Sec. 60.5411c(b);
(ii) The storage vessels must be manifolded together with piping
such that all vapors are shared among the headspaces of the storage
vessels in the tank battery;
(iii) The tank battery must be equipped with one or more closed
vent system that meets the requirements of Sec. 60.5411c(a) and (c);
and
(iv) The vapors collected in paragraphs (b)(1)(ii) and (iii) of
this section must be routed to a control device that meets the
conditions specified in Sec. 60.5412c. As an alternative to routing
the closed vent system to a control device, you may route the closed
vent system to a process.
(2) For storage vessel designated facilities that do not have
flashing emissions and that are not located at well sites or
centralized production facilities, you may use a floating roof to
reduce emissions. If you use a floating roof to reduce emissions, you
must meet the requirements of Sec. 60.112b(a)(1) or (2) and the
relevant monitoring, inspection, recordkeeping, and reporting
requirements in subpart Kb of this part. You must submit a statement
that you are complying with Sec. 60.112b(a)(1) or (2) with the initial
annual report specified in Sec. 60.5420c(b)(1) and (7).
(c) Requirements for storage vessel designated facilities that are
removed from service or returned to service. If you remove a storage
vessel designated facility from service or remove a portion of a
storage vessel designated facility from service, you must comply with
the applicable paragraphs (c)(1) through (4) of this section. A storage
vessel is not a designated facility under this subpart for the period
that it is removed from service.
(1) For a storage vessel designated facility to be removed from
service, you must comply with the requirements of paragraphs (c)(1)(i)
and (ii) of this section.
(i) You must completely empty and degas each storage vessel, such
that each storage vessel no longer contains crude oil, condensate,
produced water or intermediate hydrocarbon liquids. A storage vessel
where liquid is left on walls, as bottom clingage or in pools due to
floor irregularity is considered to be completely empty.
(ii) You must submit a notification as required in Sec.
60.5420c(b)(7)(viii) in your next annual report, identifying each
storage vessel designated facility removed from service during the
reporting period and the date of its removal from service.
(2) For a portion of a storage vessel designated facility to be
removed from service, you must comply with the requirements of
paragraphs (c)(2)(i) through (iv) of this section.
(i) You must completely empty and degas the storage vessel(s), such
that the storage vessel(s) no longer contains crude oil, condensate,
produced water or intermediate hydrocarbon liquids. A storage vessel
where liquid is left on walls, as bottom clingage or in pools
[[Page 17154]]
due to floor irregularity is considered to be completely empty.
(ii) You must disconnect the storage vessel(s) from the tank
battery by isolating the storage vessel(s) from the tank battery such
that the storage vessel(s) is no longer manifolded to the tank battery
by liquid or vapor transfer.
(iii) You must submit a notification as required in Sec.
60.5420c(b)(7)(viii) in your next annual report, identifying each
storage vessel removed from service during the reporting period, the
impacted storage vessel designated facility, and the date of its
removal from service.
(iv) The remaining storage vessel(s) in the tank battery remain a
storage vessel designated facility and must continue to comply with the
applicable requirements of paragraphs (a) and (b) of this section.
(3) If a storage vessel identified in paragraph (c)(1)(ii) or
(c)(2)(iii) of this section is returned to service, you must determine
its designated facility status as provided in Sec. 60.5386c(e)(5).
(4) For each storage vessel designated facility or portion of a
storage vessel designated facility returned to service during the
reporting period, you must submit a notification in your next annual
report as required in Sec. 60.5420c(b)(7)(ix), identifying each
storage vessel designated facility or portion of a storage vessel
designated facility and the date of its return to service.
(d) Compliance, notification, recordkeeping, and reporting. You
must comply with paragraphs (d)(1) through (3) of this section.
(1) You must demonstrate initial compliance with standards as
required by Sec. 60.5410c(h).
(2) You must demonstrate continuous compliance with standards as
required by Sec. 60.5415c(h).
(3) You must perform the required reporting as required by Sec.
60.5420c(b)(1) and (7) and (b)(10) through (12), as applicable and the
recordkeeping as required by Sec. 60.5420c(c)(6) and (c)(7) through
(12), as applicable.
(e) Exemptions. This subpart does not apply to storage vessels
subject to and controlled in accordance with the requirements for
storage vessels in subpart Kb of this part, and 40 CFR part 63,
subparts G, CC, HH, or WW.
Sec. 60.5397c What GHG standards apply to fugitive emissions
components designated facilities?
This section applies to fugitive emissions components designated
facilities. You must comply with the requirements of paragraphs (a)
through (l) of this section to reduce fugitive emissions of methane.
The requirements of this section are independent of the cover and
closed vent system requirements of Sec. 60.5411c.
(a) General requirements. You must monitor all fugitive emissions
components in accordance with paragraphs (b) through (g) of this
section. You must repair all sources of fugitive emissions in
accordance with paragraph (h) of this section. You must demonstrate
initial compliance in accordance with paragraph (i) of this section.
You must keep records in accordance with paragraph (j) of this section
and report in accordance with paragraph (k) of this section. You must
meet the requirements for well closures in accordance with paragraph
(l) of this section.
(b) Develop fugitive emissions monitoring plan. You must develop a
fugitive emissions monitoring plan that covers all fugitive emissions
components designated facilities within each company-defined area in
accordance with paragraphs (c) and (d) of this section.
(c) Fugitive emissions monitoring plan. Your fugitive emissions
monitoring plan must include the elements specified in paragraphs
(c)(1) through (8) of this section, at a minimum.
(1) Frequency for conducting surveys. Surveys must be conducted at
least as frequently as required by paragraphs (f) and (g) of this
section.
(2) Technique for determining fugitive emissions (i.e., AVO or
other detection methods, Method 21 of appendix A-7 to this part; and/or
OGI and meeting the requirements of paragraphs (c)(7)(i) through (vii)
of this section).
(3) Manufacturer and model number of fugitive emissions detection
equipment to be used, if applicable.
(4) Procedures and timeframes for identifying and repairing
fugitive emissions components from which fugitive emissions are
detected, including timeframes for fugitive emission components that
are unsafe to repair. Your repair schedule must meet the requirements
of paragraph (h) of this section at a minimum.
(5) Procedures and timeframes for verifying fugitive emission
component repairs.
(6) Records that will be kept and the length of time records will
be kept.
(7) If you are using OGI, your plan must also include the elements
specified in paragraphs (c)(7)(i) through (vii) of this section.
(i) Verification that your OGI equipment meets the specifications
of paragraphs (c)(7)(i)(A) and (B) of this section. This verification
is an initial verification, and may either be performed by the
facility, by the manufacturer, or by a third party. For the purposes of
complying with the fugitive emissions monitoring program with OGI,
fugitive emissions are defined as any visible emissions observed using
OGI.
(A) Your OGI equipment must be capable of imaging gases in the
spectral range for the compound of highest concentration in the
potential fugitive emissions.
(B) Your OGI equipment must be capable of imaging a gas that is
half methane, half propane at a concentration of 10,000 ppm at a flow
rate of <=60 g/hr from a quarter inch diameter orifice.
(ii) Procedure for a daily verification check.
(iii) Procedure for determining the operator's maximum viewing
distance from the equipment and how the operator will ensure that this
distance is maintained.
(iv) Procedure for determining maximum wind speed during which
monitoring can be performed and how the operator will ensure monitoring
occurs only at wind speeds below this threshold.
(v) Procedures for conducting surveys, including the items
specified in paragraphs (c)(7)(v)(A) through (C) of this section.
(A) How the operator will ensure an adequate thermal background is
present in order to view potential fugitive emissions.
(B) How the operator will deal with adverse monitoring conditions,
such as wind.
(C) How the operator will deal with interferences (e.g., steam).
(vi) Training and experience needed prior to performing surveys.
(vii) Procedures for calibration and maintenance. At a minimum,
procedures must comply with those recommended by the manufacturer.
(8) If you are using Method 21 of appendix A-7 to this part, your
plan must also include the elements specified in paragraphs (c)(8)(i)
through (iv) of this section. For the purposes of complying with the
fugitive emissions monitoring program using Method 21 of appendix A-7
to this part, a fugitive emission is defined as an instrument reading
of 500 ppmv or greater.
(i) Verification that your monitoring equipment meets the
requirements specified in Section 6.0 of Method 21 of appendix A-7 to
this part. For purposes of instrument capability, the fugitive
emissions definition shall be 500 ppmv or greater methane using a FID-
based instrument. If you wish to use an
[[Page 17155]]
analyzer other than a FID-based instrument, you must develop a site-
specific fugitive emission definition that would be equivalent to 500
ppmv methane using a FID-based instrument (e.g., 10.6 eV PID with a
specified isobutylene concentration as the fugitive emission definition
would provide equivalent response to your compound of interest).
(ii) Procedures for conducting surveys. At a minimum, the
procedures shall ensure that the surveys comply with the relevant
sections of Method 21 of appendix A-7 to this part, including Section
8.3.1.
(iii) Procedures for calibration. The instrument must be calibrated
before use each day of its use by the procedures specified in Method 21
of appendix A-7 to this part. At a minimum, you must also conduct
precision tests at the interval specified in Method 21 of appendix A-7
to this part, Section 8.1.2, and a calibration drift assessment at the
end of each monitoring day. The calibration drift assessment must be
conducted as specified in paragraph (c)(8)(iii)(A) of this section.
Corrective action for drift assessments is specified in paragraphs
(c)(8)(iii)(B) and (C) of this section.
(A) Check the instrument using the same calibration gas that was
used to calibrate the instrument before use. Follow the procedures
specified in Method 21 of appendix A-7 to this part, Section 10.1,
except do not adjust the meter readout to correspond to the calibration
gas value. If multiple scales are used, record the instrument reading
for each scale used. Divide the arithmetic difference of the initial
and post-test calibration response by the corresponding calibration gas
value for each scale and multiply by 100 to express the calibration
drift as a percentage.
(B) If a calibration drift assessment shows a negative drift of
more than 10 percent, then all equipment with instrument readings
between the fugitive emission definition multiplied by (100 minus the
percent of negative drift) divided by 100 and the fugitive emission
definition that was monitored since the last calibration must be re-
monitored.
(C) If any calibration drift assessment shows a positive drift of
more than 10 percent from the initial calibration value, then, at the
owner/operator's discretion, all equipment with instrument readings
above the fugitive emission definition and below the fugitive emission
definition multiplied by (100 plus the percent of positive drift)
divided by 100 monitored since the last calibration may be re-
monitored.
(iv) Procedures for monitoring yard piping (other than buried yard
piping). At a minimum, place the probe inlet at the surface of the yard
piping and run the probe down the length of the piping. Connection
points on the piping must be monitored following the procedures
specified in Method 21 of appendix A-7 to this part.
(d) Additional elements of fugitive emissions monitoring plan. Each
fugitive emissions monitoring plan must include the elements specified
in paragraphs (d)(1) and (2) of this section, at a minimum, as
applicable.
(1) If you are using OGI, your plan must include procedures to
ensure that all fugitive emissions components, except buried yard
piping and associated components (e.g., connectors), are monitored
during each survey. Example procedures include, but are not limited to,
a sitemap with an observation path, a written narrative of where the
fugitive emissions components are located and how they will be
monitored, or an inventory of fugitive emissions components.
(2) If you are using Method 21 of appendix A-7 to this part, your
plan must include a list of fugitive emissions components to be
monitored and method for determining the location of fugitive emissions
components to be monitored in the field (e.g., tagging, identification
on a process and instrumentation diagram, etc.). Your fugitive
emissions monitoring plan must include the written plan developed for
all of the fugitive emissions components designated as difficult-to-
monitor in accordance with paragraph (g)(2) of this section, and the
written plan for fugitive emissions components designated as unsafe-to-
monitor in accordance with paragraph (g)(3) of this section.
(e) Monitoring of fugitive emissions components. Each fugitive
emissions component, except buried yard piping and associated
components (e.g., connectors), shall be observed or monitored for
fugitive emissions during each monitoring survey.
(f) Initial monitoring survey. You must conduct initial monitoring
surveys according to the requirements specified in paragraphs (f)(1)
through (3) of this section.
(1) At single wellhead only sites and small sites, you must conduct
an initial monitoring survey using audible, visual, and olfactory
(AVO), or any other detection methods (e.g., OGI), within 90 days of
the startup of production, for each fugitive emissions components
designated facility or by 90 days after the state plan submittal
deadline (as specified in Sec. 60.5362c(c)), whichever date is later.
(2) For multi-wellhead only well sites, well sites or centralized
production facilities that contain the major production and processing
equipment specified in paragraphs (g)(1)(iv)(A), (B), (C), or (D) of
this section, and compressor station sites, you must conduct an initial
monitoring survey using OGI or Method 21 to appendix A-7 to this part
within 90 days of the effective date of your state or Tribal plan, for
each fugitive emissions components designated facility, or by 36 months
after the state plan submittal deadline (as specified in Sec.
60.5362c(c)), whichever date is later.
(3) Notwithstanding the deadlines, specified in paragraphs (f)(1)
through (3) of this section for each fugitive emissions components
designated facility located on the Alaskan North Slope, that would be
subject to monitoring between September and March, you must conduct an
initial monitoring survey within 6 months, or by the following June 30,
whichever date is latest.
(g) Monitoring frequency. A monitoring survey of each fugitive
emissions components designated facility must be performed as specified
in paragraph (g)(1) of this section, with the exceptions noted in
paragraphs (g)(2) through (4) of this section. Monitoring for fugitive
emissions components designated facilities located at well sites and
centralized production facilities that have wells located onsite must
continue at the specified frequencies in paragraphs (g)(1)(i), (ii),
(iii), (iv) and (vi) of this section until the well closure
requirements of paragraph (l) of this section are completed.
(1) A monitoring survey of the fugitive emissions components
designated facilities must be conducted using the methods and at the
frequencies specified in paragraphs (g)(1)(i) through (vi) of this
section.
(i) A monitoring survey of the fugitive emissions component
designated facilities located at single wellhead only well sites must
be conducted at least quarterly using AVO, or any other detection
method after the initial survey, except as specified in paragraph
(g)(1)(vi) of this section. Any indications of fugitive emissions using
these methods are considered fugitive emissions that must be repaired
in accordance with paragraph (h) of this section.
(ii) A monitoring survey of the fugitive emissions component
designated facilities located at small well sites must be conducted at
least quarterly using AVO, or any other detection method, after the
initial survey except as specified in paragraph
[[Page 17156]]
(g)(1)(vi) of this section. Any indications of fugitive emissions using
these methods are considered fugitive emissions that must be repaired
in accordance with paragraph (h) of this section. At small well sites
with an uncontrolled storage vessel, a visual inspection of all thief
hatches and other openings on the storage vessel that are fugitive
emissions components must be conducted in conjunction with the
monitoring survey to ensure that they are kept closed and sealed at all
times except during times of adding or removing material, inspecting or
sampling material, or during required maintenance operations. If
evidence of a deviation from this requirement is found, you must take
corrective action. At small well sites with a separator, a visual
inspection of all separator dump valves to ensure the dump valve is
free of debris and not stuck in an open position must be conducted in
conjunction with the monitoring survey. Any dump valve not operating as
designed must be repaired.
(iii) A monitoring survey of the fugitive emissions components
designated facilities located at multi-wellhead only well sites must be
conducted in accordance with paragraphs (g)(1)(iii)(A) and (B) of this
section, except as specified in paragraph (g)(1)(vi) of this section.
(A) A monitoring survey must be conducted at least quarterly using
AVO, or any other detection method after the initial survey. Any
indications of fugitive emissions using these methods are considered
fugitive emissions that must be repaired in accordance with paragraph
(h) of this section.
(B) A monitoring survey must be conducted at least semiannually
using OGI or Method 21 of appendix A-7 to this part after the initial
survey. Consecutive semiannual surveys must be conducted at least 4
months apart and no more than 7 months apart.
(iv) A monitoring survey of the fugitive emissions components
designated facilities located at well sites or centralized production
facilities that contain the major production and processing equipment
specified in paragraphs (g)(1)(iv)(A), (B), (C), or (D) of this section
must be conducted at the frequencies in paragraphs (g)(1)(iv)(E) and
(F) of this section, except as specified in paragraph (g)(1)(vi) of
this section.
(A) One or more controlled storage vessels or tank batteries.
(B) One or more control devices.
(C) One or more natural gas-driven process controllers or pumps.
(D) Two or more pieces of major production and processing equipment
not specified in paragraphs (g)(1)(iv)(A) through (C) of this section.
(E) A monitoring survey must be conducted at least bimonthly using
AVO, or any other detection method after the initial survey. Any
indications of fugitive emissions using these methods are considered
fugitive emissions that must be repaired in accordance with paragraph
(h) of this section. A visual inspection of all thief hatches and other
openings on storage vessels (or tank batteries) that are fugitive
emissions components must be conducted in conjunction with the
monitoring survey to ensure that they are kept closed and sealed at all
times except during times of adding or removing material, inspecting or
sampling material, or during required maintenance operations. If
evidence of a deviation from this requirement is found, you must take
corrective action. A visual inspection must be conducted of all
separator dump valves to ensure the dump valve is free of debris and
not stuck in an open position must be conducted in conjunction with the
monitoring survey. Any dump valve not operating as designed must be
repaired.
(F) A monitoring survey must be conducted at least quarterly using
OGI or Method 21 of appendix A-7 to this part after the initial survey.
Consecutive quarterly monitoring surveys must be conducted at least 60
calendar days apart.
(v) A monitoring survey of the fugitive emissions components
designated facility located at a compressor station must be conducted
at the frequencies in paragraphs (g)(1)(v)(A) and (B) of this section,
except as specified in paragraph (g)(1)(vi) of this section.
(A) A monitoring survey must be conducted at least monthly using
AVO, or any other detection method after the initial survey. Any
indications of fugitive emissions using these methods are considered
fugitive emissions that must be repaired in accordance with paragraph
(h) of this section.
(B) A monitoring survey must be conducted at least quarterly using
OGI or Method 21 of appendix A-7 to this part after the initial survey.
Consecutive quarterly monitoring surveys must be conducted at least 60
calendar days apart.
(vi) A monitoring survey of the fugitive emissions components
designated facility located on the Alaska North Slope must be conducted
using OGI of this part or Method 21 to appendix A-7 to this part at
least annually. Consecutive annual monitoring surveys must be conducted
at least 9 months apart and no more than 13 months apart.
(2) If you are using Method 21 of appendix A-7 to this part,
fugitive emissions components that cannot be monitored without
elevating the monitoring personnel more than 2 meters above the surface
may be designated as difficult-to-monitor. Fugitive emissions
components that are designated difficult-to-monitor must meet the
specifications of paragraphs (g)(2)(i) through (iv) of this section.
(i) A written plan must be developed for all the fugitive emissions
components designated difficult-to-monitor. This written plan must be
incorporated into the fugitive emissions monitoring plan required by
paragraphs (b), (c), and (d) of this section.
(ii) The plan must include the identification and location of each
fugitive emissions component designated as difficult-to-monitor.
(iii) The plan must include an explanation of why each fugitive
emissions component designated as difficult-to-monitor is difficult-to-
monitor.
(iv) The plan must include a schedule for monitoring the difficult-
to-monitor fugitive emissions components at least once per calendar
year.
(3) If you are using Method 21 of appendix A-7 to this part,
fugitive emissions components that cannot be monitored because
monitoring personnel would be exposed to immediate danger while
conducting a monitoring survey may be designated as unsafe-to-monitor.
Fugitive emissions components that are designated unsafe-to-monitor
must meet the specifications of paragraphs (g)(3)(i) through (iv) of
this section.
(i) A written plan must be developed for all the fugitive emissions
components designated unsafe-to-monitor. This written plan must be
incorporated into the fugitive emissions monitoring plan required by
paragraphs (b), (c), and (d) of this section.
(ii) The plan must include the identification and location of each
fugitive emissions component designated as unsafe-to-monitor.
(iii) The plan must include an explanation of why each fugitive
emissions component designated as unsafe-to-monitor is unsafe-to-
monitor.
(iv) The plan must include a schedule for monitoring the fugitive
emissions components designated as unsafe-to-monitor.
(4) The requirements of paragraphs (g)(1)(iv)(F) and (g)(1)(v)(B)
of this section are waived during a quarterly monitoring period for any
fugitive emissions components designated facility located within an
area that has an average calendar month temperature
[[Page 17157]]
below 0 degrees Fahrenheit for two of three consecutive calendar months
of a quarterly monitoring period. The calendar month temperature
average for each month within the quarterly monitoring period must be
determined using historical monthly average temperatures over the
previous three years as reported by a National Oceanic and Atmospheric
Administration source or other source approved by the Administrator.
The requirements of paragraph (g)(1)(iv) and (v) of this section shall
not be waived for two consecutive quarterly monitoring periods.
(h) Repairs. Each identified source of fugitive emissions shall be
repaired in accordance with paragraphs (h)(1) and (2) of this section.
(1) A first attempt at repair shall be made in accordance with
paragraphs (h)(1)(i) and (ii) of this section.
(i) A first attempt at repair shall be made no later than 15
calendar days after detection of fugitive emissions that were
identified using AVO.
(ii) If you are complying with paragraph (g)(1)(i) through (vi) of
this section using OGI or Method 21 of appendix A-7 to this part, a
first attempt at repair shall be made no later than 30 calendar days
after detection of the fugitive emissions.
(2) Repair shall be completed as soon as practicable, but no later
than 15 calendar days after the first attempt at repair as required in
paragraph (h)(1)(i) of this section, and 30 calendar days after the
first attempt at repair as required in paragraph (h)(1)(ii) of this
section.
(3) Delay of repair will be allowed if the conditions in paragraphs
(h)(3)(i) or (ii) of this section are met.
(i) If the repair is technically infeasible, would require a vent
blowdown, a compressor station shutdown, a well shutdown or well shut-
in, or would be unsafe to repair during operation of the unit, the
repair must be completed during the next scheduled compressor station
shutdown for maintenance, scheduled well shutdown, scheduled well shut-
in, after a scheduled vent blowdown, or within 2 years of detecting the
fugitive emissions, whichever is earliest. A vent blowdown is the
opening of one or more blowdown valves to depressurize major production
and processing equipment, other than a storage vessel.
(ii) If the repair requires replacement of a fugitive emissions
component or a part thereof, but the replacement cannot be acquired and
installed within the repair timelines specified in paragraphs (h)(1)
and (2) of this section due to either of the conditions specified in
paragraphs (h)(3)(ii)(A) or (B) of this section, the repair must be
completed in accordance with paragraph (h)(3)(ii)(C) of this section
and documented in accordance with Sec. 60.5420c(c)(13)(v)(I).
(A) Valve assembly supplies had been sufficiently stocked but are
depleted at the time of the required repair.
(B) A replacement fugitive emissions component or a part thereof
requires custom fabrication.
(C) The required replacement must be ordered no later than 10
calendar days after the first attempt at repair. The repair must be
completed as soon as practicable, but no later than 30 calendar days
after receipt of the replacement component, unless the repair requires
a compressor station or well shutdown. If the repair requires a
compressor station or well shutdown, the repair must be completed in
accordance with the timeframe specified in paragraph (h)(3)(i) of this
section.
(4) Each identified source of fugitive emissions must be resurveyed
to complete repair according to the requirements of paragraphs
(h)(4)(i) through (v) of this section, to ensure that there are no
fugitive emissions.
(i) The operator may resurvey the fugitive emissions components to
verify repair using either Method 21 of appendix A-7 to this part or
OGI, except as specified in paragraph (h)(4)(v) of this section.
(ii) For each repair that cannot be made during the monitoring
survey when the fugitive emissions are initially found, a digital
photograph must be taken of that component, or the component must be
tagged during the monitoring survey when the fugitive emissions were
initially found for identification purposes and subsequent repair. The
digital photograph must include the date that the photograph was taken
and must clearly identify the component by location within the site
(e.g., the latitude and longitude of the component or by other
descriptive landmarks visible in the picture).
(iii) Operators that use Method 21 of appendix A-7 to this part to
resurvey the repaired fugitive emissions components are subject to the
resurvey provisions specified in paragraphs (h)(4)(iii)(A) and (B) of
this section.
(A) A fugitive emissions component is repaired when the Method 21
instrument indicates a concentration of less than 500 ppmv above
background or when no soap bubbles are observed when the alternative
screening procedures specified in section 8.3.3 of Method 21 of
appendix A-7 to this part are used.
(B) Operators must use the Method 21 monitoring requirements
specified in paragraph (c)(8)(ii) of this section or the alternative
screening procedures specified in section 8.3.3 of Method 21 of
appendix A-7 to this part.
(iv) Operators that use OGI to resurvey the repaired fugitive
emissions components are subject to the resurvey provisions specified
in paragraphs (h)(4)(iv)(A) and (B) of this section.
(A) A fugitive emissions component is repaired when the OGI
instrument shows no indication of visible emissions.
(B) Operators must use the OGI monitoring requirements specified in
paragraph (c)(7) of this section.
(v) For fugitive emissions identified using AVO detection methods,
the operator may resurvey using those same methods, Method 21 of
appendix A-7 to this part, or OGI. For operators that use AVO detection
methods, a fugitive emissions component is repaired when there are no
indications of fugitive emissions using these methods.
(i) Initial compliance. You must demonstrate initial compliance
with the standards that apply to fugitive emissions components
designated facilities as required by Sec. 60.5410c(i).
(j) Continuous compliance. You must demonstrate continuous
compliance with the standards that apply to fugitive emissions
components designated facilities as required by Sec. 60.5415c(j).
(k) Reporting and recordkeeping. You must comply with the reporting
requirements as specified in Sec. 60.5420c(b)(1) and (8), and the
recordkeeping requirements as specified in Sec. 60.5420c(c)(13).
(l) Well closure requirements. You must complete the requirements
specified in paragraphs (l)(1) through (4) of this section.
(1) You must submit a well closure plan to the Administrator within
30 days of the cessation of production from all wells located at the
well site as specified in Sec. 60.5420c(a)(4)(i). The well closure
plan must include, at a minimum, the information specified in
paragraphs (l)(1)(i) through (iii) of this section.
(i) Description of the steps necessary to close all wells at the
well site, including permanent plugging of all wells;
(ii) Description of the financial requirements and disclosure of
financial assurance to complete closure; and
(iii) Description of the schedule for completing all activities in
the well closure plan.
(2) You must submit a notification as specified in Sec.
60.5420c(a)(4)(ii) of intent to close the well site to the
Administrator 60 days before you begin well closure activities.
[[Page 17158]]
(3) You must conduct a survey of the well site using OGI, including
each closed well, after completing all well closure activities outlined
in the well closure plan specified in paragraph (l)(1) of this section.
If any emissions are imaged by the OGI instrument, then you must take
steps to eliminate those emissions and you must resurvey the source of
emissions. You must repeat steps to eliminate emissions and resurvey
the source of emissions until no emissions are imaged by the OGI
instrument. You must update the well closure plan specified in
paragraph (l)(1) of this section to include the video of the OGI survey
demonstrating closure of all wells at the site.
(4) You must maintain the records specified in Sec.
60.5420c(c)(13) and submit the reports specified in Sec.
60.5420c(b)(8).
Sec. 60.5398c What alternative GHG standards apply to fugitive
emissions components designated facilities and what inspection and
monitoring requirements apply to covers and closed vent systems when
using an alternative technology?
This section provides alternative GHG standards for fugitive
emissions components designated facilities in Sec. 60.5397c and
alternative continuous inspection and monitoring requirements for
covers and closed vent systems in Sec. 60.5416c(a)(1)(ii) and (iii),
(2)(ii) through (iv), and (3)(iii) and (iv). If you choose to use an
alternative standard under this section, you must submit the
notification under paragraph (a) of this section. If you choose to
demonstrate compliance with the alternative GHG standards through
periodic screening, you are subject to the requirements in paragraph
(b) of this section. If you choose to demonstrate compliance through a
continuous monitoring system, you are subject to the requirements in
paragraph (c) of this section. The technology used for periodic
screenings under paragraph (b) of this section or continuous monitoring
under paragraph (c) of this section must be approved in accordance with
Sec. 60.5398b(d).
(a) Notification. If you choose to demonstrate compliance with the
alternative GHG standards in either paragraph (b) or (c) of this
section, you must notify the Administrator of adoption of the
alternative standards in the first annual report following
implementation of the alternative standards, as specified in Sec.
60.5424c(a). Once you have implemented the alternative standards, you
must continue to comply with the alternative standards.
(b) Periodic Screening. You may choose to demonstrate compliance
for your fugitive emissions components designated facility and
compliance with continuous inspection and monitoring requirements for
your covers and closed vent systems through periodic screenings using
any methane measurement technology approved in accordance with Sec.
60.5398b(d). If you choose to demonstrate compliance using periodic
screenings, you must comply with the requirements in paragraphs (b)(1)
through (5) of this section and comply with the recordkeeping and
reporting requirements in Sec. 60.5424c.
(1) You must use one or more alternative test method(s) approved
per Sec. 60.5398b(d) to conduct periodic screenings.
(i) The required frequencies for conducting periodic screenings are
listed in tables 2 and 3 to this subpart. You must choose the
appropriate frequency for conducting periodic screenings based on the
minimum aggregate detection threshold of the method used to conduct the
periodic screenings. You must also use tables 2 and 3 to this subpart
to determine whether you must conduct an annual fugitive emissions
survey using OGI, except as provided in paragraph (b)(1)(ii) of this
section.
(ii) Use of table 2 or 3 to this subpart is based on the required
frequency for conducting monitoring surveys in Sec. 60.5397c(g)(1)(i)
through (v).
(iii) You may replace one or more individual periodic screening
events required by table 2 or 3 to this subpart with an OGI survey. The
OGI survey must be conducted according to the requirements outlined in
Sec. 60.5397c.
(iv) If you use multiple methods to conduct periodic screenings,
you must conduct all periodic screenings, regardless of the method used
for the individual periodic screening event, at the frequency required
for the alternative test method with the highest aggregate detection
threshold (e.g., if you use methods with aggregate detection thresholds
of 15 kg/hr, your periodic screenings must be conducted monthly). You
must also conduct an annual OGI survey if an annual OGI survey is
required for the alternative test method with the highest aggregate
detection threshold.
(2) You must develop a monitoring plan that covers the collection
of fugitive emissions components, covers, and closed vent systems at
each site where you will use periodic screenings to demonstrate
compliance. You may develop a site-specific monitoring plan, or you may
include multiple sites that you own or operate in one plan. At a
minimum, the monitoring plan must contain the information specified in
paragraphs (b)(2)(i) through (ix) of this section.
(i) Identification of each site that will be monitored through
periodic screening, including latitude and longitude coordinates of the
site in decimal degrees to an accuracy and precision of five decimals
of a degree using the North American Datum of 1983.
(ii) Identification of the alternative test method(s) approved per
Sec. 60.5398b(d) that will be used for periodic screenings and the
spatial resolution (i.e., component-level, area-level, or facility-
level) of the technology used for each method.
(iii) Identification of and contact information for the entities
that will be performing the periodic screenings.
(iv) Required frequency for conducting periodic screenings, based
on the criteria outlined in paragraph (b)(1) of this section.
(v) If you are required to conduct an annual OGI survey by
paragraph (b)(1)(i) or (iii) of this section or you choose to replace
any individual screening event with an OGI survey, your monitoring plan
must also include the information required by Sec. 60.5397c(b).
(vi) Procedures for conducting monitoring surveys required by
paragraphs (b)(5)(ii)(A), (b)(5)(iii)(A), and (b)(5)(iv)(A) of this
section. At a minimum, your monitoring plan must include the
information required by Sec. 60.5397c(c)(2), (3), (7), and (8) and
Sec. 60.5397c(d), as applicable. The provisions of Sec.
60.5397c(d)(3) do not apply for purposes of conducting monitoring
surveys required by paragraphs (b)(5)(ii) through (iv) of this section.
(vii) Procedures and timeframes for identifying and repairing
fugitive emissions components, covers, and closed vent systems from
which emissions are detected.
(viii) Procedures and timeframes for verifying repairs for fugitive
emissions components, covers, and closed vent systems.
(ix) Records that will be kept and the length of time records will
be kept.
(3) You must conduct the initial screening of your site according
to the timeframes specified in (b)(3)(i) and (ii) of this section.
(i) Within 90 days of the effective date of your state or Tribal
plan for each fugitive emissions components designated facility and
storage vessel designated facility located at a well site.
(ii) No later than the final date by which the next monitoring
survey required by Sec. 60.5397c(g)(1)(i) through
[[Page 17159]]
(v) would have been required to be conducted if you were previously
complying with the requirements in Sec. 60.5397c and Sec. 60.5416c.
(4) If you are required to conduct an annual OGI survey by
paragraph (b)(1)(i) or (iii) of this section, you must conduct OGI
surveys according to the schedule in paragraphs (b)(4)(i) through (iv)
of this section.
(i) You must conduct the initial OGI survey no later than 12
calendar months after conducting the initial screening survey in
paragraph (b)(3) of this section.
(ii) Each subsequent OGI survey must be conducted no later than 12
calendar months after the previous OGI survey was conducted. Each
identified source of fugitive emissions during the OGI survey shall be
repaired in accordance with Sec. 60.5397c(h).
(iii) If you replace a periodic screening event with an OGI survey
or you are required to conduct a monitoring survey in accordance with
paragraph (b)(5)(ii)(A) of this section prior to the date that your
next OGI survey under paragraph (b)(4)(ii) of this section is due, the
OGI survey conducted in lieu of the periodic screening event or the
monitoring survey under paragraph (b)(5)(ii)(A) of this section can be
used to fulfill the requirements of paragraph (b)(4)(ii) of this
section. The next OGI survey is required to be conducted no later than
12 calendar months after the date of the survey conducted under
paragraph (b)(1)(iv) or (b)(5)(ii)(A) of this section.
(iv) You cannot use a monitoring survey conducted under paragraph
(b)(5)(iii)(A) or (b)(5)(iv)(A) of this section to fulfill the
requirements of paragraph (b)(4)(ii) of this section unless the
monitoring survey included all fugitive emission components at the
site.
(5) You must investigate confirmed detections of emissions from
periodic screening events and repair each identified source of
emissions in accordance with paragraphs (b)(5)(i) through (vi) of this
section.
(i) You must receive the results of the periodic screening no later
than 5 calendar days after the screening event occurs.
(ii) If you use an alternative test method with a facility-level
spatial resolution to conduct a periodic screening event and the
results of the periodic screening event indicate a confirmed detection
of emissions from a designated facility, you must take the actions
listed in paragraphs (b)(5)(ii)(A) through (C) of this section.
(A) You must conduct a monitoring survey of the entire fugitive
emissions components designated facility following the procedures in
your monitoring plan. During the survey, you must observe each fugitive
emissions component for fugitive emissions.
(B) You must inspect all covers and closed vent system(s) with OGI
or Method 21 of appendix A-7 to this part in accordance with the
requirements in Sec. 60.5416c(b)(1) through (4), as applicable.
(C) You must conduct a visual inspection of all covers and closed
vent systems to identify if there are any defects, as defined in Sec.
60.5416c(a)(1)(ii), Sec. 60.5416c(a)(2)(iii), or Sec.
60.5416c(a)(3)(i), as applicable.
(iii) If you use an alternative test method with an area-level
spatial resolution to conduct a periodic screening event and the
results of the periodic screening event indicate a confirmed detection
of emissions from a designated facility, you must take the actions
listed in paragraphs (b)(5)(iii)(A) and (B) of this section, as
applicable.
(A) You must conduct a monitoring survey of all your fugitive
emissions components located within a 4-meter radius of the location of
the periodic screening's confirmed detection. You must follow the
procedures in your monitoring plan when conducting the survey.
(B) If the confirmed detection occurred in the portion of a site
that contains a storage vessel or a closed vent system, you must
inspect all covers and all closed vent systems that are connected to
all storage vessels and closed vent systems that are within a 2-meter
radius of the location of the periodic screening's confirmed detection
(i.e., you must inspect the whole system that is connected to the
portion of the system in the radius of the detected event, not just the
portion of the system that falls within the radius of the detected
event).
(1) You must inspect the cover(s) and closed vent system(s) with
OGI or Method 21 of appendix A-7 to this part in accordance with the
requirements in Sec. 60.5416c(b)(1) through (4), as applicable.
(2) You must conduct a visual inspection of the closed vent
system(s) and cover(s) to identify if there are any defects, as defined
in Sec. 60.5416c(a)(1)(ii), Sec. 60.5416c(a)(2)(iii), or Sec.
60.5416c(a)(3)(i), as applicable.
(iv) If you use an alternative test method with a component-level
spatial resolution to conduct a periodic screening event and the
results of the periodic screening event indicate a confirmed detection
of emissions from a designated facility, you must take the actions
listed in paragraphs (b)(5)(iv)(A) and (B) of this section, as
applicable.
(A) You must conduct a monitoring survey of the all the fugitive
emissions components located within a 1-meter radius of the location of
the periodic screening's confirmed detection. You must follow the
procedures in your monitoring plan when conducting the survey.
(B) If the confirmed detection occurred in the portion of a site
that contains a storage vessel or a closed vent system, you must
inspect all covers and all closed vent systems that are connected to
all storage vessels and closed vent systems that are within a 0.5-meter
radius of the location of the periodic screening's confirmed detection
(i.e., you must inspect the whole system that is connected to the
portion of the system in the radius of the detected event, not just the
portion of the system that falls within the radius of the detected
event).
(1) You must inspect the cover(s) and closed vent system(s) with
OGI or Method 21 of appendix A-7 to this part in accordance with the
requirements in Sec. 60.5416c(b)(1) through (4), as applicable.
(2) You must conduct a visual inspection of the closed vent
system(s) and cover(s) to identify if there are any defects, as defined
in Sec. 60.5416c(a)(1)(ii), Sec. 60.5416c(a)(2)(iii), or Sec.
60.5416c(a)(3)(i), as applicable.
(v) You must repair all sources of fugitive emissions in accordance
with Sec. 60.5397c(h) and all emissions or defects of covers and
closed vent systems in accordance with Sec. 60.5416c(b)(4), except as
specified in this paragraph (b)(5)(v). Except as allowed by Sec. Sec.
60.5397c(h)(3) and 60.5416c(b)(5), all repairs must be completed,
including the resurvey verifying the repair, within 30 days of
receiving the results of the periodic screening in paragraph (b)(5)(i)
of this section.
(vi) If the results of the periodic screening event in paragraph
(b)(5)(i) of this section indicate a confirmed detection at a
designated facility, and the ground-based monitoring survey and
inspections required by paragraphs (b)(5)(ii) through (iv) of this
section demonstrate the confirmed detection was caused by a failure of
a control device used to demonstrate continuous compliance under this
subpart, you must initiate an investigative analysis to determine the
underlying primary and other contributing cause(s) of such failure
within 24 hours of receiving the results of the monitoring survey and/
or inspection. As part of the investigation, you must determine if the
control
[[Page 17160]]
device is operating in compliance with the applicable requirements of
Sec. Sec. 60.5415c and 60.5417c, and if not, what actions are
necessary to bring the control device into compliance with those
requirements as soon as possible and prevent future failures of the
control device from the same underlying cause(s).
(vii) If the results of the inspections required in paragraphs
(b)(5)(ii) through (iv) of this section indicate that there is an
emission or defect in your cover or closed vent system, you must
perform an investigative analysis to determine the underlying primary
and other contributing cause(s) of emissions from your cover or closed
vent system within 5 days of completing the inspection required by
paragraphs (b)(5)(ii) through (iv) of this section. The investigative
analysis must include a determination as to whether the system was
operated outside of the engineering design analysis and whether updates
are necessary for the cover or closed vent system to prevent future
emissions from the cover and closed vent system.
(6) You must maintain the records as specified in Sec.
60.5420c(c)(3) through (c)(6), (c)(13) and (c)(14), and Sec.
60.5424c(c).
(7) You must submit reports as specified in Sec. 60.5424c.
(c) Continuous Monitoring. You may choose to demonstrate compliance
for your fugitive emissions components designated facility and
compliance with continuous inspection and monitoring requirements for
your covers and closed vent systems through continuous monitoring using
a technology approved in accordance with Sec. 60.5398b(d). If you
choose to demonstrate compliance using continuous monitoring, you must
comply and develop a monitoring plan consistent with the requirements
in paragraphs (c)(1) through (9) of this section and comply with the
recordkeeping and reporting requirements in Sec. 60.5424c.
(1) For the purpose of this section, continuous monitoring means
the ability of a methane monitoring system to determine and record a
valid methane mass emissions rate or equivalent of designated
facilities at least once for every 12-hour block.
(i) The detection threshold of the system must be such that it can
detect at least 0.40 kg/hr (0.88 lb/hr) of methane.
(ii) The health of the devices used within the continuous
monitoring system must be confirmed for power and function at least
twice every six-hour block.
(iii) The continuous monitoring system must transmit all applicable
valid data at least once every 24-hours. The continuous monitoring
system must transmit all valid data collected, including health checks
required in paragraph (c)(1)(ii) of this section.
(iv) The continuous monitoring system must continuously collect
data as specified in paragraph (c)(1) of this section, except as
specified in paragraphs (c)(1)(iv)(A) through (D) of this section:
(A) The rolling 12-month average operational downtime of the
continuous monitoring system must be less than or equal to 10 percent.
(B) Operational downtime of the continuous monitoring system is
defined as a period of time for which any monitor fails to collect or
transmit data as specified in paragraph (c)(1) of this section or any
monitor is out-of-control as specified in paragraph (c)(1)(iv)(C) of
this section.
(C) A monitor is out-of-control if it fails ongoing quality
assurance checks, as specified in the alternative test method approved
under Sec. 60.5398b(d), or if the monitor output is outside of range.
The beginning of the out-of-control period is defined as the time of
the failure of the quality assurance check. The end of the out-of-
control period is defined as the time when either the monitor passes a
subsequent quality assurance check, or a new monitor is installed. The
out-of-control period for a monitor outside of range starts at the time
when the monitor first reads outside of range and ends when the monitor
reads within range again.
(D) The downtime for the continuous monitoring system must be
calculated each calendar month. Once 12 months of data are available,
at the end of each calendar month, you must calculate the 12-month
average by averaging that month with the previous 11 calendar months.
You must determine the rolling 12-month average by recalculating the
12-month average at the end of each month.
(2) You must develop a monitoring plan that covers the collection
of fugitive emissions components, covers, and closed vent systems for
each site where continuous monitoring will be used to demonstrate
compliance. At a minimum, the monitoring plan must contain the
information specified in paragraphs (c)(2)(i) through (xii) of this
section.
(i) Identification of each site to be monitored through continuous
monitoring, including latitude and longitude coordinates of the site in
decimal degrees to an accuracy and precision of at least four decimals
of a degree using the North American Datum of 1983.
(ii) Identification of the approved alternative test method(s)
approved under Sec. 60.5398b(d) used for the continuous monitoring,
including the detection principle; the manufacturer, make, and model;
instrument manual, if applicable; and the manufacturer's recommended
maintenance schedule.
(iii) If the continuous monitoring system is administered through a
third-party provider, contact information where the provider can be
reached 24 hours a day.
(iv) Number and location of monitors. If the continuous monitoring
system uses open path technology, you must identify the location of any
reflectors used. These locations should be identified by latitude and
longitude coordinates in decimal degrees to an accuracy and precision
of at least five decimals of a degree using the North American Datum of
1983.
(v) Discussion of system calibration requirements, including but
not limited to, the calibration procedures and calibration schedule for
the detection systems and meteorology systems.
(vi) Identification of critical components and infrastructure
(e.g., power, data systems) and procedures for their repairs.
(vii) Procedures for out-of-control periods.
(viii) Procedures for establishing baseline emissions, including
the identification of any sources with methane emissions not subject to
this subpart. The procedures for establishing the baseline emissions
must account for variability in the operation of the site. Operation of
the site during the development of the baseline emissions must
represent the site's expected annual production or throughput.
(ix) Procedures for determining when a fugitive emissions event is
detected by the continuous monitoring technology.
(x) Procedures and timeframes for identifying and repairing
fugitive emissions components, covers, and closed vent systems from
which emissions are detected.
(xi) Procedures and timeframes for verifying repairs for fugitive
emissions components, covers, and closed vent systems.
(xii) Records that will be kept and the length of time records will
be kept.
(3) You must install and begin conducting monitoring with your
continuous monitoring system according to the timeframes specified in
paragraphs (c)(3)(i) and (ii) of this section.
(i) Within 120 days of the effective date of your state or Tribal
plan for each fugitive emissions components
[[Page 17161]]
designated facility and storage vessel designated facility located at a
well site.
(ii) No later than the final date by which the next monitoring
survey required by Sec. 60.5397c(g)(1)(i) through (v) would have been
required to be conducted if you were previously complying with the
requirements in Sec. 60.5397c and Sec. 60.5416c.
(4) You are subject to the following action-levels as specified in
paragraphs (c)(4)(i) and (ii) of this section for any designated
facilities located at a well site, centralized production facility, or
compressor station.
(i) For designated facilities located at a wellhead only well site,
the action levels are as follows.
(A) The 90-day rolling average action-level is 1.2 kg/hr (2.6 lbs/
hr) of methane over the site-specific baseline emissions.
(B) The 7-day rolling average action level is 15 kg/hr (34 lbs/hr)
of methane over site-specific baseline emissions.
(ii) For designated facilities located at well sites with major
production and processing equipment (including small well sites),
centralized production facilities, and compressor stations, the action
levels are as follows.
(A) The 90-day rolling average action-level is 1.6 kg/hr (3.6 lbs/
hr) of methane over the site-specific baseline emissions.
(B) The rolling 7-day average action level is 21 kg/hr (46 lbs/hr)
of methane over the site-specific baseline emissions.
(5) You must establish site-specific baseline emissions upon
initial installation and activation of a continuous monitoring system.
You must establish the baseline emissions under the conditions outlined
in paragraphs (c)(5)(i) through (iii) of this section. You must
determine the baseline emission rates according to paragraphs
(c)(5)(iv) and (v) of this section. The baseline must be established
initially and any time there is a major change to the processing
equipment at a well site (including small well sites), centralized
production facility, or compressor station.
(i) Inspect all fugitive emissions components according to the
requirements in Sec. 60.5397c and covers and closed vent systems
according to the requirements in Sec. 60.5416c. This includes all
fugitive emissions components, covers, and closed vent systems,
regardless of whether they are regulated by this subpart. Repairs of
any fugitive emissions, leaks, or defects found during the inspection
must be completed prior to beginning the period in paragraph
(c)(5)(iii) of this section.
(ii) Verify control devices (e.g., flares) on all affected sources
are operating in compliance with the applicable requirements of
Sec. Sec. 60.5415c and 60.5417c. You must ensure that all control
devices are operating in compliance with the applicable regulations
prior to beginning the period in paragraph (b)(5)(iii) of this section.
Verify that all other methane emission sources (e.g., reciprocating
engines) located at the site are operating consistent with any
applicable regulations. You must ensure that these sources are
operating in compliance with the applicable regulations prior to
beginning the period in paragraph (b)(5)(iii) of this section.
(iii) Using the alternative test method approved per Sec.
60.5398b(d), record the site-level emission rate from your continuous
monitoring system for 30 operating days. You must minimize any
activities that are not normal, day-to-day activities during this 30
operating day period. Document any maintenance activities and the
period (including the start date and time and end date and time) such
activities occurred during the 30 operating day period.
(iv) Determine the site-specific baseline by calculating the mean
emission rate (kg/hr of methane) for the 30 operating day period, less
any time periods when maintenance activities were conducted.
(v) The site-specific baseline emission rate must be no more than
10 times the applicable 90-day action-level defined in paragraphs
(c)(4)(i) and (c)(4)(ii) of this section.
(6) Calculate the emission rate from your site according to
paragraphs (c)(6)(i) through (iii) of this section. Compare the
emission rate calculated in this paragraph (c)(6) to the appropriate
action levels in paragraph (c)(4) of this section to determine whether
you have exceeded an action level.
(i) Each calendar day, calculate the daily average mass emission
rate in kg/hr of methane from your continuous monitoring system.
(ii) Once the system has been operating for 7 calendar days, at the
end of each calendar day calculate the 7-day average mass emission rate
by averaging the mass emission rate from that day with the mass
emission rate from the previous 6 calendar days. Subtract the site-
specific baseline mass emission rate from the 7-day average mass
emission rate when comparing the mass emission rate to the applicable
action level. Determine the 7-day rolling average by recalculating the
7-day average each calendar day, less the site-specific baseline.
(iii) Once the system has been operating for 90 calendar days, at
the end of each calendar day calculate the 90-day average mass emission
rate by averaging the mass emission rate from that day with the mass
emission rate from the previous 89 calendar days. Subtract the site-
specific baseline emission rate from the 90-day average mass emission
rate when comparing the mass emission rate to the applicable action
level. Determine the 90-day rolling average by recalculating the 90-day
average each calendar day, less the site-specific baseline.
(7) Within 5 days of determining that either of your action levels
in paragraph (c)(4) of this section has been exceeded, you must
initiate an investigative analysis to determine the underlying primary
and contributing cause(s) of such exceedance and actions to be taken to
reduce the mass emission rate below the applicable action level.
(i) You must complete the investigative analysis and take initial
steps to bring the mass emission rate below the action level no later
than 5 days after determining there is an exceedance of the action
level in paragraph (c)(4)(i)(B) or (c)(4)(ii)(B) of this section.
(ii) You must complete the investigative analysis and take initial
steps to bring the mass emission rate below the action level no later
than 30 days after determining there is an exceedance of the action
level in paragraph (c)(4)(i)(A) or (c)(4)(ii)(A) of this section.
(8) You must develop a mass emission rate reduction plan if you
meet any of the criteria in paragraphs (c)(8)(i) through (iii) of this
section. The plan must describe the action(s) completed to date to
reduce the mass emission rate below the action level, additional
measures that you propose to employ to reduce methane emissions below
the action level, and a schedule for completion of these measures. You
must submit the plan to the Administrator within 60 days of initially
determining there is an exceedance of an action level in paragraph
(c)(4) of this section.
(i) If, upon completion of the initial actions required under
paragraph (c)(7) of this section, the average mass emission rate for
the following 30-day period is not below the applicable action level in
paragraph (c)(4)(i)(A) or (c)(4)(ii)(A) of this section. The beginning
of the 30-day period starts on the calendar day following completion of
the initial actions in paragraph (c)(7) of this section.
(ii) If, upon completion of the initial actions required under
paragraph (c)(6) of this section, the average mass emission rate for
the following 24-hour period is not below the applicable action level
in paragraph (c)(4)(i)(B) or (c)(4)(ii)(B) of this section. The average
mass emission rate will be the mass
[[Page 17162]]
emission rate calculated according to paragraph (c)(6)(i) of this
section for the calendar day following completion of the initial
corrective actions in paragraph (c)(7) of this section.
(iii) All actions needed to reduce the average mass emission rate
below the action level require more than 30 days to implement.
(9) You must maintain the records as specified in Sec.
60.5420c(c)(3) through (c)(6), (c)(13) and (c)(14), and Sec.
60.5424c(e). You must submit the reports as specified in Sec.
60.5420c(b)(1), (b)(3) through (9) and Sec. 60.5424c.
Sec. 60.5400c What GHG standards apply to process unit equipment
designated facilities?
This section applies to process unit equipment designated
facilities located at an onshore natural gas processing plant. You must
comply with the requirements of paragraphs (a) through (l) of this
section to reduce methane emissions from equipment leaks, except as
provided in Sec. 60.5402c. As an alternative to the standards in this
section, you may comply with the requirements in Sec. 60.5401c.
(a) General standards. You must comply with the requirements in
paragraphs (b) through (d) of this section for each pump in light
liquid service, pressure relief device in gas/vapor service, valve in
gas/vapor or light liquid service, and connector in gas/vapor or light
liquid service, as applicable. You must comply with the requirements in
paragraph (e) of this section for each open-ended valve or line. You
must comply with the requirements in paragraph (f) of this section for
each closed vent system and control device used to comply with
equipment leak provisions in this section. You must comply with
paragraph (g) of this section for each pump, valve, and connector in
heavy liquid service and pressure relief device in light liquid or
heavy liquid service. You must make repairs as specified in paragraph
(h) of this section. You must demonstrate initial compliance with the
standards as specified in paragraph (i) of this section. You must
demonstrate continuous compliance with the standards as specified in
paragraph (j) of this section. You must perform the reporting as
specified in paragraph (k) of this section. You must perform the
recordkeeping as required in paragraph (l) of this section.
(1) Each piece of equipment is presumed to have the potential to
emit methane unless an owner or operator demonstrates that the piece of
equipment does not have the potential to emit methane. For a piece of
equipment to be considered not to have the potential to emit methane,
the methane content of a gaseous stream must be below detection limits
using Method 18 of appendix A-6 of this part. Alternatively, if the
piece of equipment is in wet gas service, you may choose to determine
the methane content of the stream is below the detection limit of the
methods described in ASTM E168-16(R2023), E169-16(R2022), or E260-96
(all incorporated by reference, seeSec. 60.17).
(2) [Reserved]
(b) Monitoring surveys. You must monitor for leaks using OGI in
accordance with appendix K to this part, unless otherwise specified in
paragraphs (c) or (d) of this section.
(1) Monitoring surveys must be conducted bimonthly.
(2) Any emissions observed using OGI are defined as a leak.
(c) Additional requirements for pumps in light liquid service. In
addition to the requirements in paragraph (b) of this section, you must
conduct weekly visual inspections of all pumps in light liquid service
for indications of liquids dripping from the pump seal, except as
specified in paragraphs (c)(3) and (4) of this section. If there are
indications of liquids dripping from the pump seal, you must follow the
procedure specified in either paragraph (c)(1) or (2) of this section.
(1) Monitor the pump within 5 calendar days using the methods
specified in Sec. 60.5406c. A leak is detected if any emissions are
observed using OGI, or if an instrument reading of 2,000 ppmv or
greater is provided using Method 21 of appendix A-7 to this part.
(2) Designate the visual indications of liquids dripping as a leak
and repair the leak as specified in paragraph (h) of this section.
(3) If any pump is equipped with a closed vent system capable of
capturing and transporting any leakage from the seal or seals to a
process, fuel gas system, or a control device that complies with the
requirements of paragraph (f) of this section, it is exempt from the
weekly inspection requirements in paragraph (c) of this section.
(4) Any pump that is located within the boundary of an unmanned
plant site is exempt from the weekly visual inspection requirements in
paragraph (c) of this section, provided that each pump is visually
inspected as often as practicable and at least bimonthly.
(d) Additional requirements for pressure relief devices in gas/
vapor service. In addition to the requirements in paragraph (b) of this
section, you must monitor each pressure relief device as specified in
paragraphs (d)(1) of this section, except as specified in paragraphs
(d)(2) and (d)(3) of this section.
(1) You must monitor each pressure relief device within 5 calendar
days after each pressure release to detect leaks using the methods
specified in Sec. 60.5406c. A leak is detected if any emissions are
observed using OGI, or if an instrument reading of 500 ppmv or greater
is provided using Method 21 of appendix A-7 to this part.
(2) Any pressure relief device that is located in a
nonfractionating plant that is monitored only by non-plant personnel
may be monitored after a pressure release the next time the monitoring
personnel are onsite or within 30 calendar days after a pressure
release, whichever is sooner, instead of within 5 calendar days as
specified in paragraph (d)(1) of this section. No pressure relief
device described in this paragraph may be allowed to operate for more
than 30 calendar days after a pressure release without monitoring.
(3) Any pressure relief device that is routed to a process or fuel
gas system or equipped with a closed vent system capable of capturing
and transporting leakage through the pressure relief device to a
control device as described in paragraph (f) of this section is exempt
from the requirements of paragraph (d)(1) of this section.
(e) Open-ended valves or lines. Each open-ended valve or line must
be equipped with a cap, blind flange, plug, or a second valve, except
as provided in paragraphs (e)(4) and (5) of this section. The cap,
blind flange, plug, or second valve must seal the open end of the valve
or line at all times except during operations requiring process fluid
flow through the open-ended valve or line.
(1) If evidence of a leak is found at any time by AVO, or any other
detection method, a leak is detected.
(2) Each open-ended valve or line equipped with a second valve must
be operated in a manner such that the valve on the process fluid end is
closed before the second valve is closed.
(3) When a double block-and-bleed system is being used, the bleed
valve or line may remain open during operations that require venting
the line between the block valves but shall remain closed at all other
times.
(4) Open-ended valves or lines in an emergency shutdown system
which are designed to open automatically in the event of a process
upset are exempt from the requirements of this section.
(5) Open-ended valves or lines containing materials which would
autocatalytically polymerize or would
[[Page 17163]]
present an explosion, serious overpressure, or other safety hazard if
capped or equipped with a double block-and-bleed system as specified in
paragraphs (e) introductory text, (e)(2) and (3) of this section are
exempt from the requirements of this section.
(f) Closed vent systems and control devices. Closed vent systems
used to comply with the equipment leak provisions of this section must
comply with the requirements in Sec. Sec. 60.5411c and 60.5416c.
Control devices used to comply with the equipment leak provisions of
this section must comply with the requirements in Sec. Sec. 60.5412c,
60.5415c(e), and 60.5417c.
(g) Pumps, valves, and connectors in heavy liquid service and
pressure relief devices in light liquid or heavy liquid service. If
evidence of a potential leak is found at any time by AVO, or any other
detection method, a leak is detected and must be repaired in accordance
with paragraph (h) of this section.
(h) Repair requirements. When a leak is detected, you must comply
with the requirements of paragraphs (h)(1) through (5) of this section,
except as provided in paragraph (h)(6) of this section.
(1) A weatherproof and readily visible identification tag, marked
with the equipment identification number, must be attached to the
leaking equipment. The identification tag on equipment may be removed
after it has been repaired.
(2) A first attempt at repair must be made as soon as practicable,
but no later than 5 calendar days after the leak is detected. A first
attempt at repair is not required if the leak is detected using OGI and
the equipment identified as leaking would require elevating the repair
personnel more than 2 meters above a support surface.
(i) First attempts at repair for pumps in light liquid or heavy
liquid service include, but are not limited to, the practices described
in paragraphs (h)(2)(i)(A) and (B) of this section, where practicable.
(A) Tightening the packing gland nuts.
(B) Ensuring that the seal flush is operating at design pressure
and temperature.
(ii) For each valve where a leak is detected, you must comply with
paragraphs (h)(2)(ii)(A) (B), (C) or (D) of this section.
(A) Repack the existing valve with a low-e packing.
(B) Replace the existing valve with a low-e valve; or
(C) Perform a drill and tap repair with a low-e injectable packing.
(D) An owner or operator is not required to utilize a low-e valve
or low-e packing to replace or repack a valve if the owner or operator
demonstrates that a low-e valve or low-e packing is not technically
feasible. Low-e valve or low-e packing that is not suitable for its
intended use is considered to be technically infeasible. Factors that
may be considered in determining technical infeasibility include:
retrofit requirements for installation (e.g., re-piping or space
limitation), commercial unavailability for valve type, or certain
instrumentation assemblies.
(3) Repair of leaking equipment must be completed within 15
calendar days after detection of each leak, except as provided in
paragraphs (h)(4), (5) and (6) of this section.
(4) If the repair for visual indications of liquids dripping for
pumps in light liquid service can be made by eliminating visual
indications of liquids dripping, you must make the repair within 5
calendar days of detection.
(5) If the repair for AVO or other indication of a leak for open-
ended valves or lines; pumps, valves, or connectors in heavy liquid
service; or pressure relief devices in light liquid or heavy liquid
service can be made by eliminating the AVO, or other indication of a
potential leak, you must make the repair within 5 calendar days of
detection.
(6) Delay of repair of equipment for which leaks have been detected
is allowed if repair within 15 days is technically infeasible without a
process unit shutdown or as specified in paragraphs (h)(6)(i) through
(v) of this section. Repair of this equipment shall occur before the
end of the next process unit shutdown. Monitoring to verify repair must
occur within 15 days after startup of the process unit.
(i) Delay of repair of equipment is allowed for equipment which is
isolated from the process, and which does not have the potential to
emit methane.
(ii) Delay of repair for valves and connectors is allowed if the
conditions in paragraphs (h)(6)(ii)(A) and (B) of this section are met.
(A) You must demonstrate that emissions of purged material
resulting from immediate repair are greater than the fugitive emissions
likely to result from delay of repair, and
(B) When repair procedures are conducted, the purged material is
collected and destroyed or recovered in a control device complying with
paragraph (f) of this section.
(iii) Delay of repair for pumps is allowed if the conditions in
paragraphs (h)(6)(iii)(A) and (B) of this section are met.
(A) Repair requires the use of a dual mechanical seal system that
includes a barrier fluid system, and
(B) Repair is completed as soon as practicable, but not later than
6 months after the leak was detected.
(iv) If delay of repair is required to repack or replace the valve,
you may use delay of repair. Delay of repair beyond a process unit
shutdown is allowed for a valve, if valve assembly replacement is
necessary during the process unit shutdown, valve assembly supplies
have been depleted, and valve assembly supplies had been sufficiently
stocked before the supplies were depleted. Delay of repair beyond the
next process unit shutdown will not be allowed unless the next process
unit shutdown occurs sooner than 6 months after the first process unit
shutdown.
(v) When delay of repair is allowed for a leaking pump, valve, or
connector that remains in service, the pump, valve, or connector may be
considered to be repaired and no longer subject to delay of repair
requirements if two consecutive bimonthly monitoring results show no
leak remains.
(i) Initial compliance. You must demonstrate initial compliance
with the standards that apply to equipment leaks at onshore natural gas
processing plants as required by Sec. 60.5410c(g).
(j) Continuous compliance. You must demonstrate continuous
compliance with the standards that apply to equipment leaks at onshore
natural gas processing plants as required by Sec. 60.5415c(i).
(k) Reporting. You must perform the reporting requirements as
specified in Sec. 60.5420c(b)(1) and (10) and Sec. 60.5422c.
(l) Recordkeeping. You must perform the recordkeeping requirements
as specified in Sec. 60.5420c(c)(7), (9), and (11) and Sec. 60.5421c.
Sec. 60.5401c What are the alternative GHG standards for process
unit equipment designated facilities?
This section provides alternative standards for process unit
equipment designated facilities located at an onshore natural gas
processing plant. You may choose to comply with the standards in this
section instead of the requirements in Sec. 60.5400c. For purposes of
the alternative standards provided in this section, you must comply
with the requirements of paragraphs (a) through (m) of this section to
reduce methane emissions from equipment leaks, except as provided in
Sec. 60.5402c.
(a) General standards. You must comply with the requirements in
paragraphs (b) of this section for each
[[Page 17164]]
pump in light liquid service. You must comply with the requirements of
paragraph (c) of this section for each pressure relief device in gas/
vapor service. You must comply with the requirements in paragraph (d)
of this section for each open-ended valve or line. You must comply with
the requirements in paragraph (e) of this section for each closed vent
system and control device used to comply with equipment leak provisions
in this section. You must comply with paragraph (f) of this section for
each valve in gas/vapor or light liquid service. You must comply with
paragraph (g) of this section for each pump, valve, and connector in
heavy liquid service and pressure relief device in light liquid or
heavy liquid service. You must comply with paragraph (h) of this
section for each connector in gas/vapor and light liquid service. You
must make repairs as specified in paragraph (i) of this section. You
must demonstrate initial compliance with the standards as specified in
paragraph (j) of this section. You must demonstrate continuous
compliance with the standards as specified in paragraph (k) of this
section. You must perform the reporting requirements as specified in
paragraph (l) of this section. You must perform the recordkeeping
requirements as required in paragraph (m) of this section.
(1) Each piece of equipment is presumed to have the potential to
emit methane unless an owner or operator demonstrates that the piece of
equipment does not have the potential to emit methane. For a piece of
equipment to be considered not to have the potential to emit methane,
the methane content of a gaseous stream must be below detection limits
using Method 18 of appendix A-6 to this part. Alternatively, if the
piece of equipment is in wet gas service, you may choose to determine
the methane content of the stream is below the detection limit of the
methods described in ASTM E168-16(R2023), E169-16(R2022), or E260-96
(all incorporated by reference, see Sec. 60.17).
(2) [Reserved]
(b) Pumps in light liquid service. You must monitor each pump in
light liquid service monthly to detect leaks by the methods specified
in Sec. 60.5406c, except as provided in paragraphs (b)(2) through (4)
of this section. A leak is defined as an instrument reading of 2,000
ppmv or greater. A pump that begins operation in light liquid service
after the initial startup date for the process unit must be monitored
for the first time within 30 days after the end of its startup period,
except for a pump that replaces a leaking pump and except as provided
in paragraphs (b)(2) through (4) of this section.
(1) In addition to the requirements in paragraph (b) of this
section, you must conduct weekly visual inspections of all pumps in
light liquid service for indications of liquids dripping from the pump
seal. If there are indications of liquids dripping from the pump seal,
you must follow the procedure specified in either paragraph (b)(1)(i)
or (ii) of this section.
(i) Monitor the pump within 5 days using the methods specified in
Sec. 60.5406c. A leak is defined as an instrument reading of 2,000
ppmv or greater.
(ii) Designate the visual indications of liquids dripping as a
leak, and repair the leak as specified in paragraph (i) of this
section.
(2) Each pump equipped with a dual mechanical seal system that
includes a barrier fluid system is exempt from the requirements in
paragraph (b) of this section, provided the requirements specified in
paragraphs (b)(2)(i) through (vi) of this section are met.
(i) Each dual mechanical seal system meets the requirements of
paragraphs (b)(2)(i)(A), (B), or (C) of this section.
(A) Operated with the barrier fluid at a pressure that is at all
times greater than the pump stuffing box pressure; or
(B) Equipped with a barrier fluid degassing reservoir that is
routed to a process or fuel gas system or connected by a closed vent
system to a control device that complies with the requirements of
paragraph (e) of this section; or
(C) Equipped with a system that purges the barrier fluid into a
process stream with zero methane emissions to the atmosphere.
(ii) The barrier fluid system is in heavy liquid service or does
not have the potential to emit methane.
(iii) Each barrier fluid system is equipped with a sensor that will
detect failure of the seal system, the barrier fluid system, or both.
(iv) Each pump is checked according to the requirements in
paragraph (b)(1) of this section.
(v) Each sensor meets the requirements in paragraphs (b)(2)(v)(A)
through (C) of this section.
(A) Each sensor as described in paragraph (b)(2)(iii) of this
section is checked daily or is equipped with an audible alarm.
(B) You determine, based on design considerations and operating
experience, a criterion that indicates failure of the seal system, the
barrier fluid system, or both.
(C) If the sensor indicates failure of the seal system, the barrier
fluid system, or both, based on the criterion established in paragraph
(b)(2)(v)(B) of this section, a leak is detected.
(3) Any pump that is designated, as described in Sec.
60.5421c(b)(12), for no detectable emissions, as indicated by an
instrument reading of less than 500 ppmv above background, is exempt
from the requirements of paragraphs (b), (b)(1), and (b)(2) of this
section if the pump:
(i) Has no externally actuated shaft penetrating the pump housing;
(ii) Is demonstrated to be operating with no detectable emissions
as indicated by an instrument reading of less than 500 ppmv above
background as measured by the methods specified in Sec. 60.5406c; and
(iii) Is tested for compliance with paragraph (b)(3)(ii) of this
section initially upon designation, annually, and at other times
requested by the Administrator.
(4) If any pump is equipped with a closed vent system capable of
capturing and transporting any leakage from the seal or seals to a
process, fuel gas system, or a control device that complies with the
requirements of paragraph (e) of this section, it is exempt from
paragraphs (b) introductory text and (b)(1) through (3) of this
section, and the repair requirements of paragraph (i) of this section.
(5) Any pump that is designated, as described in Sec.
60.5421c(b)(13), as an unsafe-to-monitor pump is exempt from the
monitoring and inspection requirements of paragraphs (b) introductory
text, (b)(1), and (b)(2)(iv) through (vi) of this section if the
conditions in paragraph (b)(5)(i) and (ii) are met.
(i) You demonstrate that the pump is unsafe-to-monitor because
monitoring personnel would be exposed to an immediate danger as a
consequence of complying with paragraph (b) of this section; and
(ii) You have a written plan that requires monitoring of the pump
as frequently as practicable during safe-to-monitor times, but not more
frequently than the periodic monitoring schedule otherwise applicable,
and you repair the equipment according to the procedures in paragraph
(i) of this section if a leak is detected.
(6) Any pump that is located within the boundary of an unmanned
plant site is exempt from the weekly visual inspection requirements in
paragraph (b)(1) and (b)(2)(iv) of this section, and the daily
requirements of paragraph (b)(2)(v) of this section, provided that each
pump is visually inspected as often as practicable and at least
monthly.
[[Page 17165]]
(c) Pressure relief devices in gas/vapor service. You must monitor
each pressure relief device quarterly using the methods specified in
Sec. 60.5406c. A leak is defined as an instrument reading of 500 ppmv
or greater above background.
(1) In addition to the requirements in paragraph (c) of this
section, after each pressure release, you must monitor each pressure
relief device within 5 calendar days after each pressure release to
detect leaks. A leak is detected if an instrument reading of 500 ppmv
or greater is provided using the methods specified in Sec.
60.5406c(b).
(2) Any pressure relief device that is located in a
nonfractionating plant that is monitored only by non-plant personnel
may be monitored after a pressure release the next time the monitoring
personnel are onsite, or within 30 calendar days after a pressure
release, whichever is sooner, instead of within 5 calendar days as
specified in paragraph (c)(1) of this section.
(3) No pressure relief device described in paragraph (c)(2) of this
section may be allowed to operate for more than 30 calendar days after
a pressure release without monitoring.
(4) Any pressure relief device that is routed to a process or fuel
gas system or equipped with a closed vent system capable of capturing
and transporting leakage through the pressure relief device to a
control device as described in paragraph (e) of this section is exempt
from the requirements of paragraphs (c) introductory text and (c)(1) of
this section.
(5) Pressure relief devices equipped with a rupture disk are exempt
from the requirements of paragraphs (c)(1) and (2) of this section
provided you install a new rupture disk upstream of the pressure relief
device as soon as practicable, but no later than 5 calendar days after
each pressure release, except as provided in paragraph (i)(4) of this
section.
(d) Open-ended valves or lines. Each open-ended valve or line must
be equipped with a cap, blind flange, plug, or a second valve, except
as provided in paragraphs (d)(4) and (5) of this section. The cap,
blind flange, plug, or second valve must seal the open end of the valve
or line at all times except during operations requiring process fluid
flow through the open-ended valve or line.
(1) If evidence of a leak is found at any time by AVO, or any other
detection method, a leak is detected and must be repaired in accordance
with paragraph (i) of this section. A leak is defined as an instrument
reading of 500 ppmv or greater if Method 21 of appendix A-7 to this
part is used.
(2) Each open-ended valve or line equipped with a second valve must
be operated in a manner such that the valve on the process fluid end is
closed before the second valve is closed.
(3) When a double block-and-bleed system is being used, the bleed
valve or line may remain open during operations that require venting
the line between the block valves but shall remain closed at all other
times.
(4) Open-ended valves or lines in an emergency shutdown system
which are designed to open automatically in the event of a process
upset are exempt from the requirements of paragraphs (d), and (d)(1)
through (3) of this section.
(5) Open-ended valves or lines containing materials which would
autocatalytically polymerize or would present an explosion, serious
overpressure, or other safety hazard if capped or equipped with a
double block-and-bleed system as specified in paragraphs (d)
introductory text and (d)(2) and (3) of this section are exempt from
the requirements of this section.
(e) Closed vent systems and control devices. Closed vent systems
used to comply with the equipment leak provisions of this section must
comply with the requirements in Sec. Sec. 60.5411c and 60.5416c.
Control devices used to comply with the equipment leak provisions of
this section must comply with the requirements in Sec. Sec. 60.5412c,
60.5415c(e), and 60.5417c.
(f) Valves in gas/vapor and light liquid service. You must monitor
each valve in gas/vapor and in light liquid service quarterly to detect
leaks by the methods specified in Sec. 60.5406c, except as provided in
paragraphs (h)(3) through (5) of this section.
(1) A valve that begins operation in gas/vapor service or in light
liquid service after the initial startup date for the process unit must
be monitored for the first time within 90 days after the end of its
startup period to ensure proper installation, except for a valve that
replaces a leaking valve and except as provided in paragraphs (h)(3)
through (5) of this section.
(2) An instrument reading of 500 ppmv or greater is a leak. You
must repair each leaking valve according to the requirements in
paragraph (i) of this section.
(3) Any valve that is designated, as described in Sec.
60.5421c(b)(12), for no detectable emissions, as indicated by an
instrument reading of less than 500 ppmv above background, is exempt
from the requirements of paragraphs (f) of this section if the valve:
(i) Has no externally actuating mechanism in contact with the
process fluid;
(ii) Is operated with emissions less than 500 ppmv above background
as determined by the methods specified in Sec. 60.5406c; and
(iii) Is tested for compliance with paragraph (f)(3)(ii) of this
section initially upon designation, annually, and at other times
requested by the Administrator.
(4) Any valve that is designated, as described in Sec.
60.5421c(b)(13), as an unsafe-to-monitor pump is exempt from the
monitoring requirements of paragraph (f) of this section if the
requirements in paragraphs (f)(4)(i) and (ii) of this section are met.
(i) You demonstrate that the valve is unsafe-to-monitor because
monitoring personnel would be exposed to an immediate danger as a
consequence of complying with paragraph (f) of this section; and
(ii) You have a written plan that requires monitoring of the valve
as frequently as practicable during safe-to-monitor times, but not more
frequently than the periodic monitoring schedule otherwise applicable,
and you repair the equipment according to the procedures in paragraph
(i) of this section if a leak is detected.
(5) Any valve that is designated, as described in Sec.
60.5421c(b)(14), as a difficult-to-monitor valve is exempt from the
monitoring requirements of paragraph (h) of this section if the
requirements in paragraph (f)(5)(i) through (iii) of this section are
met.
(i) You demonstrate that the valve cannot be monitored without
elevating the monitoring personnel more than 2 meters above a support
surface.
(ii) The process unit within which the valve is located has less
than 3.0 percent of its total number of valves designated as difficult-
to-monitor.
(iii) You have a written plan that requires monitoring of the at
least once per calendar year.
(g) Pumps, valves, and connectors in heavy liquid service and
pressure relief devices in light liquid or heavy liquid service. If
evidence of a potential leak is found at any time by AVO, or any other
detection method, you must comply with either paragraph (g)(1) or (2)
of this section.
(1) You must monitor the equipment within 5 calendar days by the
method specified in Sec. 60.5406c and repair any leaks detected
according to paragraph (i) of this section. An instrument reading of
10,000 ppmv or greater is defined as a leak.
(2) You must designate the AVO, or other indication of a leak as a
leak and repair the leak according to paragraph (i) of this section.
[[Page 17166]]
(h) Connectors in gas/vapor service and in light liquid service.
You must initially monitor all connectors in the process unit for leaks
by the later of either 12 months after the compliance date or 12 months
after initial startup. If all connectors in the process unit have been
monitored for leaks prior to the compliance date, no initial monitoring
is required provided either no process changes have been made since the
monitoring or the owner or operator can determine that the results of
the monitoring, with or without adjustments, reliably demonstrate
compliance despite process changes. If required to monitor because of a
process change, you are required to monitor only those connectors
involved in the process change.
(1) You must monitor all connectors in gas/vapor service and in
light liquid service annually, except as provided in paragraph (e) of
this section or paragraph (h)(2) of this section.
(2) Any connector that is designated, as described in Sec.
60.5421c(b)(13), as an unsafe-to-monitor connector is exempt from the
requirements of paragraphs (h) and (h)(1) of this section if the
requirements of paragraphs (h)(2)(i) and (ii) of this section are met.
(i) You demonstrate the connector is unsafe-to-monitor because
monitoring personnel would be exposed to an immediate danger as a
consequence of complying with paragraphs (h) and (h)(1) of this
section; and
(ii) You have a written plan that requires monitoring of the
connector as frequently as practicable during safe-to-monitor times,
but not more frequently than the periodic monitoring schedule otherwise
applicable, and you repair the equipment according to the procedures in
paragraph (i) of this section if a leak is detected.
(3) Inaccessible, ceramic, or ceramic-line connectors.
(i) Any connector that is inaccessible or that is ceramic or
ceramic-lined (e.g., porcelain, glass, or glass-lined), is exempt from
the monitoring requirements of paragraphs (h) and (h)(1) of this
section, from the leak repair requirements of paragraph (i) of this
section, and from the recordkeeping and reporting requirements of
Sec. Sec. 60.5421c and 60.5422c. An inaccessible connector is one that
meets any of the specifications in paragraphs (h)(3)(i)(A) through (F)
of this section, as applicable.
(A) Buried.
(B) Insulated in a manner that prevents access to the connector by
a monitor probe.
(C) Obstructed by equipment or piping that prevents access to the
connector by a monitor probe.
(D) Unable to be reached from a wheeled scissor-lift or hydraulic-
type scaffold that would allow access to connectors up to 7.6 meters
(25 feet) above the ground.
(E) Inaccessible because it would require elevating monitoring
personnel more than 2 meters (7 feet) above a permanent support surface
or would require the erection of scaffold.
(F) Not able to be accessed at any time in a safe manner to perform
monitoring. Unsafe access includes, but is not limited to, the use of a
wheeled scissor-lift on unstable or uneven terrain, the use of a
motorized man-lift basket in areas where an ignition potential exists,
or access would require near proximity to hazards such as electrical
lines or would risk damage to equipment.
(ii) If any inaccessible, ceramic, or ceramic-lined connector is
observed by AVO, or other means to be leaking, the indications of a
leak to the atmosphere by AVO or other means must be eliminated as soon
as practicable.
(4) Connectors which are part of an instrumentation systems and
inaccessible, ceramic, or ceramic-lined connectors meeting the
provisions of paragraph (h)(3) of this section, are not subject to the
recordkeeping requirements of Sec. 60.5421c(b)(1).
(i) Repair requirements. When a leak is detected, comply with the
requirements of paragraphs (i)(1) through (5) of this section, except
as provided in paragraph (i)(6) of this section.
(1) A weatherproof and readily visible identification tag, marked
with the equipment identification number, must be attached to the
leaking equipment. The identification tag on the equipment may be
removed after it has been repaired.
(2) A first attempt at repair must be made as soon as practicable,
but no later than 5 calendar days after the leak is detected.
(i) First attempts at repair for pumps in light liquid or heavy
liquid service include, but are not limited to, the practices described
in paragraphs (i)(2)(i)(A) and (B) of this section, where practicable.
(A) Tightening the packing gland nuts.
(B) Ensuring that the seal flush is operating at design pressure
and temperature.
(ii) For each valve where a leak is detected, you must comply with
paragraphs (i)(2)(ii)(A), (B) or (C), and (D) of this section.
(A) Repack the existing valve with a low-e packing.
(B) Replace the existing valve with a low-e valve; or
(C) Perform a drill and tap repair with a low-e injectable packing.
(D) An owner or operator is not required to utilize a low-e valve
or low-e packing to replace or repack a valve if the owner or operator
demonstrates that a low-e valve or low-e packing is not technically
feasible. Low-e valve or low-e packing that is not suitable for its
intended use is considered to be technically infeasible. Factors that
may be considered in determining technical infeasibility include:
retrofit requirements for installation (e.g., re-piping or space
limitation), commercial unavailability for valve type, or certain
instrumentation assemblies.
(3) Repair of leaking equipment must be completed within 15
calendar days after detection of each leak, except as provided in
paragraphs (i)(4), (5) and (6) of this section.
(4) If the repair for visual indications of liquids dripping for
pumps in light liquid service can be made by eliminating visual
indications of liquids dripping, you must make the repair within 5
calendar days of detection.
(5) If the repair for AVO or other indication of a leak for open-
ended lines or valves; pumps, valves, or connectors in heavy liquid
service; or pressure relief devices in light liquid or heavy liquid
service can be made by eliminating the AVO, or other indication of a
potential leak, you must make the repair within 5 calendar days of
detection.
(6) Delay of repair of equipment for which leaks have been detected
will be allowed if repair within 15 calendar days is technically
infeasible without a process unit shutdown or as specified in
paragraphs (i)(6)(i) through (v) of this section. Repair of this
equipment shall occur before the end of the next process unit shutdown.
Monitoring to verify repair must occur within 15 calendar days after
startup of the process unit.
(i) Delay of repair of equipment will be allowed for equipment
which is isolated from the process, and which does not have the
potential to emit methane.
(ii) Delay of repair for valves and connectors will be allowed if
the conditions in paragraphs (i)(6)(ii)(A) and (B) are met.
(A) You demonstrate that emissions of purged material resulting
from immediate repair are greater than the fugitive emissions likely to
result from delay of repair, and
(B) When repair procedures are conducted, the purged material is
[[Page 17167]]
collected and destroyed or recovered in a control device complying with
paragraph (e) of this section.
(iii) Delay of repair for pumps will be allowed if the conditions
in paragraphs (i)(6)(iii)(A) and (B) of this section are met.
(A) Repair requires the use of a dual mechanical seal system that
includes a barrier fluid system, and
(B) Repair is completed as soon as practicable, but not later than
6 months after the leak was detected.
(iv) If delay of repair is required to repack or replace the valve,
you may use delay of repair. Delay of repair beyond a process unit
shutdown will be allowed for a valve, if valve assembly replacement is
necessary during the process unit shutdown, valve assembly supplies
have been depleted, and valve assembly supplies had been sufficiently
stocked before the supplies were depleted. Delay of repair beyond the
next process unit shutdown will not be allowed unless the next process
unit shutdown occurs sooner than 6 months after the first process unit
shutdown.
(v) When delay of repair is allowed for a leaking pump, valve, or
connector that remains in service, the pump, valve, or connector may be
considered to be repaired and no longer subject to delay of repair
requirements if two consecutive monthly monitoring results show no leak
remains.
(j) Initial compliance. You must demonstrate initial compliance
with the standards that apply to equipment leaks at onshore natural gas
processing plants as required by Sec. 60.5410c(g).
(k) Continuous compliance. You must demonstrate continuous
compliance with the standards that apply to equipment leaks at onshore
natural gas processing plants as required by Sec. 60.5415c(i).
(l) Reporting. You must perform the reporting requirements as
specified in Sec. 60.5420c(b)(1) and (b)(10) and Sec. 60.5422c.
(m) Recordkeeping. You must perform the recordkeeping requirements
as specified in Sec. 60.5420c(c)(7), (9), (11), and Sec. 60.5421c.
Sec. 60.5402c What are the exceptions to the GHG standards for
process unit equipment designated facilities?
(a) You may comply with the following exceptions to the provisions
of Sec. Sec. 60.5400c(a) and 60.5401c(a), as applicable.
(b) Pumps in light liquid service, pressure relief devices in gas/
vapor service, valves in gas/vapor and light liquid service, and
connectors in gas/vapor service and in light liquid service that are
located at a nonfractionating plant that does not have the design
capacity to process 283,200 standard cubic meters per day (scmd) (10
million standard cubic feet per day) or more of field gas may comply
with the exceptions specified in paragraphs (b)(1) or (2) of this
section.
(1) You are exempt from bimonthly OGI monitoring as required under
Sec. 60.5400c(b).
(2) You are exempt from the routine Method 21 of appendix A-7 to
this part monitoring requirements of Sec. 60.5401c(b), (c), (f), and
(h), if complying with the alternative standards of Sec. 60.5401c.
(c) Pumps in light liquid service, pressure relief devices in gas/
vapor service, valves in gas/vapor and light liquid service, and
connectors in gas/vapor service and in light liquid service within a
process unit that is located in the Alaskan North Slope are exempt from
the monitoring requirements Sec. 60.5400c(b) and (c) and Sec.
60.5401c(b), (c), (f) and (h).
(d) You may use the following provisions instead of Sec.
60.5403c(e):
(1) Equipment is in heavy liquid service if the weight percent
evaporated is 10 percent or less at 150 degrees Celsius (302 degrees
Fahrenheit) as determined by ASTM D86-96 (incorporated by reference,
see Sec. 60.17).
(2) Equipment is in light liquid service if the weight percent
evaporated is greater than 10 percent at 150 [deg]Celsius (302 [deg]F)
as determined by ASTM D86-96 (incorporated by reference, see Sec.
60.17).
(e) Equipment that is in vacuum service, except connectors in gas/
vapor and light liquid service, is excluded from the requirements of
Sec. 60.5400c(b) through (g), if it is identified as required in Sec.
60.5421c(b)(15). Equipment that is in vacuum service is excluded from
the requirements of Sec. 60.5401c(b) through (g) if it is identified
as required in Sec. 60.5421c(b)(15).
(f) Equipment that you designate as having the potential to emit
methane less than 300 hr/yr is excluded from the requirements of Sec.
60.5400c(b) through (g) and Sec. 60.5401c(b) through (h), if it is
identified as required in Sec. 60.5421c(b)(16) and it meets any of the
conditions specified in paragraphs (f)(1) through (3) of this section.
(1) The equipment has the potential to emit methane only during
startup and shutdown.
(2) The equipment has the potential to emit methane only during
process malfunctions or other emergencies.
(3) The equipment is backup equipment that has the potential to
emit methane only when the primary equipment is out of service.
Model Rule--Test Methods and Performance Testing
Sec. 60.5405c What test methods and procedures must I use for my
centrifugal compressor and reciprocating compressor designated
facilities?
(a) You must use one of the methods described in paragraph (a)(1)
and (2) of this section to screen for emissions or leaks from the
reciprocating compressor rod packing when complying with Sec.
60.5393c(a)(2)(iv) and from the compressor dry and wet seal vents when
complying with Sec. 60.5392c(a)(2)(i)(A).
(1) Optical gas imaging instrument. Use an optical gas imaging
instrument for equipment leak detection as specified in either
paragraph (a)(1)(i) or (ii) of this section. For the purposes of
paragraphs (a)(1)(i) and (ii) of this section, any visible emissions
observed by the optical gas imaging instrument from reciprocating rod
packing or compressor dry or wet seal vent is a leak.
(i) Optical gas imaging instrument as specified in appendix K of
this part. For reciprocating compressor and centrifugal compressor
designated facilities with wet or dry seals located at onshore natural
gas processing plants, use an optical gas imaging instrument to screen
for emissions from reciprocating rod packing or centrifugal compressor
dry or wet seal vent in accordance with the protocol specified in
appendix K of this part.
(ii) Optical gas imaging instrument as specified in Sec. 60.5397c
of this subpart. For reciprocating compressor and centrifugal
compressor designated facilities with wet or dry seals located at
centralized production facilities, compressor stations, or other
location that is not an onshore natural gas processing plant, use an
optical gas imaging instrument to screen for emissions from
reciprocating rod packing or centrifugal compressor with wet or dry
seals in accordance with the elements of Sec. 60.5397c(c)(7).
(2) Method 21. Use Method 21 in appendix A-7 to this part according
to Sec. 60.5403c(b)(1) and (2). For the purposes of this section, an
instrument reading of 500 ppmv above background or greater is a leak.
(b) You must determine natural gas volumetric flow rate using a
rate meter which meets the requirement in Method 2D in appendix A-1 to
this part. Rate meters must be calibrated on an annual basis according
to the requirements in Method 2D.
(c) You must use a high-volume sampler to measure emissions of the
reciprocating compressor rod packing or centrifugal compressor dry or
wet seal
[[Page 17168]]
vent in accordance with paragraphs (c)(1) through (7) of this section.
(1) You must use a high-volume sampler designed to capture the
entirety of the emissions from the applicable vent and measure the
entire range of methane concentrations being emitted as well as the
total volumetric flow at standard conditions. You must develop a
standard operating procedure for this device and document these
procedures in the appropriate monitoring plan. In order to get reliable
results, persons using this device should be knowledgeable in its
operation and the requirements in this section.
(2) This procedure may involve hazardous materials, operations, and
equipment. This procedure may not address all of the safety problems
associated with its use. It is the responsibility of the user of this
procedure to establish appropriate safety and health practices and
determine the applicability of regulatory limitations prior to
performing this procedure.
(3) The high-volume sampler must include a methane gas sensor(s)
which meets the requirements in paragraphs (c)(3)(i) through (iii) of
this section.
(i) The methane sensor(s) must be selective to methane with minimal
interference, less than 2.5 percent for the sum of responses to other
compounds in the gas matrix. You must document the minimal interference
though empirical testing or through data provided by the manufacturer
of the sensor.
(ii) The methane sensor(s) must have a measurement range over the
entire expected range of concentrations.
(iii) The methane sensor(s) must be capable of taking a measurement
once every second, and the data system must be capable of recording
these results for each sensor at all times during operation of the
sampler.
(4) The high-volume sampler must be designed such that it is
capable of sampling sufficient volume in order to capture all emissions
from the applicable vent. Your high-volume sampler must include a flow
measurement sensor(s) which meets the requirements of paragraphs
(c)(4)(i) and (ii) of this section.
(i) The flow measurement sensor must have a measurement range over
the entire expected range of flow rates sampled. If needed multiple
sensors may be used to capture the entire range of expected flow rates.
(ii) The flow measurement sensor(s)must be capable of taking a
measurement once every second, and the data system must be capable of
recording these results for each sensor at all times during operation
of the sampler.
(5) You must calibrate your methane sensor(s) according to the
procedures in paragraphs (c)(5)(i)(A) and (B) of this section, and flow
measurement sensors must be calibrated according to the procedures in
paragraph (c)(5)(ii) of this section.
(i) For Methane sensor calibration:
(A) Initially and on a semi-annual basis, determine the linearity
at four points through the measurement range for each methane sensor
using methane gaseous calibration cylinder standards. At each point,
the difference between the cylinder value and the sensor reading must
be less than 5 percent of the respective calibration gas value. If the
sensor does not meet this requirement, perform corrective action on the
sensor, and do not use the sampler until these criteria can be met.
(B) Prior to and at the end of each testing day, challenge each
sensor at two points, a low point, and a mid-point, using methane
gaseous calibration cylinder standards. At each point, the difference
between the cylinder value and the sensor reading must be less than 5
percent of the respective calibration gas value. If the sensor does not
meet this requirement, perform corrective action on the sensor and do
not use the sampler again until these criteria can be met. If the post-
test calibration check fails at either point, invalidate the data from
all tests performed subsequent to the last passing calibration check.
(ii) Flow measurement sensors must meet the requirements in Method
2D in appendix A-1 to this part. Rate meters must be calibrated on an
annual basis according to the requirements in Method 2D. If your flow
sensor relies on ancillary temperature and pressure measurements to
correct the flow rate to standard conditions, the temperature and
pressure sensors must also be calibrated on an annual basis. Standard
conditions are defined as 20 [deg]C (68 [deg]F) and 760 mm Hg (29.92
in. Hg).
(6) You must conduct sampling of the reciprocating compressor rod
packing or centrifugal compressor dry or wet seal vent in accordance
with the procedures in paragraphs (c)(6)(i) through (v) of this
section.
(i) The instrument must be operated consistent with manufacturer
recommendations; users are encouraged to develop a standard operating
procedure to document the exact procedures used for sampling.
(ii) Identify the rod packing or centrifugal compressor dry or wet
seal vent to be measured and record the signal to noise ratio (S/N) of
the engine. Collect a background methane sample in parts per million by
volume (ppmv) for a minimum of one minute and record the result along
with the date and time.
(iii) Approach the vent with the sample hose and adjust the sampler
so that you are measuring at the full flow rate. Then, adjust the flow
rate to ensure the measured methane concentration is within the
calibrated range of the methane sensor and minimum methane
concentration is at least 2 ppmv higher than the background
concentration. Sample for a period of at least one minute and record
the average flow rate in standard cubic feet per minute and the methane
sample concentration in ppmv, along with the date and time. Standard
conditions are defined as 20 [deg]C (68 [deg]F) and 760 mm Hg (29.92
in. Hg).
(iv) Calculate the leak rate according to the following equation:
[GRAPHIC] [TIFF OMITTED] TR08MR24.037
Where:
CH4B = background methane concentration, ppmv
CH4S = methane sample concentration, ppmv
V = Average flow rate of the sampler, scfm
Q = Methane emission rate, scfm
(v) You must collect at least three separate one-minute
measurements and determine the average leak rate. The relative percent
difference of these three separate samples should be less than 10
percent.
(7) If the measured natural gas flow determined as specified in
paragraph (c)(6) of this section exceeds 70.0 percent of the
manufacturer's reported maximum sampling flow rate you must either use
a temporary or permanent
[[Page 17169]]
flow meter according to paragraph (b) of this section or use another
method meeting the requirements in paragraph (d) of this section to
determine the leak or flow rate.
(d) As an alternative to a high-volume sampler, you may use any
other method that has been validated in accordance with the procedures
specified in Method 301 in appendix A to 40 CFR part 63, subject to
Administrator approval, as specified in Sec. 60.8(b).
Sec. 60.5406c What test methods and procedures must I use for my
process unit equipment designated facilities?
(a) In conducting the performance tests required in Sec. 60.8, you
must use as reference methods and procedures the test methods in
appendix A to this part or other methods and procedures as specified in
this section, except as provided in Sec. 60.8(b).
(b) You must determine compliance with the standards in Sec.
60.5401c as follows:
(1) Method 21 of appendix A-7 to this part shall be used to
determine the presence of leaking sources. The instrument shall be
calibrated before use each day of its use by the procedures specified
in Method 21 of appendix A-7 to this part. The following calibration
gases shall be used:
(i) Zero air (less than 10 ppmv of hydrocarbon in air); and
(ii) A mixture of methane or n-hexane and air at a concentration no
more than 2,000 ppmv greater than the leak definition concentration of
the equipment monitored. If the monitoring instrument's design allows
for multiple calibration scales, then the lower scale shall be
calibrated with a calibration gas that is no higher than 2,000 ppmv
above the concentration specified as a leak, and the highest scale
shall be calibrated with a calibration gas that is approximately or
equal to 10,000 ppmv. If only one scale on an instrument will be used
during monitoring, you need not calibrate the scales that will not be
used during that day's monitoring.
(iii) Verification that your monitoring equipment meets the
requirements specified in Section 6.0 of Method 21 of appendix A-7 to
this part. For purposes of instrument capability, the leak definition
shall be 500 ppmv or greater methane using a FID-based instrument for
valves and connectors and 2,000 ppmv methane or greater for pumps. If
you wish to use an analyzer other than a FID-based instrument, you must
develop a site-specific leak definition that would be equivalent to 500
ppmv methane using a FID-based instrument (e.g., 10.6 eV PID with a
specified isobutylene concentration as the leak definition would
provide equivalent response to your compound of interest).
(2) The instrument must be calibrated before use each day of its
use by the procedures specified in Method 21 of appendix A-7 to this
part. At minimum, you must also conduct precision tests at the interval
specified in Method 21 of appendix A-7 to this part, Section 8.1.2, and
a calibration drift assessment at the end of each monitoring day. The
calibration drift assessment must be conducted as specified in
paragraph (b)(2)(i) of this section. Corrective action for drift
assessments is specified in paragraphs (b)(2)(ii) and (iii) of this
section.
(i) Check the instrument using the same calibration gas that was
used to calibrate the instrument before use. Follow the procedures
specified in Method 21 of appendix A-7 to this part, Section 10.1,
except do not adjust the meter readout to correspond to the calibration
gas value. If multiple scales are used, record the instrument reading
for each scale used. Divide the arithmetic difference of the initial
and post-test calibration response by the corresponding calibration gas
value for each scale and multiply by 100 to express the calibration
drift as a percentage.
(ii) If a calibration drift assessment shows a negative drift of
more than 10 percent, then all equipment with instrument readings
between the fugitive emission definition multiplied by (100 minus the
percent of negative drift) divided by 100 and the fugitive emission
definition that was monitored since the last calibration must be re-
monitored.
(iii) If any calibration drift assessment shows a positive drift of
more than 10 percent from the initial calibration value, then, at the
owner/operator's discretion, all equipment with instrument readings
above the fugitive emission definition and below the fugitive emission
definition multiplied by (100 plus the percent of positive drift)
divided by 100 monitored since the last calibration may be re-
monitored.
(c) You shall determine compliance with the no detectable emission
standards in Sec. 60.5401c(b), (c), and (f) as specified in paragraphs
(c)(1) and (2) of this section.
(1) The requirements of paragraph (b) of this section shall apply.
(2) Method 21 of appendix A-7 to this part shall be used to
determine the background level. All potential leak interfaces shall be
traversed as close to the interface as possible. The arithmetic
difference between the maximum concentration indicated by the
instrument and the background level is compared with 500 ppmv for
determining compliance.
(d) You shall demonstrate that a piece of equipment is in light
liquid service by showing that all of the following conditions apply:
(1) The vapor pressure of one or more of the organic components is
greater than 0.3 kPa at 20 [deg]C (1.2 in. H2O at 68
[deg]F). Standard reference texts or ASTM D2879-83, -96, or -97
(incorporated by reference, see Sec. 60.17) shall be used to determine
the vapor pressures.
(2) The total concentration of the pure organic components having a
vapor pressure greater than 0.3 kPa at 20 [deg]C (1.2 in.
H2O at 68 [deg]F) is equal to or greater than 20 percent by
weight.
(3) The fluid is a liquid at operating conditions.
(e) Samples used in conjunction with paragraphs (d) and (e) of this
section shall be representative of the process fluid that is contained
in or contacts the equipment, or the gas being combusted in the flare.
Model Rule--Initial Compliance Requirements
Sec. 60.5410c How do I demonstrate initial compliance with the
standards for each of my designated facilities?
You must determine initial compliance with the standards for each
designated facility using the requirements of paragraphs (a) through
(i) of this section. Except as otherwise provided in this section, the
initial compliance period begins on the date specified in Sec.
60.5387c and ends no later than 1 year after that date. The initial
compliance period may be less than 1 full year.
(a) Gas well liquids unloading standards for well designated
facility. To demonstrate initial compliance with the GHG standards for
each gas well liquids unloading operation conducted at your well
designated facility as required by Sec. 60.5390c, you must comply with
paragraphs (a)(1) through (4) of this section, as applicable.
(1) You must submit the initial annual report for your well
designated facility as required in Sec. 60.5420c(b)(1) and (2).
(2) If you comply by using a liquids unloading technology or
technique that does not vent to the atmosphere according to Sec.
60.5390c(a)(1), you must maintain the records specified in Sec.
60.5420c(c)(1)(i).
(3) If you comply by using a liquids unloading technology or
technique that vents to the atmosphere according to Sec.
60.5390c(a)(2), (b) and (c), you must comply with paragraphs (a)(3)(i)
and (ii) of this section.
[[Page 17170]]
(i) Employ best management practices to minimize venting of methane
emissions as specified in Sec. 60.5390c(d) for each gas well liquids
unloading operation.
(ii) Maintain the records specified in Sec. 60.5420c(c)(1)(ii).
(4) If you comply by using Sec. 60.5390c(g), you must comply with
paragraphs (b)(4)(i) through (vi) of this section.
(i) Reduce methane emissions by 95.0 percent or greater and as
demonstrated by the requirements of Sec. 60.5413c.
(ii) Install a closed vent system that meets the requirements of
Sec. 60.5411c(a) and (c) to capture all emissions and route all
emissions to a control device that meets the conditions specified in
Sec. 60.5412c.
(iii) Conduct an initial performance test as required in Sec.
60.5413c within 180 days after the initial gas well liquids unloading
operation or install a control device tested under Sec. 60.5413c(d)
which meets the criteria in Sec. 60.5413c(d)(11) and (e), and comply
with the continuous compliance requirements of Sec. 60.5415c(e).
(iv) You must conduct the initial inspections required in Sec.
60.5416c(a) and (b).
(v) You must install and operate the continuous parameter
monitoring systems in accordance with Sec. 60.5417c(a) through (i), as
applicable.
(vi) You must maintain the records specified in Sec.
60.5420c(c)(1)(iii), (c)(7) and (c)(9) through (12), as applicable and
submit the reports as required by Sec. 60.5420c(b)(11) through (13),
as applicable.
(b) Associated gas well standards for well designated facility. To
demonstrate initial compliance with the GHG standards for each
associated gas well as required by Sec. 60.5391c, you must comply with
paragraphs (b)(1) through (5) of this section.
(1) If you comply with the requirements of Sec. 60.5391c(a), you
must maintain the records specified in Sec. 60.5420c(c)(2)(i) and
submit the information required by Sec. 60.5420c(b)(3)(i) through (iv)
in your initial annual report.
(2) If you comply with Sec. 60.5391c(b) because you have
demonstrated that annual methane emissions are 40 tons per year or
less, you must document the calculation of annual methane emissions
determined in accordance with Sec. 60.5391c(e)(1) and submit them in
the initial annual report, and comply with paragraphs (b)(4) of this
section.
(3) If you comply with Sec. 60.5391c(b) because you have
demonstrated that it is not feasible to comply with Sec.
60.5391c(a)(1), (2), (3), or (4) due to technical reasons, document the
initial demonstration and certification of the technical reason in
accordance with Sec. 60.5391c(e)(1) and submit them in the initial
annual report, and comply with paragraphs (b)(4) of this section.
Submit this documentation in the initial annual report, and comply with
paragraph (b)(4) of this section.
(4) If you comply with Sec. 60.5391c(b), you must comply with
paragraphs (b)4)((i) through (iv) of this section
(i) Reduce methane emissions by 95.0 percent or greater and as
demonstrated by the requirements of Sec. 60.5413c.
(ii) Install a closed vent system that meets the requirements of
Sec. 60.5411c(a) and (c) to capture the associated gas and route the
captured associated gas to a control device that meets the conditions
specified in Sec. 60.5412c.
(iii) Conduct an initial performance test as required in Sec.
60.5413c within 180 days after initial startup or by 36 months after
the state plan submittal deadline (as specified in Sec. 60.5362c(c)),
whichever date is later, or install a control device tested under Sec.
60.5413c(d) which meets the criteria in Sec. 60.5413c(d)(11) and (e)
and you must comply with the continuous compliance requirements of
Sec. 60.5415c(e).
(iv) Conduct the initial inspections required in Sec. 60.5416c(a)
and (b).
(v) Install and operate the continuous parameter monitoring systems
in accordance with Sec. 60.5417c(a) through (g), as applicable.
(vi) Maintain the records specified in Sec. 60.5420c(c)(2)(ii) and
(c)(7) and (9) through (12), as applicable.
(5) You must submit the initial annual report for your associated
gas well at a well designated facility as required in Sec.
60.5420c(b)(1), (3), and (10) through (12), as applicable.
(c) Centrifugal compressor designated facility. To demonstrate
initial compliance with the GHG standards in Sec. 60.5392c(a)(1) and
(2) for your centrifugal compressors (including both wet seal
centrifugal compressors and dry seal centrifugal compressors) that
require volumetric flow rate measurements, you must comply with
paragraphs (c)(1), (6), and (7) of this section. Alternatively, if you
comply with the GHG standards for your wet seal and dry seal
centrifugal compressor designated facility by reducing methane
emissions from each centrifugal compressor wet seal fluid degassing
system by 95.0 percent in accordance with Sec. 60.5392c(a)(3) and (4),
you must achieve initial compliance by complying with paragraphs (c)(2)
through (7) of this section. If you comply with the GHG standards for
your wet seal and dry seal centrifugal compressor designated facility
by routing emissions from the wet seal fluid degassing system through a
closed vent system to a process in accordance with Sec.
60.5392c(a)(5), you must achieve initial compliance by complying with
paragraphs (c)(2), (4), (6), and (7) of this section.
(1) You must maintain the volumetric flow rates for your
centrifugal compressors as specified in paragraphs (c)(1)(i) through
(iii) of this section, as applicable. You must conduct your initial
annual volumetric measurement as required by Sec. 60.5392c(a)(1).
(i) For your wet seal centrifugal compressors (including self-
contained wet seal centrifugal compressors), you must maintain the
volumetric flow rate at or below 3 scfm per seal.
(ii) For your Alaska North Slope centrifugal compressor equipped
with sour seal oil separator and capture system, you must maintain the
volumetric flow rate at or below 9 scfm per seal.
(iii) For your dry seal compressor, you must maintain the
volumetric flow rate at or below 10 scfm per seal.
(2) If you use a control device to reduce emissions to comply with
Sec. 60.5392c(a)(4) or route the emissions to a process to comply with
Sec. 60.5392c(a)(5), you must equip the wet seal fluid degassing
system or dry seal system with a cover that meets the requirements of
Sec. 60.5411c(b) and route the captured vapors through a closed vent
system that meets the requirements of Sec. 60.5411c(a) and (c).
(3) If you use a control device to comply with Sec.
60.5392c(a)(4), you must conduct an initial performance test as
required in Sec. 60.5413c within 180 days after initial startup, or by
36 months after the state plan submittal deadline (as specified in
Sec. 60.5362c(c)), whichever date is later, or install a control
device tested under Sec. 60.5413c(d) which meets the criteria in Sec.
60.5413c(d)(11) and (e) and you must comply with the continuous
compliance requirements of Sec. 60.5415c(e).
(4) If you use a control device to comply with Sec. 60.5392c(a)(4)
or comply with Sec. 60.5392c(a)(5) by routing to a process, you must
conduct the initial inspections required in Sec. 60.5416c(a) and (b).
(5) If you use a control device to comply with Sec.
60.5392c(a)(4), you must install and operate the continuous parameter
monitoring systems in accordance with Sec. 60.5417c(a) through (i), as
applicable.
(6) You must submit the initial annual report for your centrifugal
compressor
[[Page 17171]]
designated facility as required in Sec. 60.5420c(b)(1) and (4) and
(b)(10) through (12), as applicable.
(7) You must maintain the records as specified in Sec.
60.5420c(c)(3) and (c)(7) through (12), as applicable.
(d) Reciprocating compressor designated facility. To demonstrate
initial compliance with the GHG standards for each reciprocating
compressor designated facility as required by Sec. 60.5393c, you must
comply with paragraphs (d)(1) through (7) of this section.
(1) If you comply with Sec. 60.5393c(a) by maintaining volumetric
flow rate at or below 2 scfm per cylinder (or a combined cylinder
emission flow rate greater than the number of compression cylinders
multiplied by 2 scfm) as required by Sec. 60.5393c(a), you must
maintain volumetric flow rate at or below 2 scfm and you must conduct
your initial annual volumetric flow rate measurement as required by
Sec. 60.5393c(a)(1).
(2) If you comply with Sec. 60.5393c by collecting the methane
emissions from your reciprocating compressor rod packing using a rod
packing emissions collection system as required by Sec.
60.5393c(d)(1), you must equip the reciprocating compressor with a
cover that meets the requirements of Sec. 60.5411c(b), route emissions
to a process through a closed vent system that meets the requirements
of Sec. 60.5411c(a) and (c), and you must conduct the initial
inspections required in Sec. 60.5416c(a) and (b).
(3) If you comply with Sec. 60.5393c(d) by collecting emissions
from your rod packing emissions collection system by using a control
device to reduce methane emissions by 95.0 percent as required by Sec.
60.5393c(d)(2), you must equip the reciprocating compressor with a
cover that meets the requirements of Sec. 60.5411c(b), route emissions
to a control device that meets the conditions specified in Sec.
60.5412c through a closed vent system that meets the requirements of
Sec. 60.5411c(a) and (c), and you must conduct the initial inspections
required in Sec. 60.5416c(a) and (b).
(4) If you comply with Sec. 60.5393c(d)(2), you must conduct an
initial performance test as required in Sec. 60.5413c within 180 days
after initial startup, or by 36 months after the state plan submittal
deadline (as specified in Sec. 60.5362c(c)), whichever date is later,
or install a control device tested under Sec. 60.5413c(d) which meets
the criteria in Sec. 60.5413c(d)(11) and (e) and you must comply with
the continuous compliance requirements of Sec. 60.5415c(e).
(5) If you comply with Sec. 60.5393c(d)(2), you must install and
operate the continuous parameter monitoring systems in accordance with
Sec. 60.5417c(a) through (i), as applicable.
(6) You must submit the initial annual report for your
reciprocating compressor as required in Sec. 60.5420c(b)(1), (5) and
(10) through (12), as applicable.
(7) You must maintain the records as specified in Sec.
60.5420c(c)(4) and (7) through (12), as applicable.
(e) Process controller designated facility. To demonstrate initial
compliance with GHG emission standards for your process controller
designated facility, you must comply with paragraphs (e)(1) through (5)
of this section, as applicable. If you change compliance methods, you
must perform the applicable compliance demonstrations of paragraphs
(e)(1) through (3) of this section again for the new compliance method,
note the change in compliance method in the annual report required by
Sec. 60.5420c(b)(6)(iv), and maintain the records required by
paragraph (e)(1)(i) or (ii) of this section for the new compliance
method.
(1) For process controller designated facilities complying with the
requirements of Sec. 60.5394c(a), you must demonstrate that your
process controller designated facility does not emit any methane to the
atmosphere by meeting the requirements of paragraph (e)(3) of this
section.
(i) If you comply by routing the emissions to a process, you must
meet the requirements for closed vent systems specified in paragraph
(e)(3) of this section.
(ii) If you comply by using a self-contained natural gas-driven
process controller, you must conduct an initial no identifiable
emissions inspection required by Sec. 60.5416c(b).
(2) For each process controller designated facility located at a
site in Alaska that does not have access to electrical power, you must
demonstrate initial compliance with Sec. 60.5394c(b)(1) and (2) or
with Sec. 60.5394c(b)(3), as an alternative to complying with
paragraph Sec. 60.5394c(a) by meeting the requirements specified in
(e)(2)(i) through (v) of this section for each process controller, as
applicable.
(i) For each process controller in the process controller
designated facility operating with a bleed rate of less than or equal
to 6 scfh, you must maintain records in accordance with Sec.
60.5420c(c)(5)(iii)(A) that demonstrate the process controller is
designed and operated to achieve a bleed rate less than or equal to 6
scfh.
(ii) For each process controller in the process controller
designated facility operating with a bleed rate greater than 6 scfh,
you must maintain records that demonstrate that a controller with a
higher bleed rate than 6 scfh is required based on a specific
functional need for that controller as specified in Sec.
60.5420c(c)(5)(iii)(B).
(iii) For each intermittent vent process controller in the process
controller designated facility you must demonstrate that each
intermittent vent controller does not emit to the atmosphere during
idle periods by conducting initial monitoring in accordance with Sec.
60.5394c(b)(2)(ii).
(iv) For each process controller designated facility that complies
by reducing methane emissions from all controllers in the process
controller designated facility by 95.0 percent in accordance with Sec.
60.5394c(b)(3), you must comply with paragraphs (e)(2)(iv)(A) through
(D) of this section.
(A) Reduce methane emissions by 95.0 percent or greater and as
demonstrated by the requirements of Sec. 60.5413c.
(B) Route all process controller designated facility emissions to a
control device that meets the conditions specified in Sec. 60.5412c
through a closed vent system that meets the requirements specified in
paragraph (e)(3) of this section.
(C) Conduct an initial performance test as required in Sec.
60.5413c within 180 days after initial startup, or by 36 months after
the state plan submittal deadline (as specified in Sec. 60.5362c(c)),
whichever date is later, or install a control device tested under Sec.
60.5413c(d) which meets the criteria in Sec. 60.5413c(d)(11) and (e)
and you must comply with the continuous compliance requirements of
Sec. 60.5415c(g).
(D) Install and operate the continuous parameter monitoring systems
in accordance with Sec. 60.5417c(a) through (g), as applicable.
(3) For each closed vent system used to comply with Sec. 60.5394c,
you must meet the requirements specified in paragraphs (e)(3)(i) and
(ii) of this section.
(i) Install a closed vent system that meets the requirements of
Sec. 60.5411c(a) and (c).
(ii) Conduct the initial inspections of the closed vent system and
bypasses, if applicable, as required in Sec. 60.5416c(a) and (b).
(4) You must submit the initial annual report for your process
controller designated facility as required in Sec. 60.5420c(b)(1) and
(6).
[[Page 17172]]
(5) You must maintain the records as specified in Sec.
60.5420c(c)(5).
(f) Pump designated facility. To demonstrate initial compliance
with the GHG standards for your pump designated facility as required by
Sec. 60.5395c, you must comply with paragraphs (f)(1) through (4) of
this section, as applicable. If you change compliance methods, you must
perform the applicable compliance demonstrations of paragraphs (f)(1)
and (2) of this section again for the new compliance method, note the
change in compliance method in the annual report required by Sec.
60.5420c(b)(9)(v), and maintain the records required by paragraph
(f)(4) of this section for the new compliance method.
(1) For pump designated facilities complying with the requirements
of Sec. 60.5395c(a) or (b)(2) by routing emissions to a process, you
must meet the requirements specified in paragraphs (f)(1)(ii) and (iv)
of this section. For pump designated facilities complying with the
requirements of Sec. 60.5395c(b)(3), you must meet the requirements
specified in paragraphs (f)(1)(i) and (v) of this section.
(i) Reduce methane emissions by 95.0 percent or greater and as
demonstrated by the requirements of Sec. 60.5413c.
(ii) Install a closed vent system that meets the requirements of
Sec. 60.5411c(a) and (c) to capture all emissions from all pumps in
the pump designated facility and route all emissions to a process or
control device that meets the conditions specified in Sec. 60.5412c.
(iii) Conduct an initial performance test as required in Sec.
60.5413c within 180 days after initial startup, or by 36 months after
the state plan submittal deadline (as specified in Sec. 60.5362c(c)),
whichever date is later, or install a control device tested under Sec.
60.5413c(d) which meets the criteria in Sec. 60.5413c(d)(11) and (e),
and you must comply with the continuous compliance requirements of
Sec. 60.5415c(e).
(iv) Conduct the initial inspections of the closed vent system and
bypasses, if applicable, as required in Sec. 60.5416c(a) and (b).
(v) Install and operate the continuous parameter monitoring systems
in accordance with Sec. 60.5417c(a) through (i), as applicable.
(2) Submit the certifications specified in paragraphs (f)(2)(i)
through (iii) of this section, as applicable.
(i) The certification required by Sec. 60.5395c(b)(3) that there
is no vapor recovery unit on site and that there is a control device on
site, but it does not achieve a 95.0 percent emissions reduction.
(ii) The certification required by Sec. 60.5395c(b)(4) that there
is no control device or process available on site.
(iii) The certification required by Sec. 60.5395c(b)(5)(i) that it
is technically infeasible to capture and route the pump designated
facility emissions to a process or an existing control device.
(3) You must submit the initial annual report for your pump
designated facility as specified in Sec. 60.5420c(b)(1) and (9).
(4) You must maintain the records for your pump designated facility
as specified in Sec. 60.5420c (c)(7) and (c)(9) through (12), as
applicable, and (c)(14).
(g) Process unit equipment designated facility. To achieve initial
compliance with the GHG standards for process unit equipment designated
facilities as required by Sec. 60.5400c, you must comply with
paragraphs (g)(1) through (4) and (g)(11) through (15) of this section,
unless you meet and comply with the exception in Sec. 60.5402c(b),
(e), or (f) or meet the exemption in Sec. 60.5402c(c). If you comply
with the GHG standards for process unit equipment designated facilities
using the alternative standards in Sec. 60.5401c, you must comply with
paragraphs (g)(5) through (15) of this section, unless you meet the
exemption in Sec. 60.5402c(b) or (c) or the exception in Sec.
60.5402c(e) or (f).
(1) You must conduct monitoring for each pump in light liquid
service, pressure relief device in gas/vapor service, valve in gas/
vapor or light liquid service and connector in gas/vapor or light
liquid service as required by Sec. 60.5400c(b).
(2) You must conduct monitoring as required by Sec. 60.5400c(c)
for each pump in light liquid service.
(3) You must conduct monitoring as required by Sec. 60.5400c(d)
for each pressure relief device in gas/vapor service.
(4) You must comply with the equipment requirements for each open-
ended valve or line as required by Sec. 60.5400c(e).
(5) You must conduct monitoring for each pump in light liquid
service as required by Sec. 60.5401c(b).
(6) You must conduct monitoring for each pressure relief device in
gas/vapor service as required by Sec. 60.5401c(c).
(7) You must comply with the equipment requirements for each open-
ended valve or line as required by Sec. 60.5401c(d).
(8) You must conduct monitoring for each valve in gas/vapor or
light liquid service as required by Sec. 60.5401c(f).
(9) You must conduct monitoring for each pump, valve, and connector
in heavy liquid service and each pressure relief device in light liquid
or heavy liquid service as required by Sec. 60.5401c(g).
(10) You must conduct monitoring for each connector in gas/vapor or
light liquid service as required by Sec. 60.5401c(h).
(11) For each pump equipped with a dual mechanical seal system that
degasses the barrier fluid reservoir to a process or a control device,
each pump which captures and transports leakage from the seal or seals
to a process or a control device, or each pressure relief device which
captures and transports leakage through the pressure relief device to a
process or a control device, you must meet the requirements of
paragraph (g)(11)(i) through (vi) of this section.
(i) Reduce methane emissions by 95.0 percent or greater and as
demonstrated by the requirements of Sec. 60.5413c or route to a
process.
(ii) Install a closed vent system that meets the requirements of
Sec. 60.5411c(a) and (c) to capture all emissions from each pump
equipped with a dual mechanical seal system that degasses the barrier
fluid reservoir, each pump which captures and transports leakage from
the seal or seals, or each pressure relief device which captures and
transports leakage through the pressure relief device and route all
emissions to a process or to a control device that meets the conditions
specified in Sec. 60.5412c.
(iii) If routing to a control device, conduct an initial
performance test as required in Sec. 60.5413c within 180 days after
initial startup, or by 36 months after the state plan submittal
deadline (as specified in Sec. 60.5362c(c)), whichever date is later,
or install a control device tested under Sec. 60.5413c(d) which meets
the criteria in Sec. 60.5413c(d)(11) and (e), and you must comply with
the continuous compliance requirements of Sec. 60.5415c(d).
(iv) Conduct the initial inspections of the closed vent system and
bypasses, if applicable, as required in Sec. 60.5416c(a) and (b).
(v) Install and operate the continuous parameter monitoring systems
in accordance with Sec. 60.5417c(a) through (g), as applicable.
(vi) Maintain the records as required by Sec. 60.5420c(c)(7) and
(c)(9) through (12), as applicable and submit the reports as required
by Sec. 60.5420c(b)(10) through (12), as applicable.
(12) You must tag and repair each identified leak as required in
Sec. 60.5400c(h) or Sec. 60.5400c(i), as applicable.
(13) You must submit the notice required by Sec. 60.5420c(a)(2).
[[Page 17173]]
(14) You must submit the initial semiannual report and subsequent
semiannual report as required by Sec. 60.5422c and the annual reports
in Sec. 60.5420c(b)(10)(i) through (iv), as applicable.
(15) You must maintain the records specified by Sec. 60.5421c.
(h) Storage vessel designated facility. To achieve initial
compliance with the GHG standards for each storage vessel designated
facility as required by Sec. 60.5396c, you must comply with paragraphs
(h)(1) through (9) of this section. To achieve initial compliance with
the GHG standards for each storage vessel designated facility that
complies by using a floating roof in accordance with Sec.
60.5396c(b)(2), you must comply with paragraph (h)(1) and (10) of this
section.
(1) You must determine the potential for methane emissions as
specified in Sec. 60.5386c(e)(2).
(2) You must reduce methane emissions by 95.0 percent or greater
according to Sec. 60.5396c(a) and as demonstrated by the requirements
of Sec. 60.5413c or route to a process.
(3) If you use a control device to reduce emissions, you must equip
each storage vessel in the storage vessel designated facility with a
cover that meets the requirements of Sec. 60.5411c(b), install a
closed vent system that meets the requirements of Sec. 60.5411c(a) and
(c) to capture all emissions from the storage vessel designated
facility, and route all emissions to a control device that meets the
conditions specified in Sec. 60.5412c. If you route emissions to a
process, you must equip each storage vessel in the storage vessel
affected facility with a cover that meets the requirements of Sec.
60.5411c(b), install a closed vent system that meets the requirements
of Sec. 60.5411c(a) and (c) to capture all emissions from the storage
vessel affected facility, and route all emissions to a process.
(4) If you use a control device to reduce emissions, you must
conduct an initial performance test as required in Sec. 60.5413c
within 180 days after initial startup, or within 180 days 36 months
after the state plan submittal deadline (as specified in Sec.
60.5362c(c)), whichever date is later, or install a control device
tested under Sec. 60.5413c(d) which meets the criteria in Sec.
60.5413c(d)(11) and (e), and you must comply with the continuous
compliance requirements of Sec. 60.5415c(h).
(5) You must conduct the initial inspections of the closed vent
system and bypasses, if applicable, as required in Sec. 60.5416c(a)
and (b).
(6) You must install and operate the continuous parameter
monitoring systems in accordance with Sec. 60.5417c(a) through (g), as
applicable.
(7) You must maintain the records as required by Sec.
60.5420c(c)(7) through (12), as applicable and submit the reports as
required by Sec. 60.5420c(b)(10) through (12), as applicable.
(8) You must submit the initial annual report for your storage
vessel designated facility required by Sec. 60.5420c(b)(1) and (7).
(9) You must maintain the records required for your storage vessel
designated facility, as specified in Sec. 60.5420c(c)(6) for each
storage vessel designated facility.
(10) For each storage vessel designated facility that complies by
using a floating roof, you must meet the requirements of Sec.
60.112b(a)(1) or (2) and the relevant monitoring, inspection,
recordkeeping, and reporting requirements in subpart Kb of this part.
You must submit a statement that you are complying with Sec.
60.112b(d)(a)(1) or (2) in accordance with Sec. 60.5396c(b)(2) with
the initial annual report specified in Sec. 60.5420c(b)(1) and (7).
(i) Fugitive emission components designated facility. To achieve
initial compliance with the GHG standards for fugitive emissions
components designated facilities as required by Sec. 60.5397c, you
must comply with paragraphs (i)(1) through (5) of this section.
(1) You must develop a fugitive emissions monitoring plan as
required in Sec. 60.5397c(b), (c), and (d).
(2) You must conduct an initial monitoring survey as required in
Sec. 60.5397c(e) and (f).
(3) You must repair each identified source of fugitive emissions
for each designated facility as required in Sec. 60.5397c(h).
(4) You must submit the initial annual report for each fugitive
emissions components designated facility as required in Sec.
60.5420c(b)(1) and (8).
(5) You must maintain the records specified in Sec.
60.5420c(c)(13).
Sec. 60.5411c What additional requirements must I meet to determine
initial compliance for my covers and closed vent systems?
For each cover or closed vent system at your well, centrifugal
compressor, reciprocating compressor, process controller, pump, storage
vessel, and process unit equipment designated facilities, you must
comply with the applicable requirements of paragraphs (a) through (c)
of this section.
(a) Closed vent system requirements. (1) Reciprocating compressor
rod packing, process controllers, and pumps. You must design the closed
vent system to capture and route all gases, vapors, and fumes to a
process.
(2) Associated gas wells, gas wells where liquids are being
unloaded, centrifugal compressors, reciprocating compressor rod
packing, process controllers in Alaska, pumps, storage vessels, and
process unit equipment. You must design the closed vent system to
capture and route all gases, vapors, and fumes to a process or a
control device that meets the requirements specified in Sec.
60.5412c(a) through (d) of this section. For pumps complying with Sec.
60.5395c(b)(3), you must design the closed vent system to capture and
route all gases, vapors, and fumes to a control device that meets the
requirements specified in Sec. 60.5412c(a) through (d) of this
section.
(3) You must design and operate the closed vent system with no
identifiable emissions as demonstrated by Sec. 60.5416c(a) and (b).
(4) For bypass devices, you must meet the requirements specified in
paragraphs (a)(4)(i) and (ii) of this section if the closed vent system
contains one or more bypass devices that could be used to divert all or
a portion of the gases, vapors, or fumes from entering the control
device or being routed to a process.
(i) Except as provided in paragraph (a)(4)(ii) of this section, you
must comply with either paragraph (a)(4)(i)(A) or (B) of this section
for each bypass device.
(A) You must properly install, calibrate, maintain, and operate a
flow indicator at the inlet to the bypass device. The flow indicator
must be capable of taking periodic readings as specified in Sec.
60.5416c(a)(4)(i) and sound an alarm, or initiate notification via
remote alarm to the nearest field office, when the bypass device is
open such that the stream is being, or could be, diverted away from the
control device or process, and sent to the atmosphere. You must
maintain records of each time the alarm is activated according to Sec.
60.5420c(c)(9).
(B) You must secure the bypass device valve installed at the inlet
to the bypass device in the non-diverting position using a car-seal or
a lock-and-key type configuration.
(ii) Low leg drains, high point bleeds, analyzer vents, open-ended
valves or lines, and safety devices are not subject to the requirements
of paragraph (a)(4)(i) of this section.
(b) Cover requirements for storage vessels, centrifugal
compressors, and reciprocating compressors. (1) The cover and all
openings on the cover (e.g., access hatches, sampling ports, pressure
[[Page 17174]]
relief devices and gauge wells) shall form a continuous impermeable
barrier over the entire surface area of the liquid in the storage
vessel or centrifugal compressor wet seal fluid degassing system, or
reciprocating compressor rod packing emissions collection system.
(2) Each cover opening shall be secured in a closed, sealed
position (e.g., covered by a gasketed lid or cap) whenever material is
in the unit on which the cover is installed except during those times
when it is necessary to use an opening as follows:
(i) To add material to, or remove material from the unit (this
includes openings necessary to equalize or balance the internal
pressure of the unit following changes in the level of the material in
the unit);
(ii) To inspect or sample the material in the unit;
(iii) To inspect, maintain, repair, or replace equipment located
inside the unit; or
(iv) To vent liquids, gases, or fumes from the unit through a
closed vent system designed and operated in accordance with the
requirements of paragraph (a) of this section to a control device or to
a process.
(3) Each storage vessel thief hatch shall be equipped, maintained,
and operated with a weighted mechanism or equivalent, to ensure that
the lid remains properly seated and sealed under normal operating
conditions, including such times when working, standing/breathing, and
flash emissions may be generated. You must select gasket material for
the hatch based on composition of the fluid in the storage vessel and
weather conditions.
(4) You must design and operate the cover with no identifiable
emissions as demonstrated by Sec. 60.5416c(a) and (b), except when
operated as provided in paragraphs (b)(2)(i) through (iii) of this
section.
(c) Design requirements. (1) You must conduct an assessment that
the closed vent system is of sufficient design and capacity to ensure
that all gases, vapors, and fumes from the designated facility are
routed to the control device or process and that the control device or
process is of sufficient design and capacity to accommodate all
emissions from the designated facility. The assessment must be
certified by a qualified professional engineer or an in-house engineer
with expertise on the design and operation of the closed vent system in
accordance with paragraphs (c)(1)(i) and (ii) of this section.
(i) You must provide the following certification, signed and dated
by a qualified professional engineer or an in-house engineer: ``I
certify that the closed vent system design and capacity assessment was
prepared under my direction or supervision. I further certify that the
closed vent system design and capacity assessment was conducted, and
this report was prepared pursuant to the requirements of subpart OOOOc
of this part. Based on my professional knowledge and experience, and
inquiry of personnel involved in the assessment, the certification
submitted herein is true, accurate, and complete.''
(ii) The assessment shall be prepared under the direction or
supervision of a qualified professional engineer or an in-house
engineer who signs the certification in paragraph (c)(1)(i) of this
section.
Sec. 60.5412c What additional requirements must I meet for
determining initial compliance of my control devices?
You must meet the requirements of paragraphs (a) and (b) of this
section for each control device used to comply with the emissions
standards for your well, centrifugal compressor, reciprocating
compressor, storage vessel, process controller, pump, or process unit
equipment designated facility. If you use a carbon adsorption system as
a control device to meet the requirements of paragraph (a)(2) of this
section, you also must meet the requirements in paragraph (c) of this
section.
(a) Each control device used to meet the emissions reduction
standard in Sec. 60.5390c(g) for your well designated facility gas
well that unloads liquids; Sec. 60.5391c(b) for your well designated
facility with associated gas; Sec. 60.5392c(a)(4) for your centrifugal
compressor designated facility; Sec. 60.5393c(d)(2) for your
reciprocating compressor designated facility; Sec. 60.5396c(a)(2) for
your storage vessel designated facility; Sec. 60.5394c(b)(3) for your
process controller designated facility in Alaska; Sec. 60.5395c(b)(1)
for your pumps designated facility; or either Sec. 60.5400c(f) or
Sec. 60.5401c(e) for your process equipment designated facility must
be installed according to paragraphs (a)(1) through (3) of this
section. As an alternative to paragraphs (a)(1) through (3) of this
section, you may install a control device model tested under Sec.
60.5413c(d), which meets the criteria in Sec. 60.5413c(d)(11) and
which meets the initial and continuous compliance requirements in Sec.
60.5413c(e).
(1) Each enclosed combustion device (e.g., thermal vapor
incinerator, catalytic vapor incinerator, boiler, or process heater)
must be designed and operated in accordance with paragraph (a)(1)(i) of
this section, meet one of the operating limits specified in paragraphs
(a)(1)(ii) through (v) of this section, and except for boilers and
process heaters meeting the requirements of paragraph (a)(1)(iii) of
this section and catalytic vapor incinerators meeting the requirements
of paragraph (a)(1)(v) of this section, meet the operating limits
specified in paragraphs (a)(1)(vi) through (ix) of this section.
Alternatively, the enclosed combustion device must meet the
requirements specified in paragraph (d) of this section.
(i) You must reduce the mass content of methane in the gases vented
to the device by 95.0 percent by weight or greater or reduce the
concentration of total organic compounds (TOC) in the exhaust gases at
the outlet to the device to a level equal to or less than 275 ppmv as
propane on a wet basis corrected to 3 percent oxygen as determined in
accordance with the requirements of Sec. 60.5413c(b), with the
exceptions noted in Sec. 60.5413c(a).
(ii) For an enclosed combustion device for which you demonstrate
during the performance test conducted under Sec. 60.5413c(b) that
combustion zone temperature is an indicator of destruction efficiency,
you must operate at or above the minimum temperature established during
the most recent performance test. During the performance test conducted
under Sec. 60.5413c(b), you must continuously record the temperature
of the combustion zone and average the temperature for each test run.
The established minimum temperature limit is the average of the test
run averages.
(iii) For an enclosed combustion device which is a boiler or
process heater, you must introduce the vent stream into the flame zone
of the boiler or process heater and introduce the vent stream with the
primary fuel or use the vent stream as the primary fuel.
(iv) For an enclosed combustion device other than those meeting the
operating limits in paragraphs (a)(1)(ii), (iii), and (v) of this
section, if the enclosed combustion device is unassisted or pressure-
assisted, you must maintain the net heating value (NHV) of the gas sent
to the enclosed combustion device at or above the applicable limits
specified in paragraphs (a)(1)(iv)(A) and (B) of this section. If the
enclosed combustion device is steam-assisted or air-assisted, you must
meet the applicable limits specified in paragraphs (a)(1)(iv)(C) and
(D) of this section, as appropriate.
(A) For enclosed combustion devices that do not use assist gas or
pressure-assisted burner tips to promote mixing at the burner tip, 200
British thermal units (Btu) per standard cubic feet (Btu/scf).
[[Page 17175]]
(B) For enclosed combustion devices that use pressure-assisted
burner tips to promote mixing at the burner tip, 800 Btu/scf.
(C) For steam-assisted and air-assisted enclosed combustion
devices, maintain the combustion zone NHV (NHVcz) at or
above 270 Btu/scf.
(D) For enclosed combustion devices with perimeter assist air,
maintain the NHV dilution parameter (NHVdil) at or above 22
British thermal units per square foot (Btu/sqft). If the only assist
air provided to the enclosed combustion control device is perimeter
assist air intentionally entrained in lower and/or upper steam at the
burner tip and the effective diameter is 9 inches or greater, you are
only required to comply with the NHVcz limit specified in
paragraph (a)(1)(iv)(C) of this section.
(v) For an enclosed combustion device which is a catalytic vapor
incinerator, you must operate the catalytic vapor incinerator at or
above the minimum temperature of the catalyst bed inlet and at or above
the minimum temperature differential between the catalyst bed inlet and
the catalyst bed outlet established in accordance with Sec.
60.5417c(f) and as determined in your performance test conducted in
accordance with Sec. 60.5413c(b).
(vi) Unless you have an enclosed combustion device with pressure-
assisted burner tips to promote mixing at the burner tip, you must
operate each enclosed combustion control device at or below the maximum
inlet gas flow rate established in accordance with Sec. 60.5417c(f)
and as determined in your performance test conducted in accordance with
Sec. 60.5413c(b).
(vii) You must operate the combustion control device at or above
the minimum inlet gas flow rate established in accordance with Sec.
60.5417c(f).
(viii) You must install and operate a continuous burning pilot or
combustion flame. An alert must be sent to the nearest control room
whenever the pilot or combustion flame is unlit.
(ix) You must operate the enclosed combustion device with no
visible emissions, except for periods not to exceed a total of 1 minute
during any 15-minute period. A visible emissions test using section 11
of Method 22 of appendix A-7 to this part must be performed at least
once every calendar month, separated by at least 15 days between each
test. The observation period shall be 15 minutes or once the amount of
time visible emissions is present has exceeded 1 minute, whichever time
period is less. Alternatively, you may conduct visible emissions
monitoring according to Sec. 60.5417c(h). Devices failing the visible
emissions test must follow manufacturer's repair instructions, if
available, or best combustion engineering practice as outlined in the
unit inspection and maintenance plan, to return the unit to compliant
operation. All inspection, repair, and maintenance activities for each
unit must be recorded in a maintenance and repair log and must be
available for inspection. Following return to operation from
maintenance or repair activity, each device must pass a Method 22 of
appendix A-7 to this part visual observation as described in this
paragraph or be monitored according to Sec. 60.5417c(h).
(2) Each vapor recovery device (e.g., carbon adsorption system or
condenser) or other non-destructive control device must be designed and
operated to reduce the mass content of methane in the gases vented to
the device by 95.0 percent by weight or greater as determined in
accordance with the requirements of Sec. 60.5413c(b). As an
alternative to the performance testing requirements of Sec.
60.5413c(b), you may demonstrate initial compliance by conducting a
design analysis for vapor recovery devices according to the
requirements of Sec. 60.5413c(c). For a condenser, you also must
calculate the daily average condenser outlet temperature in accordance
with Sec. 60.5417c(e), and you must determine the condenser efficiency
for the current operating day using the daily average condenser outlet
temperature and the condenser performance curve established in
accordance with Sec. 60.5417c(f)(2). You must determine the average
TOC emission reduction in accordance with Sec. 60.5415c(e)(1)(ix)(D).
For a carbon adsorption system, you also must comply with paragraph (c)
of this section.
(3) Each flare must be designed and operated according to the
requirements specified in paragraphs (a)(3)(i) through (viii) of this
section, as applicable. Alternatively, flares must meet the
requirements specified in paragraph (d) of this section.
(i) For unassisted flares, you must maintain the NHV of the vent
gas sent to the flare at or above 200 Btu/scf.
(ii) For flares that use pressure-assisted burner tips to promote
mixing at the burner tip, you must maintain the NHV of the vent gas
sent to the flare at or above 800 Btu/scf.
(iii) For steam-assisted and air-assisted flares, you must maintain
the NHVcz at or above 270 Btu/scf.
(iv) For flares with perimeter assist air, you must maintain the
NHVdil at or above 22 Btu/sqft. If the only assist air provided to the
flare is perimeter assist air intentionally entrained in lower and/or
upper steam at the flare tip and the effective diameter is 9 inches or
greater, you are not required to comply with the NHVdil limit.
(v) For flares other than pressure-assisted flares, you must
determine the maximum flow rate of vent gas to the control system based
on the design considerations of the designated facilities to
demonstrate compliance with the flare tip velocity limits in Sec.
60.18(b) according to Sec. 60.5417c(d)(8)(iv). The maximum flare tip
velocity limits do not apply for pressure-assisted flares.
(vi) You must operate the flare at or above the minimum inlet gas
flow rate. The minimum inlet gas flow rate is established based on
manufacturer recommendations.
(vii) You must operate the flare with no visible emissions, except
for periods not to exceed a total of 1 minute during any 15-minute
period. You must conduct the compliance determination with the visible
emission limits using Method 22 of appendix A-7 to this part, or you
must monitor the flare according to Sec. 60.5417c(h).
(viii) You must install and operate a continuous burning pilot or
combustion flame. An alert must be sent to the nearest control room
whenever the pilot flame is unlit.
(b) You must operate each control device installed on your well,
centrifugal compressor, reciprocating compressor, storage vessel,
process controller, pump, or process unit equipment designated facility
in accordance with the requirements specified in paragraphs (b)(1) and
(2) of this section.
(1) You must operate each control device used to comply with this
subpart at all times when gases, vapors, and fumes are vented from the
designated facility through the closed vent system to the control
device. You may vent more than one designated facility to a control
device used to comply with this subpart.
(2) For each control device monitored in accordance with the
requirements of Sec. 60.5417c(a) through (i), you must demonstrate
compliance according to the requirements of Sec. 60.5415c(e), as
applicable.
(c) For each carbon adsorption system used as a control device to
meet the requirements of paragraph (a)(2) of this section, you must
comply with the requirements of paragraph (c)(1) of this section. If
the carbon adsorption system is a regenerative-type carbon adsorption
system, you also must comply with the
[[Page 17176]]
requirements of paragraph (c)(2) of this section.
(1) You must manage the carbon in accordance with the requirements
specified in paragraphs (c)(1)(i) and (ii) of this section.
(i) Following the initial startup of the control device, you must
replace all carbon in the carbon adsorption system with fresh carbon on
a regular, predetermined time interval that is no longer than the
carbon service life established according to Sec. 60.5413c(c)(2) or
(3). You must maintain records identifying the schedule for replacement
and records of each carbon replacement as required in Sec.
60.5420c(c)(9) and (11).
(ii) You must either regenerate, reactivate, or burn the spent
carbon removed from the carbon adsorption system in one of the units
specified in paragraphs (c)(1)(ii)(A) through (F) of this section.
(A) Regenerate or reactivate the spent carbon in a unit for which
you have been issued a final permit under 40 CFR part 270 that
implements the requirements of 40 CFR part 264, subpart X.
(B) Regenerate or reactivate the spent carbon in a unit equipped
with an operating organic air emissions control in accordance with an
emissions standard for VOC under another subpart in 40 CFR part 63 or
this part.
(C) Burn the spent carbon in a hazardous waste incinerator for
which the owner or operator complies with the requirements of 40 CFR
part 63, subpart EEE, and has submitted a Notification of Compliance
under 40 CFR 63.1207(j).
(D) Burn the spent carbon in a hazardous waste boiler or industrial
furnace for which the owner or operator complies with the requirements
of 40 CFR part 63, subpart EEE, and has submitted a Notification of
Compliance under 40 CFR 63.1207(j).
(E) Burn the spent carbon in an industrial furnace for which you
have been issued a final permit under 40 CFR part 270 that implements
the requirements of 40 CFR part 266, subpart H.
(F) Burn the spent carbon in an industrial furnace that you have
designed and operated in accordance with the interim status
requirements of 40 CFR part 266, subpart H.
(2) You must comply with the requirements of paragraph (c)(2)(i)
through (iii) of this section for each regenerative-type carbon
adsorption system.
(i) You must measure and record the average total regeneration
stream mass flow or volumetric flow during each carbon bed regeneration
cycle to demonstrate compliance with the total regeneration stream flow
established in accordance with Sec. 60.5413c(c)(2).
(ii) You must check the mechanical connections for leakage at least
every month, and you must perform a visual inspection at least every 3
months of all components of the flow continuous parameter monitoring
system for physical and operational integrity and all electrical
connections for oxidation and galvanic corrosion, if your continuous
parameter monitoring system is not equipped with a redundant flow
sensor.
(iii) You must measure and record the average carbon bed
temperature for the duration of the carbon bed steaming cycle and
measure the actual carbon bed temperature after regeneration and within
15 minutes of completing the cooling cycle. You must maintain the
average carbon bed temperature above the temperature limit in
established accordance with Sec. 60.5413c(c)(2) during the carbon bed
steaming cycle and below the carbon bed temperature established in in
accordance with Sec. 60.5413c(c)(2) after the regeneration cycle.
(d) To demonstrate that a flare or enclosed combustion device
reduces methane in the gases vented to the device by 95.0 percent by
weight or greater, as outlined in Sec. 60.8(b), you may submit a
request for an alternative test method. At a minimum, the request must
follow the requirements outlined in paragraphs (d)(1) through (5) of
this section.
(1) The alternative method must be capable of demonstrating
continuous compliance with a combustion efficiency of 95.0 percent or
greater or it must be capable of demonstrating continuous compliance
with the following metrics:
(i) NHVcz of 270 Btu/scf or greater.
(ii) NHVdil of 22 Btu/sqft or greater, if the
alternative test method will be used for enclosed combustion devices or
flares with perimeter assist air.
(2) The alternative method must be validated according to Method
301 in appendix A to 40 CFR part 63 for each type of control device
covered by the alternative test method (e.g., air-assisted flare,
unassisted enclosed combustion device) or the alternative test method
must contain performance-based procedures and indicators to ensure
self-validation.
(3) At a minimum the alternative test method must provide a reading
for each successive 15-minute period.
(4) The alternative test method must be capable of documenting
periods when the enclosed combustion device or flare operates with
visible emissions. If the alternative test method cannot identify
periods of visible emissions, you must conduct the inspections required
by Sec. 60.5417c(d)(8)(v).
(5) If the alternative test method demonstrates compliance with the
metrics specified in paragraphs (d)(1)(i) and (ii) of this section
instead of demonstrating continuous compliance with 95.0 percent or
greater combustion efficiency, you must still install the pilot or
combustion flame monitoring system required by Sec. 60.5417c(d)(8)(i).
If the alternative test method demonstrates continuous compliance with
a combustion efficiency of 95.0 percent or greater, the requirement in
Sec. 60.5417c(d)(8)(i) no longer applies.
Sec. 60.5413c What are the performance testing procedures for
control devices?
This section applies to the performance testing of control devices
used to demonstrate compliance with the emissions standards for your
well, centrifugal compressor, reciprocating compressor, storage vessel,
process controller, pump designated facilities complying with Sec.
60.5393c(b)(1), or process unit equipment designated facility. You must
demonstrate that a control device achieves the performance requirements
of Sec. 60.5412c(a)(1) or (2) using the performance test methods and
procedures specified in this section. For condensers and carbon
adsorbers, you may use a design analysis as specified in paragraph (c)
of this section in lieu of complying with paragraph (b) of this
section. In addition, this section contains the requirements for
enclosed combustion device performance tests conducted by the
manufacturer applicable to well, centrifugal compressor, reciprocating
compressor, storage vessel, process controller, pump designated
facilities complying with Sec. 60.5393c(b)(1), or process unit
equipment designated facilities.
(a) Performance test exemptions. You are exempt from the
requirements to conduct initial and periodic performance tests and
design analyses if you use any of the control devices described in
paragraphs (a)(1) through (6) of this section. You are exempt from the
requirements to conduct an initial performance test if you use a
control device described in paragraph (a)(7) of this section.
(1) A flare that is designed and operated in accordance with the
requirements in Sec. 60.5412c(a)(3). You must conduct the compliance
determination using Method 22 of appendix A-7 to this part to determine
visible emissions or monitor the flare according to Sec. 60.5417c(h).
The net heating value of the vent gas must be
[[Page 17177]]
determined according to Sec. 60.5417c(d)(8)(ii).
(2) A boiler or process heater with a design heat input capacity of
44 megawatts or greater.
(3) A boiler or process heater into which the vent stream is
introduced with the primary fuel or is used as the primary fuel.
(4) A boiler or process heater burning hazardous waste for which
you have been issued a final permit under 40 CFR part 270 and comply
with the requirements of 40 CFR part 266, subpart H; you have certified
compliance with the interim status requirements of 40 CFR part 266,
subpart H; you have submitted a Notification of Compliance under 40 CFR
63.1207(j) and comply with the requirements of 40 CFR part 63, subpart
EEE; or you comply with 40 CFR part 63, subpart EEE, and will submit a
Notification of Compliance under 40 CFR 63.1207(j) by the date
specified in Sec. 60.5420c(b)(11) for submitting the initial
performance test report.
(5) A hazardous waste incinerator for which you have submitted a
Notification of Compliance under 40 CFR 63.1207(j), or for which you
will submit a Notification of Compliance under 40 CFR 63.1207(j) by the
date specified in Sec. 60.5420c(b)(11) for submitting the initial
performance test report, and you comply with the requirements of 40 CFR
part 63, subpart EEE.
(6) A control device for which performance test is waived in
accordance with Sec. 60.8(b).
(7) A control device whose model can be demonstrated to meet the
performance requirements of Sec. 60.5412c(a)(1)(i) through a
performance test conducted by the manufacturer, as specified in
paragraph (d) of this section.
(b) Test methods and procedures. You must use the test methods and
procedures specified in paragraphs (b)(1) through (4) of this section,
as applicable, for each performance test conducted to demonstrate that
a control device meets the requirements of Sec. 60.5412c(a)(1) or (2).
You must conduct the initial and periodic performance tests according
to the schedule specified in paragraph (b)(5) of this section. Each
performance test must consist of a minimum of 3 test runs. Each run
must be at least 1 hour long.
(1) You must use Method 1 or 1A of appendix A-1 to this part, as
appropriate, to select the sampling sites. Any references to
particulate mentioned in Methods 1 and 1A do not apply to this section.
(i) Sampling sites must be located at the inlet of the first
control device and at the outlet of the final control device to
determine compliance with a control device percent reduction
requirement.
(ii) The sampling site must be located at the outlet of the
combustion device to determine compliance with a TOC exhaust gas
concentration limit.
(2) You must determine the gas volumetric flow rate using Method 2,
2A, 2C, or 2D of appendix A-2 of this part, as appropriate.
(3) To determine compliance with the control device percent
reduction performance requirement in Sec. 60.5412c(a)(1)(i) or (a)(2),
you must use Method 18 of appendix A-6 to this part, Method 320 of
appendix A to 40 CFR part 63, or ASTM D6348-12e1(incorporated by
reference, see Sec. 60.17) to measure methane or Method 25A of
appendix A-7 to this part to measure TOC, as propane. You must use
Method 4 of appendix A-3 to this part to convert the Method 25A results
to a dry basis. You must use the procedures in paragraphs (b)(3)(i)
through (iii) of this section to calculate percent reduction
efficiency.
(i) You must compute the mass rate of methane or TOC using the
following equations:
[GRAPHIC] [TIFF OMITTED] TR08MR24.038
Where:
Ei, Eo = Mass rate of methane or TOC at the
inlet and outlet of the control device, respectively, dry basis,
kilograms per hour.
K2 = Constant, 2.494 x 10-6 (parts per
million) (gram-mole per standard cubic meter) (kilogram/gram)
(minute/hour), where standard temperature (gram-mole per standard
cubic meter) is 20[deg] degrees Celsius.
Ci, Co = Concentration of methane of the gas
stream as measured by Method 18 of appendix A-6, Method 320 of
appendix A to 40 CFR part 63, or ASTM D6348-12e1 or TOC, as propane,
of the gas stream as measured by Method 25A of appendix A-7 to this
part at the inlet and outlet of the control device, respectively,
dry basis, parts per million by volume.
Mp = Molecular weight of methane, if using Method 18 of
appendix A-6 to this part, Method 320 of appendix A to 40 CFR part
63, or ASTM D6348-12e1, 16.04 gram/gram-mole. Molecular weight of
propane, if using Method 25A of appendix A-7 to this part, 44.1
gram/gram-mole.
Qi, Qo = Flow rate of gas stream at the inlet
and outlet of the control device, respectively, dry standard cubic
meter per minute.
(ii) You must calculate the percent reduction in TOC as follows:
[GRAPHIC] [TIFF OMITTED] TR08MR24.039
Where:
Rcd = Control efficiency of control device, percent.
Ei = Mass rate of methane or TOC at the inlet to the
control device as calculated under paragraph (b)(3)(i) of this
section, kilograms per hour.
Eo = Mass rate of methane or TOC at the outlet of the
control device, as calculated under paragraph (b)(3)(i) of this
section, kilograms per hour.
(iii) If the vent stream entering a boiler or process heater with a
design
[[Page 17178]]
capacity less than 44 megawatts is introduced with the combustion air
or as a secondary fuel, you must determine the weight-percent reduction
of methane across the device by comparing the methane in all combusted
vent streams and primary and secondary fuels with the methane exiting
the device, respectively.
(4) You must use Method 25A of appendix A-7 to this part to measure
TOC, as propane, to determine compliance with the TOC exhaust gas
concentration limit specified in Sec. 60.5412c(a)(1)(i). You must
determine the concentration in parts per million by volume on a wet
basis and correct it to 3 percent oxygen. You must use the emission
rate correction factor for excess air, integrated sampling and analysis
procedures of Method 3A or 3B of appendix A-2 to this part, ASTM D6522-
20, or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion only) (both
incorporated by reference, see Sec. 60.17) to determine the oxygen
concentration. The samples must be taken during the same time that the
samples are taken for determining TOC concentration. You must correct
the TOC concentration for percent oxygen as follows:
[GRAPHIC] [TIFF OMITTED] TR08MR24.040
Where:
Cc = TOC concentration, as propane, corrected to 3
percent oxygen, parts per million by volume on a wet basis.
Cm = TOC concentration, as propane, parts per million by
volume on a wet basis.
%O2m = Concentration of oxygen, percent by volume as
measured, wet.
(5) You must conduct performance tests according to the schedule
specified in paragraphs (b)(5)(i) through (iii) of this section.
(i) You must conduct an initial performance test within 180 days
after initial startup for your designated facility. You must submit the
performance test results as required in Sec. 60.5420c(b)(11).
(ii) You must conduct periodic performance tests for all control
devices required to conduct initial performance tests. You must conduct
the first periodic performance test no later than 60 months after the
initial performance test required in paragraph (b)(5)(i) of this
section. You must conduct subsequent periodic performance tests at
intervals no longer than 60 months following the previous periodic
performance test or whenever you desire to establish a new operating
limit. If a control device is not operational at the time a performance
test is due, you must conduct the performance test no later than 30
calendar days after returning the control device to service. You must
submit the periodic performance test results as specified in Sec.
60.5420c(b)(11).
(iii) If the initial performance test was conducted by the
manufacturer under paragraph (d) of this section, you must conduct the
first periodic performance test no later than 60 months after initial
installation and startup of the control device. You must conduct
subsequent periodic performance tests at intervals no longer than 60
months following the previous periodic performance test. If a control
device is not operational at the time a performance test is due, you
must conduct the performance test no later than 30 calendar days after
returning the control device to service. You must submit the periodic
performance test results as specified in Sec. 60.5420c(b)(11).
(c) Control device design analysis to meet the requirements of
Sec. 60.5412c(a)(2). (1) For a condenser, the design analysis must
include an analysis of the vent stream composition, constituent
concentrations, flow rate, relative humidity, and temperature and must
establish the design outlet organic compound concentration level,
design average temperature of the condenser exhaust vent stream and the
design average temperatures of the coolant fluid at the condenser inlet
and outlet.
(2) For a regenerable carbon adsorption system, the design analysis
shall include the vent stream composition, constituent concentrations,
flow rate, relative humidity and temperature and shall establish the
design exhaust vent stream organic compound concentration level,
adsorption cycle time, number and capacity of carbon beds, type and
working capacity of activated carbon used for the carbon beds, design
total regeneration stream flow over the period of each complete carbon
bed regeneration cycle, design carbon bed temperature after
regeneration, design carbon bed regeneration time and design service
life of the carbon.
(3) For a nonregenerable carbon adsorption system, such as a carbon
canister, the design analysis shall include the vent stream
composition, constituent concentrations, flow rate, relative humidity
and temperature and shall establish the design exhaust vent stream
organic compound concentration level, capacity of the carbon bed, type
and working capacity of activated carbon used for the carbon bed and
design carbon replacement interval based on the total carbon working
capacity of the control device and source operating schedule. In
addition, these systems shall incorporate dual carbon canisters in case
of emission breakthrough occurring in one canister.
(4) If you and the Administrator do not agree on a demonstration of
control device performance using a design analysis, then you must
perform a performance test in accordance with the requirements of
paragraph (b) of this section to resolve the disagreement. The
Administrator may choose to have an authorized representative observe
the performance test.
(d) Performance testing for combustion control devices--
manufacturers' performance test. (1) This paragraph (d) applies to the
performance testing of a combustion control device conducted by the
device manufacturer. The manufacturer must demonstrate that a specific
model of control device achieves the performance requirements in
paragraph (d)(11) of this section by conducting a performance test as
specified in paragraphs (d)(2) through (10) of this section. You must
submit a test report for each combustion control device in accordance
with the requirements in paragraph (d)(12) of this section.
(2) Performance testing must consist of three 1-hour (or longer)
test runs for each of the four firing rate settings specified in
paragraphs (d)(2)(i) through (iv) of this section, making a total of 12
test runs per test. Propene (propylene) gas must be used for the
testing fuel. All fuel analyses must be performed by an independent
third-party laboratory (not affiliated with the control device
manufacturer or fuel supplier).
(i) 90-100 percent of maximum design rate (fixed rate).
[[Page 17179]]
(ii) 70-100-70 percent (ramp up, ramp down). Begin the test at 70
percent of the maximum design rate. During the first 5 minutes,
incrementally ramp the firing rate to 100 percent of the maximum design
rate. Hold at 100 percent for 5 minutes. In the 10 to 15-minute time
range, incrementally ramp back down to 70 percent of the maximum design
rate. Repeat three more times for a total of 60 minutes of sampling.
(iii) 30-70-30 percent (ramp up, ramp down). Begin the test at 30
percent of the maximum design rate. During the first 5 minutes,
incrementally ramp the firing rate to 70 percent of the maximum design
rate. Hold at 70 percent for 5 minutes. In the 10 to 15-minute time
range, incrementally ramp back down to 30 percent of the maximum design
rate. Repeat three more times for a total of 60 minutes of sampling.
(iv) 0-30-0 percent (ramp up, ramp down). Begin the test at the
minimum firing rate. During the first 5 minutes, incrementally ramp the
firing rate to 30 percent of the maximum design rate. Hold at 30
percent for 5 minutes. In the 10 to 15-minute time range, incrementally
ramp back down to the minimum firing rate. Repeat three more times for
a total of 60 minutes of sampling.
(3) All models employing multiple enclosures must be tested
simultaneously and with all burners operational. Results must be
reported for each enclosure individually and for the average of the
emissions from all interconnected combustion enclosures/chambers.
Control device operating data must be collected continuously throughout
the performance test using an electronic Data Acquisition System. A
graphic presentation or strip chart of the control device operating
data and emissions test data must be included in the test report in
accordance with paragraph (d)(12) of this section. Inlet fuel meter
data may be manually recorded provided that all inlet fuel data
readings are included in the final report.
(4) Inlet testing must be conducted as specified in paragraphs
(d)(4)(i) and (ii) of this section.
(i) The inlet gas flow metering system must be located in
accordance with Method 2A of appendix A-1 to this part (or other
approved procedure) to measure inlet gas flow rate at the control
device inlet location. You must position the fitting for filling fuel
sample containers a minimum of eight pipe diameters upstream of any
inlet gas flow monitoring meter.
(ii) Inlet flow rate must be determined using Method 2A of appendix
A-1 to this part. Record the start and stop reading for each 60-minute
THC test. Record the gas pressure and temperature at 5-minute intervals
throughout each 60-minute test.
(5) Inlet gas sampling must be conducted as specified in paragraphs
(d)(5)(i) and (ii) of this section.
(i) At the inlet gas sampling location, securely connect a fused
silica-coated stainless steel evacuated canister fitted with a flow
controller sufficient to fill the canister over a 3-hour period.
Filling must be conducted as specified in paragraphs (d)(5)(i)(A)
through (C) of this section.
(A) Open the canister sampling valve at the beginning of each test
run and close the canister at the end of each test run.
(B) Fill one canister across the three test runs such that one
composite fuel sample exists for each test condition.
(C) Label the canisters individually and record sample information
on a chain of custody form.
(ii) Analyze each inlet gas sample using the methods in paragraphs
(d)(5)(ii)(A) through (C) of this section. You must include the results
in the test report required by paragraph (d)(12) of this section.
(A) Hydrocarbon compounds containing between one and five atoms of
carbon plus benzene using ASTM D1945-03(R2010) (incorporated by
reference, see Sec. 60.17).
(B) Hydrogen (H2), carbon monoxide (CO), carbon dioxide
(CO2), nitrogen (N2), oxygen (O2)
using ASTM D1945-03(R2010) (incorporated by reference, see Sec.
60.17).
(C) Higher heating value using ASTM D3588-98(R2003) or ASTM D4891-
89(R2006) (incorporated by reference, see Sec. 60.17).
(6) Outlet testing must be conducted in accordance with the
criteria in paragraphs (d)(6)(i) through (v) of this section.
(i) Sample and flow rate must be measured in accordance with
paragraphs (d)(6)(i)(A) and (B) of this section.
(A) The outlet sampling location must be a minimum of four
equivalent stack diameters downstream from the highest peak flame or
any other flow disturbance, and a minimum of one equivalent stack
diameter upstream of the exit or any other flow disturbance. A minimum
of two sample ports must be used.
(B) Flow rate must be measured using Method 1 of appendix A-1 to
this part for determining flow measurement traverse point location, and
Method 2 of appendix A-1 to this part for measuring duct velocity. If
low flow conditions are encountered (i.e., velocity pressure
differentials less than 0.05 inches of water) during the performance
test, a more sensitive manometer must be used to obtain an accurate
flow profile.
(ii) Molecular weight and excess air must be determined as
specified in paragraph (d)(7) of this section.
(iii) Carbon monoxide must be determined as specified in paragraph
(d)(8) of this section.
(iv) THC must be determined as specified in paragraph (d)(9) of
this section.
(v) Visible emissions must be determined as specified in paragraph
(d)(10) of this section.
(7) Molecular weight and excess air determination must be performed
as specified in paragraphs (d)(7)(i) through (iii) of this section.
(i) An integrated bag sample must be collected during the moisture
test required by Method 4 of appendix A-3 to this part following the
procedure specified in (d)(7)(i)(A) and (B) of this section. Analyze
the bag sample using a gas chromatograph-thermal conductivity detector
(GC-TCD) analysis meeting the criteria in paragraphs (d)(7)(i)(C) and
(D) of this section.
(A) Collect the integrated sample throughout the entire test and
collect representative volumes from each traverse location.
(B) Purge the sampling line with stack gas before opening the valve
and beginning to fill the bag. Clearly label each bag and record sample
information on a chain of custody form.
(C) The bag contents must be vigorously mixed prior to the gas
chromatograph analysis.
(D) The GC-TCD calibration procedure in Method 3C of appendix A-2
to this part must be modified as follows: For the initial calibration,
triplicate injections of any single concentration must agree within 5
percent of their mean to be valid. The calibration response factor for
a single concentration re-check must be within 10 percent of the
original calibration response factor for that concentration. If this
criterion is not met, repeat the initial calibration using at least
three concentration levels.
(ii) Calculate and report the molecular weight of oxygen, carbon
dioxide, methane and nitrogen in the integrated bag sample and include
in the test report specified in paragraph (d)(12) of this section.
Moisture must be determined using Method 4 of appendix A-3 to this
part. Traverse both ports with the sampling train required by Method 4
of appendix A-3 to this part during each test run. Ambient air must not
be introduced into the integrated bag sample required by Method 3C of
[[Page 17180]]
appendix A-2 to this part during the port change.
(iii) Excess air must be determined using resultant data from the
Method 3C tests and Method 3B of appendix A-2 to this part, equation
3B-1, or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion only)
(incorporated by reference, see Sec. 60.17).
(8) Carbon monoxide must be determined using Method 10 of appendix
A-4 of this part. Run the test simultaneously with Method 25A of
appendix A-7 to this part using the same sampling points. An instrument
range of 0-10 parts per million by volume-dry (ppmvd) is recommended.
(9) Total hydrocarbon determination must be performed as specified
by in paragraphs (d)(9)(i) through (vii) of this section.
(i) Conduct THC sampling using Method 25A of appendix A-7 to this
part, except that the option for locating the probe in the center 10
percent of the stack is not allowed. The THC probe must be traversed to
16.7 percent, 50 percent, and 83.3 percent of the stack diameter during
each test run.
(ii) A valid test must consist of three Method 25A tests, each no
less than 60 minutes in duration.
(iii) A 0 to 10 parts per million by volume-wet (ppmvw) (as
propane) measurement range is preferred; as an alternative a 0 to 30
ppmvw (as propane) measurement range may be used.
(iv) Calibration gases must be propane in air and be certified
through EPA-600/R-12/531--``EPA Traceability Protocol for Assay and
Certification of Gaseous Calibration Standards,'' (incorporated by
reference, see Sec. 60.17).
(v) THC measurements must be reported in terms of ppmvw as propane.
(vi) THC results must be corrected to 3 percent CO2, as
measured by Method 3C of appendix A-2 to this part. You must use the
following equation for this diluent concentration correction:
[GRAPHIC] [TIFF OMITTED] TR08MR24.041
Where:
Cmeas = The measured concentration of the pollutant.
CO2meas = The measured concentration of the
CO2 diluent.
3 = The corrected reference concentration of CO2 diluent.
Ccorr = The corrected concentration of the pollutant.
(vii) Subtraction of methane or ethane from the THC data is not
allowed in determining results.
(10) Visible emissions must be determined using Method 22 of
appendix A-7 to this part. The test must be performed continuously
during each test run. A digital color photograph of the exhaust point,
taken from the position of the observer and annotated with date and
time, must be taken once per test run and the 12 photos included in the
test report specified in paragraph (d)(12) of this section.
(11) For performance test criteria:
(i) The control device model tested must meet the criteria in
paragraphs (d)(11)(i)(A) through (D) of this section. These criteria
must be reported in the test report required by paragraph (d)(12) of
this section.
(A) Results from Method 22 of appendix A-7 to this part determined
under paragraph (d)(10) of this section with no indication of visible
emissions.
(B) Average results from Method 25A of appendix A-7 to this part
determined under paragraph (d)(9) of this section equal to or less than
10.0 ppmvw THC as propane corrected to 3.0 percent CO2.
(C) Average CO emissions determined under paragraph (d)(8) of this
section equal to or less than 10 parts ppmvd, corrected to 3.0 percent
CO2.
(D) Excess air determined under paragraph (d)(7) of this section
equal to or greater than 150 percent.
(ii) The manufacturer must determine a minimum inlet gas flow rate
above which each control device model must be operated to achieve the
criteria in paragraph (d)(11)(iii) of this section. The manufacturer
must determine a maximum inlet gas flow rate which must not be exceeded
for each control device model to achieve the criteria in paragraph
(d)(11)(iii) of this section. The minimum and maximum inlet gas flow
rate must be included in the test report required by paragraph (d)(12)
of this section.
(iii) A manufacturer must demonstrate a destruction efficiency of
at least 95.0 percent for THC, as propane. A control device model that
demonstrates a destruction efficiency of 95.0 percent for THC, as
propane, will meet the control requirement for 95.0 percent destruction
of methane required under this subpart.
(12) The owner or operator of a combustion control device model
tested under this paragraph (d)(12) must submit the information listed
in paragraphs (d)(12)(i) through (vi) of this section for each test run
in the test report required by this section in accordance with Sec.
60.5420c(b)(12). Owners or operators who claim that any of the
performance test information being submitted is confidential business
information (CBI) must submit a complete file including information
claimed to be CBI to the OAQPS CBI office. The preferred method to
receive CBI is for it to be transmitted electronically using email
attachments, File Transfer Protocol, or other online file sharing
services. Electronic submissions must be transmitted directly to the
OAQPS CBI Office at the email address [email protected] and should
include clear CBI markings and be flagged to the attention of the
Leader, Measurement Policy Group. If assistance is needed with
submitting large electronic files that exceed the file size limit for
email attachments, and if you do not have your own file sharing
service, please email [email protected] to request a file transfer link.
If you cannot transmit the file electronically, you may send CBI
information through the postal service to the following address: U.S.
EPA, Attn: OAQPS Document Control Officer and Measurement Policy Group
Leader, Mail Drop: C404-02, 109 T.W. Alexander Drive, P.O. Box 12055,
RTP, North Carolina 27711. The mailed CBI material should be double
wrapped and clearly marked. Any CBI markings should not show through
the outer envelope. The same file with the CBI omitted must be
submitted to [email protected].
(i) A full schematic of the control device and dimensions of the
device components.
(ii) The maximum net heating value of the device.
(iii) The test fuel gas flow range (in both mass and volume).
Include the minimum and maximum allowable inlet gas flow rate.
(iv) The air/stream injection/assist ranges, if used.
(v) The test conditions listed in paragraphs (d)(12)(v)(A) through
(O) of
[[Page 17181]]
this section, as applicable for the tested model.
(A) Fuel gas delivery pressure and temperature.
(B) Fuel gas moisture range.
(C) Purge gas usage range.
(D) Condensate (liquid fuel) separation range.
(E) Combustion zone temperature range. This is required for all
devices that measure this parameter.
(F) Excess air range.
(G) Flame arrestor(s).
(H) Burner manifold.
(I) Continuous pilot flame indicator.
(J) Pilot flame design fuel and calculated or measured fuel usage.
(K) Tip velocity range.
(L) Momentum flux ratio.
(M) Exit temperature range.
(N) Exit flow rate.
(O) Wind velocity and direction.
(vi) The test report must include all calibration quality
assurance/quality control data, calibration gas values, gas cylinder
certification, strip charts, or other graphic presentations of the data
annotated with test times and calibration values.
(e) Initial and continuous compliance for combustion control
devices tested by the manufacturer in accordance with paragraph (d) of
this section. This paragraph (e) applies to the demonstration of
compliance for a combustion control device tested under the provisions
in paragraph (d) of this section. Owners or operators must demonstrate
that a control device achieves the performance criteria in paragraph
(d)(11) of this section by installing a device tested under paragraph
(d) of this section, complying with the criteria specified in
paragraphs (e)(1) through (10) of this section, maintaining the records
specified in Sec. 60.5420c(c)(10) and submitting the report specified
in Sec. 60.5420c(b)(10)(v) and (b)(12).
(1) The inlet gas flow rate must be equal to or greater than the
minimum inlet gas flow rate and equal to or less than the maximum inlet
gas flow rate specified by the manufacturer.
(2) A pilot or combustion flame must be present at all times of
operation. An alert must be sent to the nearest control room whenever
the pilot or combustion flame is unlit.
(3) Devices must be operated with no visible emissions, except for
periods not to exceed a total of 1 minute during any 15-minute period.
A visible emissions test conducted according to section 11 of Method 22
of appendix A-7 to this part must be performed at least once every
calendar month, separated by at least 15 days between each test. The
observation period shall be 15 minutes or once the amount of time
visible emissions is present has exceeded 1 minute, whichever time
period is less. Alternatively, you may conduct visible emissions
monitoring according to Sec. 60.5417c(h).
(4) Devices failing the visible emissions test must follow
manufacturer's repair instructions, if available, or best combustion
engineering practice as outlined in the unit inspection and maintenance
plan, to return the unit to compliant operation. All repairs and
maintenance activities for each unit must be recorded in a maintenance
and repair log and must be available for inspection.
(5) Following return to operation from maintenance or repair
activity, each device must pass a visual observation according to
Method 22 of appendix A-7 to this part as described in paragraph (e)(3)
of this section or be monitored according to Sec. 60.5417c(h).
(6) If the owner or operator operates a combustion control device
model tested under this section, an electronic copy of the performance
test results required by this section shall be submitted via email to
[email protected] unless the test results for that model of
combustion control device are posted at the following website: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.
(7) Ensure that each enclosed combustion device is maintained in a
leak free condition.
(8) Operate each control device following the manufacturer's
written operating instructions, procedures, and maintenance schedule to
ensure good air pollution control practices for minimizing emissions.
(9) Install and operate the continuous parameter monitoring systems
in accordance with Sec. 60.5417c(a) and (c) through (i).
(10) Comply with the applicable NHV limit specified in Sec.
60.5412c(a)(1)(iv).
Model Rule--Continuous Compliance Requirements
Sec. 60.5415c How do I demonstrate continuous compliance with the
standards for each of my designated facilities?
(a) Gas well liquids unloading standards for well designated
facility. For each well liquids unloading operation at your well
designated facility, you must demonstrate continuous compliance with
the requirements of Sec. 60.5390c by submitting the annual report
information specified in Sec. 60.5420c(b)(1) and (2) and maintaining
the records for each well liquids unloading event that vents to the
atmosphere as specified in Sec. 60.5420c(c)(1). For each gas well
liquids unloading well affected facility that complies with the
requirements of Sec. 60.5390c(g), you must route emissions to a
control device through a closed vent system and continuously comply
with the closed vent requirements of Sec. 60.5416c. You also must
comply with the requirements specified in paragraph (f) of this section
and maintain the records in Sec. 60.5420c(c)(7), (9) and (11).
(b) Associated gas well standards for well designated facility. For
each associated gas well at your well designated facility, you must
demonstrate continuous compliance with the requirements of Sec.
60.5391c by submitting the reports required by Sec. 60.5420c(b)(1) and
(3) and maintaining the records specified in Sec. 60.5420c(c)(2). For
each associated gas well at your well designated facility that complies
with the requirements of Sec. 60.5391c(b) or (c), you must route
emissions to a control device through a closed vent system and
continuously comply with the closed vent requirements of Sec.
60.5416c. You must also comply with the requirements specified in
paragraph (e) of this section and maintain the records in paragraphs
(c)(7), (9) and (11) of this section.
(c) Centrifugal compressor designated facility. For each
centrifugal compressor designated facility complying with the
volumetric flow rate measurements requirements in Sec. 60.5392c(a)(1)
and (2), you must demonstrate continuous compliance according to
paragraph (c)(1) and paragraphs (c)(3) and (4) of this section.
Alternatively, for each wet seal and dry seal centrifugal compressor
designated facility complying with Sec. 60.5392c(a)(3) and (a)(4) or
(5) by routing emissions to a control device or to a process, you must
demonstrate continuous compliance according to paragraphs (c)(2)
through (4) of this section.
(1) You must maintain volumetric flow rate at or below the
volumetric flow rates specified in paragraphs (c)(1)(i) through (iii)
of this section for your centrifugal compressor, as applicable, and you
must conduct the required volumetric flow rate measurement of your dry
or wet seal in accordance with Sec. 60.5392c(a)(1) and (2) on or
before 8,760 hours of operation after your last volumetric flow rate
measurement which demonstrates compliance with the applicable
volumetric flow rate.
(i) For your wet seal centrifugal compressors (including self-
contained wet seal centrifugal compressors), you must maintain the
volumetric flow rate at or below 3 scfm per seal (or in the case of
manifolded groups of seals, 3 scfm multiplied by the number of seals).
[[Page 17182]]
(ii) For your Alaska North Slope centrifugal compressor equipped
with sour seal oil separator and capture system, you must maintain the
volumetric flow rate at or below 9 scfm per seal (or in the case of
manifolded groups of wet seals, 9 scfm multiplied by the number of
seals).
(iii) For your dry seal compressor, you must maintain the
volumetric flow rate at or below 10 scfm per seal (or in the case of
manifolded groups of wet seals, 10 scfm multiplied by the number of
seals).
(2) For each wet seal and dry seal centrifugal compressor
designated facility complying by routing emissions to a control device
or to a process, you must operate the wet seal emissions collection
system and dry seal system to route emissions to a control device or a
process through a closed vent system and continuously comply with the
closed vent requirements of Sec. 60.5416c(a) and (b). If you comply
with Sec. 60.5392c(a)(4) by using a control device, you also must
comply with the requirements in paragraph (e) of this section.
(3) You must submit the annual reports as required in Sec.
60.5420c(b)(1), (4) and (10)(i) through (iv), as applicable.
(4) You must maintain records as required in Sec. 60.5420c(c)(3),
(7) through (9) and (11), as applicable.
(d) Pump designated facility. To demonstrate continuous compliance
with the GHG standards for your pump designated facility as required by
Sec. 60.5395c, you must comply with paragraphs (d)(1) through (3) of
this section.
(1) For pump designated facilities complying with the requirements
of Sec. 60.5395c(a) by routing emissions to a process and for pump
designated facilities complying with the requirements of Sec.
60.5395c(b)(1) or (3), you must continuously comply with the closed
vent requirements of Sec. 60.5416c(a) and (b). If you comply with
Sec. 60.5395c(b)(3), you also must comply with the requirements in
paragraph (d) of this section.
(2) You must submit the annual reports for your pump designated
facility as required in Sec. 60.5420c(b)(1), and (9) through (12), as
applicable.
(3) You must maintain the records for your pump designated facility
as specified in Sec. 60.5420c(c)(14), as applicable.
(e) Additional continuous compliance requirements for well,
centrifugal compressor, reciprocating compressor, process controllers
in Alaska, storage vessel, process unit equipment, or pump designated
facilities. For each associated gas well at your well designated
facility, each gas well liquids unloading operation at your well
designated facility, each centrifugal compressor designated facility,
each reciprocating compressor designated facility, each process
controller designated facility in Alaska, each storage vessel
designated facility, each process unit equipment designated facility,
and each pump designated facility referenced to this paragraph from
either paragraph (a), (b), (c)(2), (d)(1), (f), (g)(2)(iv), (h) or (i)
of this section, you must also install monitoring systems as specified
in Sec. 60.5417c, demonstrate continuous compliance according to
paragraph (e)(1) of this section, maintain the records in paragraph
(e)(2) of this section, and comply with the reporting requirements
specified in paragraph (e)(3) of this section.
(1) You must demonstrate continuous compliance with the control
device performance requirements of Sec. 60.5412c(a) using the
procedures specified in paragraphs (e)(1)(i) through (viii) of this
section and conducting the monitoring as required by Sec. 60.5417c. If
you use a condenser as the control device to achieve the requirements
specified in Sec. 60.5412c(a)(2), you may demonstrate compliance
according to paragraph (e)(1)(ix) of this section. You may switch
between compliance with paragraphs (e)(1)(i) through (viii) of this
section and compliance with paragraph (e)(1)(ix) of this section only
after at least 1 year of operation in compliance with the selected
approach. You must provide notification of such a change in the
compliance method in the next annual report, following the change. If
you use an enclosed combustion device or a flare as the control device,
you must also conduct the monitoring required in paragraph (e)(1)(x) of
this section. If you use an enclosed combustion device or flare using
an alternative test method approved under Sec. 60.5412c(d), you must
use the procedures in paragraph (e)(1)(xi) of this section in lieu of
the procedures in paragraphs (e)(1)(i) through (viii) of this section,
but you must still conduct the monitoring required in paragraph
(e)(1)(x) of this section.
(i) You must operate below (or above) the site-specific maximum (or
minimum) parameter value established according to the requirements of
Sec. 60.5417c(f)(1). For flares, you must operate above the limits
specified in paragraphs (e)(1)(vii)(B) of this section.
(ii) You must calculate the average of the applicable monitored
parameter in accordance with Sec. 60.5417c(e).
(iii) Compliance with the operating parameter limit is achieved
when the average of the monitoring parameter value calculated under
paragraph (e)(1)(ii) of this section is either equal to or greater than
the minimum parameter value or equal to or less than the maximum
parameter value established under paragraph (e)(1)(i) of this section.
When performance testing of a combustion control device is conducted by
the device manufacturer as specified in Sec. 60.5413c(d), compliance
with the operating parameter limit is achieved when the criteria in
Sec. 60.5413c(e) are met.
(iv) You must operate the continuous monitoring system required in
Sec. 60.5417c(a) at all times the affected source is operating, except
for periods of monitoring system malfunctions, repairs associated with
monitoring system malfunctions and required monitoring system quality
assurance or quality control activities (including, as applicable,
system accuracy audits and required zero and span adjustments). A
monitoring system malfunction is any sudden, infrequent, not reasonably
preventable failure of the monitoring system to provide valid data.
Monitoring system failures that are caused in part by poor maintenance
or careless operation are not malfunctions. You are required to
complete monitoring system repairs in response to monitoring system
malfunctions and to return the monitoring system to operation as
expeditiously as practicable.
(v) You may not use data recorded during monitoring system
malfunctions, repairs associated with monitoring system malfunctions,
or required monitoring system quality assurance or control activities
in calculations used to report emissions or operating levels. You must
use all the data collected during all other required data collection
periods to assess the operation of the control device and associated
control system.
(vi) Failure to collect required data is a deviation of the
monitoring requirements.
(vii) If you use an enclosed combustion device to meet the
requirements of Sec. 60.5412c(a)(1) and you demonstrate compliance
using the test procedures specified in Sec. 60.5413c(b), or you use a
flare designed and operated in accordance with Sec. 60.5412c(a)(3),
you must comply with the applicable requirements in paragraphs
(e)(1)(vii)(A) through (E) of this section.
(A) For each enclosed combustion device which is not a catalytic
vapor incinerator and for each flare, you must comply with the
requirements in
[[Page 17183]]
paragraphs (e)(1)(vii)(A)(1) through (4) of this section.
(1) A pilot or combustion flame must be present at all times of
operation. An alert must be sent to the nearest control room whenever
the pilot or combustion flame is unlit.
(2) Devices must be operated with no visible emissions, except for
periods not to exceed a total of 1 minute during any 15-minute period.
A visible emissions test conducted according to section 11 of Method 22
of appendix A-7 to this part, must be performed at least once every
calendar month, separated by at least 15 days between each test. The
observation period shall be 15 minutes or once the amount of time
visible emissions is present has exceeded 1 minute, whichever time
period is less. Alternatively, you may conduct visible emissions
monitoring according to Sec. 60.5417c(h).
(3) Devices failing the visible emissions test must follow
manufacturer's repair instructions, if available, or best combustion
engineering practice as outlined in the unit inspection and maintenance
plan, to return the unit to compliant operation. All repairs and
maintenance activities for each unit must be recorded in a maintenance
and repair log and must be available for inspection.
(4) Following return to operation from maintenance or repair
activity, each device must pass a Method 22 of appendix A-7 to this
part visual observation as described in paragraph (e)(1)(vii)(D) of
this section or be monitored according to Sec. 60.5417c(h).
(B) For flares, you must comply with the requirements in paragraphs
(e)(1)(vii)(B)(1) through (6) of this section.
(1) For unassisted flares, maintain the NHV of the gas sent to the
flare at or above 200 Btu/scf.
(2) If you use a pressure assisted flare, maintain the NHV of gas
sent to the flare at or above 800 Btu/scf.
(3) For steam-assisted and air-assisted flares, maintain the
NHVcz at or above 270 Btu/scf.
(4) For flares with perimeter assist air, maintain the
NHVdil at or above 22 Btu/sqft. If the only assist air
provided to the flare is perimeter assist air intentionally entrained
in lower and/or upper steam at the flare tip and the effective diameter
is 9 inches or greater, you are not required to comply with the
NHVdil limit.
(5) Unless you use a pressure-assisted flare, maintain the flare
tip velocity below the applicable limits in Sec. 60.18(b).
(6) Maintain the total gas flow to the flare above the minimum
inlet gas flow rate. The minimum inlet gas flow rate is established
based on manufacturer recommendations.
(C) For enclosed combustion devices for which, during the
performance test conducted under Sec. 60.5413c(b), the combustion zone
temperature is not an indicator of destruction efficiency, you must
comply with the requirements in paragraphs (e)(1)(vii)(C)(1) through
(5) of this section, as applicable.
(1) Maintain the total gas flow to the enclosed combustion device
at or above the minimum inlet gas flow rate and at or below the maximum
inlet flow rate for the enclosed combustion device established in
accordance with Sec. 60.5417c(f).
(2) For unassisted enclosed combustion devices, maintain the NHV of
the gas sent to the enclosed combustion device at or above 200 Btu/scf.
(3) For enclosed combustion devices that use pressure-assisted
burner tips to promote mixing at the burner tip, maintain the NHV of
the gas sent to the enclosed combustion device at or above 800 Btu/scf.
(4) For steam-assisted and air-assisted enclosed combustion
devices, maintain the NHVcz at or above 270 Btu/scf.
(5) For enclosed combustion devices with perimeter assist air,
maintain the NHVdil at or above 22 Btu/sqft. If the only
assist air provided to the enclosed combustion device is perimeter
assist air intentionally entrained in lower and/or upper steam at the
flare tip and the effective diameter is 9 inches or greater, you are
not required to comply with the NHVdil limit.
(D) For enclosed combustion devices for which, during the
performance test conducted under Sec. 60.5413c(b), the combustion zone
temperature is demonstrated to be an indicator of destruction
efficiency, you must comply with the requirements in paragraphs
(e)(1)(vii)(D)(1) and (2) of this section.
(1) Maintain the temperature at or above the minimum temperature
established during the most recent performance test. The minimum
temperature limit established during the most recent performance test
is the average temperature recorded during each test run, averaged
across the 3 test runs (average of the test run averages).
(2) Maintain the total gas flow to the enclosed combustion device
at or above the minimum inlet gas flow rate and at or below the maximum
inlet flow rate for the enclosed combustion device established in
accordance with Sec. 60.5417c(f).
(E) For catalytic vapor incinerators you must operate the catalytic
vapor incinerator at or above the minimum temperature of the catalyst
bed inlet and at or above the minimum temperature differential between
the catalyst bed inlet and the catalyst bed outlet established in
accordance with Sec. 60.5417c(f).
(viii) If you use a carbon adsorption system as the control device
to meet the requirements of Sec. 60.5412c(a)(2), you must demonstrate
compliance by the procedures in paragraphs (e)(1)(viii)(A) and (B) of
this section, as applicable.
(A) If you use a regenerative-type carbon adsorption system, you
must comply with paragraphs (e)(1)(viii)(A)(1) through (4) of this
section.
(1) You must maintain the average regenerative mass flow or
volumetric flow to the carbon adsorber during each bed regeneration
cycle above the limit established in in accordance with Sec.
60.5413c(c)(2).
(2) You must maintain the average carbon bed temperature above the
temperature limit established in accordance with Sec. 60.5413c(c)(2)
during the carbon bed steaming cycle and below the carbon bed
temperature established in in accordance with Sec. 60.5413c(c)(2)
after the regeneration cycle.
(3) You must check the mechanical connections for leakage at least
every month, and you must perform a visual inspection at least every 3
months of all components of the continuous parameter monitoring system
for physical and operational integrity and all electrical connections
for oxidation and galvanic corrosion if your continuous parameter
monitoring system is not equipped with a redundant flow sensor.
(4) You must replace all carbon in the carbon adsorption system
with fresh carbon on a regular, predetermined time interval that is no
longer than the carbon service life established according to Sec.
60.5413c(c)(2).
(B) If you use a nonregenerative-type carbon adsorption system, you
must replace all carbon in the control device with fresh carbon on a
regular, predetermined time interval that is no longer than the carbon
service life established according to Sec. 60.5413c(c)(3).
(ix) If you use a condenser as the control device to achieve the
percent reduction performance requirements specified in Sec.
60.5412c(a)(2), you must demonstrate compliance using the procedures in
paragraphs (e)(1)(ix)(A) through (E) of this section.
(A) You must establish a site-specific condenser performance curve
according to Sec. 60.5417c(f)(2).
[[Page 17184]]
(B) You must calculate the daily average condenser outlet
temperature in accordance with Sec. 60.5417c(e).
(C) You must determine the condenser efficiency for the current
operating day using the daily average condenser outlet temperature
calculated under paragraph (e)(1)(ix)(B) of this section and the
condenser performance curve established under paragraph (e)(1)(ix)(A)
of this section.
(D) Except as provided in paragraphs (e)(1)(ix)(D)(1) and (2) of
this section, at the end of each operating day, you must calculate the
365-day rolling average TOC emission reduction, as appropriate, from
the condenser efficiencies as determined in paragraph (e)(1)(ix)(C) of
this section.
(1) After the compliance dates specified in Sec. 60.5387c(a), if
you have less than 120 days of data for determining average TOC
emission reduction, you must calculate the average TOC emission
reduction for the first 120 days of operation after the compliance
date. You have demonstrated compliance with the overall 95.0 percent
reduction requirement if the 120-day average TOC emission reduction is
equal to or greater than 95.0 percent.
(2) After 120 days and no more than 364 days of operation after the
compliance date specified in Sec. 60.5387c(a), you must calculate the
average TOC emission reduction as the TOC emission reduction averaged
over the number of days between the current day and the applicable
compliance date. You have demonstrated compliance with the overall 95.0
percent reduction requirement if the average TOC emission reduction is
equal to or greater than 95.0 percent.
(E) If you have data for 365 days or more of operation, you have
demonstrated compliance with the TOC emission reduction if the rolling
365-day average TOC emission reduction calculated in paragraph
(e)(1)(ix)(D) of this section is equal to or greater than 95.0 percent.
(x) During each inspection conducted using an OGI camera under
Sec. 60.5397c and during each periodic screening event or each
inspection conducted using an OGI camera under Sec. 60.5398c, you must
observe each enclosed combustion device and flare to determine if it is
operating properly. You must determine whether there is a flame present
and whether any uncontrolled emissions from the control device are
visible with the OGI camera or the technique used to conduct the
periodic screening event. During each inspection conducted under Sec.
60.5397c using AVO, you must observe each enclosed combustion device
and flare to determine if it is operating properly. Visually confirm
that the pilot or combustion flame is lit and that the pilot or
combustion flame is operating properly.
(xi) If you use an enclosed combustion device or flare using an
alternative test method approved under Sec. 60.5412c(d), you must
comply with paragraphs (e)(1)(xi)(A) through (E) of this section.
(A) You must maintain the combustion efficiency at or above 95.0
percent. Alternatively, if the alternative test method does not
directly monitor combustion efficiency, you must comply with the
applicable requirements in paragraphs (e)(1)(xi)(A)(1) and (2) of this
section.
(1) Maintain the NHVcz at or above 270 Btu/scf.
(2) For flares or enclosed combustion devices with perimeter assist
air, maintain the NHVdil at or above 22 Btu/sqft. If the
only assist air provided to the flare or enclosed combustion device is
perimeter assist air intentionally entrained in lower and/or upper
steam at the flare tip and the effective diameter is 9 inches or
greater, you are only required to comply with the NHVcz
limit specified in paragraph (e)(1)(xi)(A)(1) of this section.
(B) You must calculate the value of the applicable monitored
metric(s) in accordance with the approved alternative test method.
Compliance with the limit is achieved when the calculated values are
within the range specified in paragraph (e)(1)(xi)(A) of this section.
(C) You must conduct monitoring using the alternative test method
at all times the affected source is operating, except for periods of
monitoring system malfunctions, repairs associated with monitoring
system malfunctions and required monitoring system quality assurance or
quality control activities (including, as applicable, system accuracy
audits and required zero and span adjustments). A monitoring system
malfunction is any sudden, infrequent, not reasonably preventable
failure of the monitoring system to provide valid data. Monitoring
system failures that are caused in part by poor maintenance or careless
operation are not malfunctions. You are required to complete monitoring
system repairs in response to monitoring system malfunctions and to
return the monitoring system to operation as expeditiously as
practicable.
(D) You may not use data recorded during monitoring system
malfunctions, repairs associated with monitoring system malfunctions,
or required monitoring system quality assurance or control activities
in calculations used to report values to demonstrate compliance with
the limits specified in paragraph (e)(1)(xi)(A) of this section. You
must use all the data collected during all other required data
collection periods to assess the operation of the control device and
associated control system.
(E) Failure to collect required data is a deviation of the
monitoring requirements.
(2) You must maintain the records as specified in Sec.
60.5420c(c)(10) and (12).
(3) You must comply with the reporting requirements in Sec.
60.5420c(b)(10) through (12).
(f) Reciprocating compressor designated facility. For each
reciprocating compressor designated facility complying with Sec.
60.5393c(a) through (c), you must demonstrate continuous compliance
according to paragraphs (f)(1), (3) and (4) of this section. For each
reciprocating compressor designated facility complying with Sec.
60.5393c(d), you must demonstrate continuous compliance according to
paragraph (f)(4) through (6) of this section. For each reciprocating
compressor affected facility complying with Sec. 60.5393c(d)(2), you
must demonstrate continuous compliance according to paragraphs (g)(3)
through (6) of this section.
(1) You must maintain the volumetric flow rate at or below 2 scfm
per cylinder (or at or below the combined volumetric flow rate
determined by multiplying the number of cylinders by 2 scfm), and you
must conduct the required volumetric flow rate measurement of your
reciprocating compressor rod packing vents in accordance with Sec.
60.5393c(b) on or before 8,760 hours of operation after your last
volumetric flow rate measurement which demonstrated compliance with the
applicable volumetric flow rate.
(2) You must operate the rod packing emissions collection system to
route emissions to a control device or to a process through a closed
vent system and continuously comply with the cover and closed vent
requirements of Sec. 60.5416c. If you comply with Sec. 60.5393c(d) by
using a control device, you also must comply with the requirements in
paragraph (e) of this section.
(3) You must continuously monitor the number of hours of operation
for each reciprocating compressor affected facility since initial
startup, since 60 days after the state plan submittal deadline (as
specified in Sec. 60.5362c(c)), since the previous flow rate
measurement, or since the date of the
[[Page 17185]]
most recent reciprocating compressor rod packing replacement, whichever
date is latest.
(4) You must replace the reciprocating compressor rod packing on or
before the total number of hours of operation reaches 8,760 hours.
(5) You must submit the annual reports as required in Sec.
60.5420c(b)(1), (5), and (b)(10)(i) through (iv), as applicable.
(6) You must maintain records as required in Sec. 60.5420c(c)(4),
(7), (9), and (11), as applicable.
(g) Process controller designated facility. To demonstrate
continuous compliance with GHG emission standards for your process
controller designated facility as required by Sec. 60.5394c, you must
comply with the paragraphs (g)(1) through (4) of this section.
(1) You must demonstrate that your process controller designated
facility does not emit any methane to the atmosphere by meeting the
requirements of paragraphs (g)(1)(i) or (ii) of this section.
(i) If you comply by routing the emissions to a process, you must
comply with the closed vent system inspection and monitoring
requirements of Sec. 60.5416c.
(ii) If you comply by using a self-contained natural gas-driven
process controller, you must conduct the no identifiable emissions
inspections required by Sec. 60.5416c(b).
(2) For each process controller designated facility located at a
site in Alaska that does not have access to electrical power, and that
complies by reducing methane emissions from all controllers in the
process controller designated facility by 95.0 percent in accordance
with Sec. 60.5494c(b)(3), you must comply with comply with the closed
vent requirements of Sec. 60.5416c and the requirements in paragraph
(f) of this section for the control device.
(3) You must submit the annual report for your process controller
as required in Sec. 60.5420c(b)(1), (6), and (10) through (12), as
applicable.
(4) You must maintain the records as specified in Sec.
60.5420c(c)(5) for each process controller designated facility, as
applicable.
(h) Storage vessel designated facility. For each storage vessel
designated facility, you must demonstrate continuous compliance with
the requirements of Sec. 60.5396c according to paragraphs (h)(1)
through (10) of this section, as applicable.
(1) For each storage vessel designated facility complying with the
requirements of Sec. 60.5396c(a)(2), you must demonstrate continuous
compliance according to paragraphs (h)(5) and (h)(9) and (10) of this
section.
(2) For each storage vessel designated facility complying with the
requirements of Sec. 60.5396c(a)(3), you must demonstrate continuous
compliance according to paragraphs (h)(2)(i), (ii), or (iii) of this
section, as applicable, and (h)(9) and (10) of this section.
(i) You must maintain the uncontrolled actual methane emissions
from the storage vessel designated facility at less than 14 tpy.
(ii) You must comply with paragraph (h)(5) of this section as soon
as liquids from the well are routed to the storage vessel designated
facility following fracturing or refracturing according to the
requirements of Sec. 60.5396c(a)(3)(i).
(iii) You must comply with paragraph (h)(5) of this section within
30 days of the monthly determination according to the requirements of
Sec. 60.5396c(a)(3)(ii), where the monthly emissions determination
indicates that methane emissions from your storage vessel designated
facility increase to 14 tpy or greater and the increase is not
associated with fracturing or refracturing of a well feeding the
storage vessel designated facility.
(3) For each storage vessel designated facility or portion of a
storage vessel designated facility removed from service, you must
demonstrate compliance with the requirements of Sec. 60.5396c(c)(1),
by complying with paragraphs (h)(6) and (7) and (h)(9) and (10) of this
section.
(4) For each storage vessel designated facility or portion of a
storage vessel designated facility returned to service, you must
demonstrate compliance with the requirements of Sec. 60.5396c(c)(1) by
complying with paragraphs (h)(8) through (10) of this section.
(5) For each storage vessel designated facility, you must comply
with paragraphs (h)(5)(i) and (ii) of this section.
(i) You must reduce methane emissions as specified in Sec.
60.5396c(a)(2).
(ii) For each control device installed to meet the requirements of
Sec. 60.5396c(a)(2), you must demonstrate continuous compliance with
the performance requirements of Sec. 60.5412c for each storage vessel
designated facility using the procedure specified in paragraph
(h)(5)(ii)(A) and (B) of this section. When routing emissions to a
process, you must demonstrate continuous compliance as specified in
paragraph (h)(5)(ii)(A) of this section.
(A) You must comply with Sec. 60.5416c for each cover and closed
vent system.
(B) You must comply with the requirements specified in paragraph
(e) of this section.
(6) You must completely empty and degas each storage vessel, such
that each storage vessel no longer contains crude oil, condensate,
produced water or intermediate hydrocarbon liquids. For a portion of a
storage vessel designated facility to be removed from service, you must
completely empty and degas the storage vessel(s), such that the storage
vessel(s) no longer contains crude oil, condensate, produced water or
intermediate hydrocarbon liquids. A storage vessel where liquid is left
on walls, as bottom clingage or in pools due to floor irregularity is
considered to be completely empty.
(7) You must disconnect the storage vessel(s) from the tank battery
by isolating the storage vessel(s) from the tank battery such that the
storage vessel(s) is no longer manifolded to the tank battery by liquid
or vapor transfer.
(8) You must determine the designated facility status of a storage
vessel returned to service as provided in Sec. 60.5386c(e)(5).
(9) You must submit the annual reports as required by Sec.
60.5420c(b)(1) and (7).
(10) You must maintain the records as required by Sec.
60.5420c(c)(6) through (9), and (11), as applicable.
(i) Process unit equipment designated facility. For each process
unit equipment designated facility, you must demonstrate continuous
compliance with the requirements of Sec. 60.5400c according to
paragraphs (i)(1) through (4) and (11) through (16) of this section,
unless you meet and comply with the exception in Sec. 60.5402c(b),
(e), or (f) or meet the exemption in Sec. 60.5402c(c). Alternatively,
if you comply with the GHG standards for process unit designated
facilities using the standards in Sec. 60.5401c, you must comply with
paragraphs (i)(5) through (16) of this section, unless you meet the
exemption in Sec. 60.5402c(b) or (c) or the exception in Sec.
60.5402c(e) and (f).
(1) You must conduct monitoring for each pump in light liquid
service, pressure relief device in gas/vapor service, valve in gas/
vapor and light liquid service and connector in gas/vapor and light
liquid service as required by Sec. 60.5400c(b).
(2) You must conduct monitoring as required by Sec. 60.5400c(c)
for each pump in light liquid service.
(3) You must conduct monitoring as required by Sec. 60.5400c(d)
for each pressure relief device in gas/vapor service.
(4) You must comply with the equipment requirements for each open-
[[Page 17186]]
ended valve or line as required by Sec. 60.5400c(e).
(5) You must conduct monitoring for each pump in light liquid
service as required by Sec. 60.5401c(b).
(6) You must conduct monitoring for each pressure relief device in
gas/vapor service as required by Sec. 60.5401c(c).
(7) You must comply with the equipment requirements for each open-
ended valve or line as required by Sec. 60.5401c(d).
(8) You must conduct monitoring for each valve in gas/vapor or
light liquid service as required by Sec. 60.5401c(f).
(9) You must conduct monitoring for each pump, valve, and connector
in heavy liquid service and each pressure relief device in light liquid
or heavy liquid service as required by Sec. 60.5401c(g).
(10) You must conduct monitoring for each connector in gas/vapor or
light liquid service as required by Sec. 60.5401c(h).
(11) You must collect emissions and meet the closed vent system
requirements as required by Sec. 60.5416c for each pump equipped with
a dual mechanical seal system that degasses the barrier fluid reservoir
to a process or a control device, each pump which captures and
transports leakage from the seal or seals to a process or control
device, or each pressure relief device which captures and transports
leakage through the pressure relief device to a process or control
device.
(12) You must comply with the requirements specified in paragraph
(f) of this section.
(13) You must tag and repair each identified leak as required in
Sec. 60.5400c(h) or Sec. 60.5400c(i), as applicable.
(14) You must submit semiannual reports as required by Sec.
60.5422c and the annual reports in Sec. 60.5420b(b)(10)(i) through
(iv), as applicable.
(15) You must maintain the records specified by Sec.
60.5420c(c)(7), (c)(9), and (c)(11) as applicable and Sec. 60.5421c.
(j) Continuous compliance. For each fugitive emissions components
designated facility, you must demonstrate continuous compliance with
the requirements of Sec. 60.5397c(a) according to paragraphs (j)(1)
through (4) of this section.
(1) You must conduct periodic monitoring surveys as required in
Sec. 60.5397c(e) and (g).
(2) You must repair each identified source of fugitive emissions as
required in Sec. 60.5397c(h).
(3) You must submit annual reports for fugitive emissions
components designated facilities as required in Sec. 60.5420c(b)(1)
and (8).
(4) You must maintain records as specified in Sec.
60.5420c(c)(15).
Sec. 60.5416c What are the initial and continuous cover and closed
vent system inspection and monitoring requirements?
For each closed vent system and cover at your well, centrifugal
compressor, reciprocating compressor, process controller, pump, storage
vessel, and process unit equipment designated facilities, you must
comply with the applicable requirements of paragraphs (a) and (b) of
this section. Each self-contained natural gas process controller must
comply with paragraph (b) of this section.
(a) Inspections for closed vent systems, covers, and bypass
devices. If you install a control device or route emissions to a
process, you must inspect each closed vent system according to the
procedures and schedule specified in paragraphs (a)(1) and (2) of this
section, inspect each cover according to the procedures and schedule
specified in paragraph (a)(3) of this section, and inspect each bypass
device according to the procedures of paragraph (a)(4) of this section,
except as provided in paragraphs (b)(6) and (7) of this section.
(1) For each closed vent system joint, seam, or other connection
that is permanently or semi-permanently sealed (e.g., a welded joint
between two sections of hard piping or a bolted and gasketed ducting
flange), you must meet the requirements specified in paragraphs
(a)(1)(i) through (iii) of this section.
(i) Conduct an initial inspection according to the test methods and
procedures specified in paragraph (b) of this section to demonstrate
that the closed vent system operates with no identifiable emissions
within the first 30 calendar days after routing emissions through the
closed vent system.
(ii) Conduct annual visual inspections for defects that could
result in air emissions. Defects include, but are not limited to,
visible cracks, holes, or gaps in piping; loose connections; liquid
leaks; or broken or missing caps or other closure devices. You must
monitor a component or connection using the test methods and procedures
in paragraph (b) of this section to demonstrate that it operates with
no identifiable emissions following any time the component is repaired
or replaced or the connection is unsealed.
(iii) Conduct AVO inspections in accordance with and at the same
frequency as specified for fugitive emissions components designated
facilities located at the same type of site as specified in Sec.
60.5397c(g). Process unit equipment designated facilities must conduct
annual AVO inspections concurrent with the inspections required by
paragraph (a)(1)(ii) of this section.
(2) For closed vent system components other than those specified in
paragraph (a)(1) of this section, you must meet the requirements of
paragraphs (a)(2)(i) through (iv) of this section.
(i) Conduct an initial inspection according to the test methods and
procedures specified in paragraph (b) of this section within the first
30 calendars days after routing emissions through the closed vent
system to demonstrate that the closed vent system operates with no
identifiable emissions.
(ii) Conduct inspections according to the test methods, procedures,
and frequencies specified in paragraph (b) of this section to
demonstrate that the components or connections operate with no
identifiable emissions.
(iii) Conduct annual visual inspections for defects that could
result in air emissions. Defects include, but are not limited to,
visible cracks, holes, or gaps in ductwork; loose connections; liquid
leaks; or broken or missing caps or other closure devices. You must
monitor a component or connection using the test methods and procedures
in paragraph (b) of this section to demonstrate that it operates with
no identifiable emissions following any time the component is repaired
or replaced or the connection is unsealed.
(iv) Conduct AVO inspections in accordance with and at the same
frequency as specified for fugitive emissions components designated
facilities located at the same type of site, as specified in Sec.
60.5397c(g). Process unit equipment designated facilities must conduct
annual AVO inspections concurrent with the inspections required by
paragraph (a)(2)(iii) of this section.
(3) For each cover, you must meet the requirements of paragraphs
(a)(3)(i) through (iv) of this section.
(i) Conduct the inspections specified in paragraphs (a)(3)(ii)
through (iv) of this section to identify defects that could result in
air emissions and to ensure the cover operates with no identifiable
emissions. Defects include, but are not limited to, visible cracks,
holes, or gaps in the cover, or between the cover and the separator
wall; broken, cracked, or otherwise damaged seals or gaskets on closure
devices; and broken or missing hatches, access covers, caps, or other
closure devices. In the case where the storage vessel is buried
partially or entirely
[[Page 17187]]
underground, you must inspect only those portions of the cover that
extend to or above the ground surface, and those connections that are
on such portions of the cover (e.g., fill ports, access hatches, gauge
wells, etc.) and can be opened to the atmosphere.
(ii) An initial inspection according to the test methods and
procedures specified in paragraph (b) of this section, following
installation of the cover to demonstrate that each cover operates with
no identifiable emissions.
(iii) Conduct AVO inspections in accordance with and at the same
frequency as specified for fugitive emissions components designated
facilities located at the same type of site as specified in Sec.
60.5397b(g). Process unit equipment designated facilities must conduct
annual AVO inspections concurrent with the inspections required by
paragraph (a)(1)(ii) of this section.
(iv) Inspections according to the test methods, procedures, and
schedules specified in paragraph (b) of this section to demonstrate
that each cover operates with no identifiable emissions.
(4) For each bypass device, except as provided for in Sec.
60.5411c(a)(4)(ii), you must meet the requirements of paragraph
(a)(4)(i) or (ii) of this section.
(i) Set the flow indicator to take a reading at least once every 15
minutes at the inlet to the bypass device that could divert the stream
away from the control device and to the atmosphere.
(ii) If the bypass device valve installed at the inlet to the
bypass device is secured in the non-diverting position using a car-seal
or a lock-and-key type configuration, visually inspect the seal or
closure mechanism at least once every month to verify that the valve is
maintained in the non-diverting position and the vent stream is not
diverted through the bypass device.
(b) No identifiable emissions test methods and procedures. If you
are required to conduct an inspection of a closed vent system and cover
as specified in paragraph (a)(1), (2), or (3) of this section or Sec.
60.5398c(b), you must meet the requirements of paragraphs (b)(1)
through (9) of this section. You must meet the requirements of
paragraphs (b)(1), (2), (4), and (9) of this section for each self-
contained process controller at your process controller designated
facility as specified at Sec. 60.5394c(a)(2).
(1) Initial and periodic inspection. You must conduct initial and
periodic no identifiable emissions inspections as specified in
paragraphs (b)(1)(i) through (iii) of this section, as applicable.
(i) You must conduct inspections for no identifiable emissions from
your closed vent systems and covers at your well, centrifugal
compressor, reciprocating compressor, process controller, pump, or
storage vessel designated facility, using the procedures for conducting
OGI inspections in Sec. 60.5397c(c)(7). As an alternative you may
conduct inspections in accordance with Method 21 of appendix A-7 to
this part. Monitoring must be conducted at the same frequency as
specified for fugitive emissions components designated facilities
located at the same type of site, as specified in Sec. 60.5397c(g).
(ii) For closed vent systems and covers located at onshore natural
gas processing plants, OGI inspections for no identifiable emissions
must be conducted initially and bimonthly in accordance with appendix K
to this part. As an alternative you must conduct quarterly inspections
for no identifiable emissions in accordance with Method 21 of appendix
A-7 to this part.
(iii) For your self-contained process controller, you must conduct
initial and quarterly inspections for no identifiable emissions using
the procedures for conducting OGI inspections in Sec. 60.5397c(c)(7).
As an alternative you may conduct quarterly inspections in accordance
with Method 21 of appendix A-7 to this part.
(2) OGI inspection. Where OGI is used, the closed vent system,
cover, or self-contained process controller is determined to operate
with no identifiable emissions if no emissions are imaged during the
inspection. Emissions imaged by OGI constitute a deviation of the no
identifiable emissions standard until an OGI inspection conducted in
accordance with this paragraph (b)(2) of this section determines that
the closed vent system, cover, or self-contained process controller, as
applicable, operates with no identifiable emissions.
(3) AVO inspection. Where AVO inspections are required, the closed
vent system or cover is determined to operate with no identifiable
emissions if no emissions are detected by AVO. Emissions detected by
AVO constitute a deviation of the no identifiable emissions standard
until an AVO inspection determines that the closed vent system or cover
operates with no identifiable emissions.
(4) Method 21 inspection. Where Method 21 of appendix A-7 to this
part is used for the inspection, the requirements of paragraphs
(b)(4)(i) through (vii) of this section apply.
(i) The detection instrument must meet the performance criteria of
Method 21 of appendix A-7 to this part, except that the instrument
response factor criteria in section 8.1.1 of Method 21 must be for the
average composition of the fluid and not for each individual organic
compound in the stream.
(ii) You must calibrate the detection instrument before use on each
day of its use by the procedures specified in Method 21 of appendix A-7
to this part.
(iii) Calibration gases must be as specified in paragraphs
(b)(4)(iii)(A) and (B) of this section.
(A) Zero air (less than 10 parts per million by volume hydrocarbon
in air).
(B) A mixture of methane in air at a concentration less than 500
ppmv.
(iv) You may choose to adjust or not adjust the detection
instrument readings to account for the background organic concentration
level. If you choose to adjust the instrument readings for the
background level, you must determine the background level value
according to the procedures in Method 21 of appendix A-7 to this part.
(v) Your detection instrument must meet the performance criteria
specified in paragraphs (b)(4)(v)(A) and (B) of this section.
(A) Except as provided in paragraph (b)(4)(v)(B) of this section,
the detection instrument must meet the performance criteria of Method
21 of appendix A-7 to this part, except the instrument response factor
criteria in section 8.1.1 of Method 21 must be for the average
composition of the process fluid, not each individual volatile organic
compound in the stream. For process streams that contain nitrogen, air,
or other inerts that are not organic hazardous air pollutants or
volatile organic compounds, you must calculate the average stream
response factor on an inert-free basis.
(B) If no instrument is available that will meet the performance
criteria specified in paragraph (b)(4)(v)(A) of this section, you may
adjust the instrument readings by multiplying by the average response
factor of the process fluid, calculated on an inert-free basis, as
described in paragraph (b)(4)(v)(A) of this section.
(vi) You must determine if a potential leak interface operates with
no identifiable emissions, as applicable, using the applicable
procedure specified in paragraph (b)(4)(vi)(A) or (B) of this section.
(A) If you choose not to adjust the detection instrument readings
for the background organic concentration level, then you must directly
compare the maximum organic concentration value measured by the
detection instrument to the applicable value for the potential leak
interface as specified in paragraph (b)(4)(vii) of this section.
[[Page 17188]]
(B) If you choose to adjust the detection instrument readings for
the background organic concentration level, you must compare the value
of the arithmetic difference between the maximum organic concentration
value measured by the instrument and the background organic
concentration value as determined in paragraph (b)(4)(iv) of this
section with the applicable value for the potential leak interface as
specified in paragraph (b)(4)(vii) of this section.
(vii) A closed vent system, cover, or self-contained process
controller is determined to operate with no identifiable emissions if
the organic concentration value determined in paragraph (b)(4)(vi) of
this section is less than 500 ppmv. An organic concentration value
determined in paragraph (b)(4)(vi) of this section of greater than or
equal to 500 ppmv constitutes a deviation of the no identifiable
emissions standard until an inspection conducted in accordance with
this paragraph (b)(4) of this section determines that the closed vent
system, cover, or self-contained process controller, as applicable,
operates with no identifiable emissions.
(5) Repairs. Whenever emissions or a defect is detected, you must
repair the emissions or defect as soon as practicable according to the
requirements of paragraphs (b)(5)(i) through (iii) of this section,
except as provided in paragraph (b)(6) of this section.
(i) A first attempt at repair must be made no later than 5 calendar
days after the emissions or defect is detected.
(ii) Repair must be completed no later than 30 calendar days after
the emissions or defect is detected.
(iii) For covers, grease or another substance compatible with the
gasket material must be applied to deteriorating or cracked gaskets to
improve the seal while awaiting repair.
(6) Delay of repair. Delay of repair of a closed vent system or
cover for which emissions or defects have been detected is allowed if
the repair is technically infeasible without a shutdown, or if you
determine that emissions resulting from immediate repair would be
greater than the emissions likely to result from delay of repair. You
must complete repair of such equipment by the end of the next shutdown.
(7) Unsafe to inspect requirements. You may designate any parts of
the closed vent system or cover as unsafe to inspect if the
requirements of paragraphs (b)(7)(i) and (ii) of this section are met.
Unsafe to inspect parts are exempt from the inspection requirements of
paragraphs (a)(1) through (3) of this section.
(i) You determine that the equipment is unsafe to inspect because
inspecting personnel would be exposed to an imminent or potential
danger as a consequence of complying with paragraphs (a)(1), (2), or
(3) of this section.
(ii) You have a written plan that requires inspection of the
equipment as frequently as practicable during safe-to-inspect times.
(8) Difficult to inspect requirements. You may designate any parts
of the closed vent system or cover as difficult to inspect if the
requirements of paragraphs (b)(8)(i) and (ii) of this section are met.
Difficult to inspect parts are exempt from the inspection requirements
of paragraphs (a)(1) through (3) of this section.
(i) You determine that the equipment cannot be inspected without
elevating the inspecting personnel more than 2 meters above a support
surface.
(ii) You have a written plan that requires inspection of the
equipment at least once every 5 years.
(9) Records and reports. You must maintain records of all
inspection results as specified in Sec. 60.5420c(c)(7) through (9).
You must submit the reports as specified in Sec. 60.5420c(b)(10).
Sec. 60.5417c What are the continuous monitoring requirements for my
control devices?
You must meet the requirements of this section to demonstrate
continuous compliance for each control device used to meet emission
standards for your well, centrifugal compressor, reciprocating
compressor, process controller, storage vessel, and process unit
equipment designated facilities.
(a) For each control device used to comply with the emission
reduction standard in Sec. 60.5391c(b) for well designated facilities,
Sec. 60.5392c(a)(3) for centrifugal compressor designated facilities,
Sec. 60.5393c(d)(2) for reciprocating compressor designated
facilities, Sec. 60.5394c(b)(3) for your process controller designated
facility in Alaska, Sec. 60.5393c(b)(1) for your pumps designated
facility, Sec. 60.5396c(a)(2) for your storage vessel designated
facility, or either Sec. 60.5400c(f) or Sec. 60.5401c(e) for your
process equipment designated facility, you must install and operate a
continuous parameter monitoring system for each control device as
specified in paragraphs (c) through (h) of this section, except as
provided for in paragraph (b) of this section. If you install and
operate a flare in accordance with Sec. 60.5412c(a)(3), you are exempt
from the requirements of paragraph (f) of this section. If you operate
an enclosed combustion device or flare using an alternative test method
approved under Sec. 60.5412c(d), you must operate the control device
as specified in paragraph (i) of this section instead of using the
procedures specified in paragraphs (c) through (h) of this section. You
must keep records and report in accordance with paragraph (j) of this
section.
(b) You are exempt from the monitoring requirements specified in
paragraphs (c) through (g) of this section for the control devices
listed in paragraphs (b)(1) and (2) of this section.
(1) A boiler or process heater in which all vent streams are
introduced with the primary fuel or are used as the primary fuel.
(2) A boiler or process heater with a design heat input capacity
equal to or greater than 44 megawatts.
(c) You must meet the specifications and requirements of paragraphs
(c)(1) through (4) of this section.
(1) Except for continuous parameter monitoring systems used to
detect the presence of a pilot or combustion flame, each continuous
parameter monitoring system must measure data values at least once
every hour and record the values for each parameter as required in
paragraphs (c)(1)(i) or (ii) of this section. Continuous parameter
monitoring systems used to detect the presence of a pilot or combustion
flame must record a reading at least once every 5 minutes.
(i) Each measured data value.
(ii) Each block average value for each 1-hour period or shorter
periods calculated from all measured data values during each period.
(2) You must prepare a monitoring plan that covers each control
device for designated facilities within each company-defined area. The
monitoring plan must address the monitoring system design, data
collection, and the quality assurance and quality control elements
outlined in paragraphs (c)(2)(i) through (v) of this section. You must
install, calibrate, operate, and maintain each continuous parameter
monitoring system in accordance with the procedures in your monitoring
plan. Heat sensing monitoring devices that indicate the continuous
ignition of a pilot or combustion flame are exempt from the
calibration, quality assurance and quality control requirements of this
section.
(i) The performance criteria and design specifications for the
monitoring system equipment, including the sample interface, detector
signal analyzer, and data acquisition and calculations.
(ii) Sampling interface (e.g., thermocouple) location such that the
[[Page 17189]]
monitoring system will provide representative measurements.
(iii) Equipment performance checks, system accuracy audits, or
other audit procedures.
(iv) Ongoing operation and maintenance procedures in accordance
with provisions in Sec. 60.13(b).
(v) Ongoing recordkeeping procedures in accordance with provisions
in Sec. 60.7(f).
(3) You must conduct the continuous parameter monitoring system
equipment performance checks, system accuracy audits, or other audit
procedures specified in the monitoring plan at least once every 12
months.
(4) You must conduct a performance evaluation of each continuous
parameter monitoring system in accordance with the monitoring plan.
Heat sensing monitoring devices that indicate the continuous ignition
of a pilot or combustion flame are exempt from the calibration, quality
assurance and quality control requirements of this section.
(d) You must install, calibrate, operate, and maintain a device
equipped with a continuous recorder to measure the values of operating
parameters appropriate for the control device as specified in
paragraphs (d)(1) through (8) of this section, as applicable. Instead
of complying with the requirements in paragraphs (d)(1) through (8) of
this section, you may install an organic monitoring device equipped
with a continuous recorder that measures the concentration level of
organic compounds in the exhaust vent stream from the control device to
demonstrate compliance with the applicable performance requirement
specified in Sec. 60.5412c(a)(1). The monitor must meet the
requirements of Performance Specification 8 or 9 of appendix B to this
part. You must install, calibrate, and maintain the monitor according
to the manufacturer's specifications and the requirements in
Performance Specification 8 or 9. You may also request approval from
the Administrator to monitor different operating parameters than those
specified in paragraphs (d)(1) through (8) of this section in
accordance with Sec. 60.13(i).
(1) For an enclosed combustion device that demonstrates during the
performance test conducted under Sec. 60.5413c(b) that combustion zone
temperature is an accurate indicator of performance, a temperature
monitoring device equipped with a continuous recorder. The monitoring
device must have a minimum accuracy of 1 percent of the
temperature being monitored in degrees Celsius, or 2.5
[deg]C, whichever value is greater. You must install the temperature
sensor at a location representative of the combustion zone temperature.
You must also comply with the requirements of paragraphs (d)(8)(i),
(iv), and (v) of this section.
(2) For a catalytic vapor incinerator, a temperature monitoring
device equipped with a continuous recorder. The device must be capable
of monitoring temperature at two locations and have a minimum accuracy
of 1 percent of the temperature being monitored in degrees
Celsius, or 2.5 [deg]C, whichever value is greater. You
must install one temperature sensor in the vent stream at the nearest
feasible point to the catalyst bed inlet, and you must install a second
temperature sensor in the vent stream at the nearest feasible point to
the catalyst bed outlet.
(3) For a boiler or process heater, a temperature monitoring device
equipped with a continuous recorder. The temperature monitoring device
must have a minimum accuracy of 1 percent of the
temperature being monitored in degrees Celsius, or 2.5
[deg]C, whichever value is greater. You must install the temperature
sensor at a location representative of the combustion zone temperature.
(4) For a condenser, a temperature monitoring device equipped with
a continuous recorder. The temperature monitoring device must have a
minimum accuracy of 1 percent of the temperature being
monitored in degrees Celsius, or 2.5 [deg]C, whichever
value is greater. You must install the temperature sensor at a location
in the exhaust vent stream from the condenser.
(5) For a regenerative-type carbon adsorption system, a continuous
monitoring system that meets the specifications in paragraphs (d)(5)(i)
and (ii) of this section. You also must monitor the design carbon
service life established using a design analysis performed as specified
in Sec. 60.5413c(c)(2).
(i) The continuous parameter monitoring system must measure and
record the average total regeneration stream mass flow or volumetric
flow during each carbon bed regeneration cycle. The flow sensor must
have a measurement sensitivity of 5 percent of the flow rate or 10
cubic feet per minute, whichever is greater. You must check the
mechanical connections for leakage at least every month, and you must
perform a visual inspection at least every 3 months of all components
of the flow continuous parameter monitoring system for physical and
operational integrity and all electrical connections for oxidation and
galvanic corrosion if your flow continuous parameter monitoring system
is not equipped with a redundant flow sensor; and
(ii) The continuous parameter monitoring system must measure and
record the average carbon bed temperature for the duration of the
carbon bed steaming cycle and measure the actual carbon bed temperature
after regeneration and within 15 minutes of completing the cooling
cycle. The temperature monitoring device must have a minimum accuracy
of 1 percent of the temperature being monitored in degrees
Celsius, or 2.5 [deg]C, whichever value is greater.
(6) For a nonregenerative-type carbon adsorption system, you must
monitor the design carbon replacement interval established using a
design analysis performed as specified in Sec. 60.5413c(c)(3). The
design carbon replacement interval must be based on the total carbon
working capacity of the control device and source operating schedule.
(7) For a combustion control device whose model is tested under
Sec. 60.5413c(d), continuous monitoring systems as specified in
paragraphs (d)(8)(i) through (iv) and (vi) of this section and visible
emission observations conducted as specified in paragraph (d)(8)(v) of
this section.
(8) For an enclosed combustion device other than those listed in
paragraphs (d)(1) through (3) and (7) of this section or for a flare,
continuous monitoring systems as specified in paragraphs (d)(8)(i)
through (iv) of this section and visible emission observations
conducted as specified in paragraph (d)(8)(v) of this section.
Additionally, for enclosed combustion devices or flares that are air-
assisted or steam-assisted, the continuous monitoring systems specified
in paragraph (d)(8)(vi) of this section.
(i) Continuously monitor at least once every five minutes for the
presence of a pilot flame or combustion flame using a device
(including, but not limited to, a thermocouple, ultraviolet beam
sensor, or infrared sensor) capable of detecting that the pilot or
combustion flame is present at all times. An alert must be sent to the
nearest control room whenever the pilot or combustion flame is unlit.
Continuous monitoring systems used for the presence of a pilot flame or
combustion flame are not subject to a minimum accuracy requirement
beyond being able to detect the presence or absence of a flame and are
exempt from the calibration requirements of this section.
(ii) Except as provided in this paragraph (d)(8)(ii) and paragraph
(d)(8)(iii) of this section, use one of the following methods to
continuously
[[Page 17190]]
determine the NHV of the inlet gas to the enclosed combustion device or
flare at standard conditions. If the only inlet gas stream to the
enclosed combustion device or flare is associated gas from a well
designated facility, the NHV of the inlet stream is considered to be
sufficiently above the minimum required NHV for the inlet gas, and you
are not required to conduct the continuous monitoring in this paragraph
(d)(8)(ii) or the demonstration in paragraph (d)(8)(iii) of this
section.
(A) A calorimeter with a minimum accuracy of 2 percent
of span.
(B) A gas chromatograph that meets the requirements in paragraphs
(d)(8)(ii)(B)(1) through (5) of this section.
(1) You must follow the procedure in Performance Specification 9 of
appendix B to this part, except that a single daily mid-level
calibration check can be used (rather than triplicate analysis), the
multi-point calibration can be conducted quarterly (rather than
monthly), and the sampling line temperature must be maintained at a
minimum temperature of 60 [deg]C (rather than 120 [deg]C). Calibration
gas cylinders must be certified to an accuracy of 2 percent and
traceable to National Institute of Standards and Technology (NIST)
standards.
(2) You must meet the accuracy requirements in Performance
Specification 9 of appendix B to this part.
(3) You must use a calibration gas or multiple gases that includes
the compounds that are reasonably expected to be present in the flare
gas stream. If multiple calibration gases are necessary to cover all
compounds, you must calibrate the instrument on all of the gases. You
may only use the compounds used to calibrate the gas chromatograph in
the calculation of the vent gas NHV.
(4) In lieu of the calibration gas described in paragraph
(d)(8)(ii)(B)(3) of this section, you may use a surrogate calibration
gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All
of the calibration gases may be combined in one cylinder. If multiple
calibration gases are necessary to cover all compounds, you must
calibrate the instrument on all of the gases. Use the response factor
for the nearest normal hydrocarbon (i.e., n-alkane) in the calibration
mixture to quantify unknown components detected in the analysis. Use
the response factor for n-pentane to quantify unknown components
detected in the analysis that elute after n-pentane.
(5) To determine the NHV of the vent gas, determine the product of
the volume fraction of the individual component in the vent gas and the
net heating value of that individual component. Sum the products for
all components in the vent gas to determine the NHV for the vent gas.
For the net heating value of each individual component, use the net
heating value at 25 [deg]C and 1 atmosphere.
(C) A mass spectrometer that meets the requirements in paragraphs
(d)(8)(ii)(C)(1) through (6) of this section.
(1) You must meet applicable requirements in Performance
Specification 9 of appendix B of this part for continuous monitoring
system acceptance including, but not limited to, performing an initial
multi-point calibration check at three concentrations following the
procedure in Section 10.1. A single daily mid-level calibration check
can be used (rather than triplicate analysis), the multi-point
calibration can be conducted quarterly (rather than monthly), and the
sampling line temperature must be maintained at a minimum temperature
of 60 [deg]C (rather than 120 [deg]C). Calibration gas cylinders must
be certified to an accuracy of 2 percent and traceable to NIST
standards.
(2) The average instrument calibration error (CE) for each
calibration compound at any calibration concentration must not differ
by more than 10 percent from the certified cylinder gas value. The CE
for each component in the calibration blend must be calculated using
the following equation:
[GRAPHIC] [TIFF OMITTED] TR08MR24.042
Where:
Cm = Average instrument response (ppm).
Ca = Certified cylinder gas value (ppm).
(3) You must use a calibration gas or multiple gases that includes
the compounds that are reasonably expected to be present in the flare
gas stream. If multiple calibration gases are necessary to cover all
compounds, you must calibrate the instrument on all of the gases. You
may only use the compounds used to calibrate the mass spectrometer in
the calculation of the vent gas NHV.
(4) In lieu of the calibration gas described in paragraph
(d)(8)(ii)(C)(3) of this section, you may use a surrogate calibration
gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All
of the calibration gases may be combined in one cylinder. If multiple
calibration gases are necessary to cover all compounds, you must
calibrate the instrument on all of the gases. For unknown gas
components that have similar analytical mass fragments to calibration
compounds, you may report the unknowns as an increase in the overlapped
calibration gas compound. For unknown compounds that produce mass
fragments that do not overlap calibration compounds, you may use the
response factor for the nearest molecular weight hydrocarbon in the
calibration mix to quantify the unknown component. You may use the
response factor for n-pentane to quantify any unknown components
detected with a higher molecular weight than n-pentane.
(5) You must perform an initial calibration to identify mass
fragment overlap and response factors for the target compounds.
(6) To determine the NHV of the vent gas, determine the product of
the volume fraction of the individual component in the vent gas and the
net heating value of that individual component. Sum the products for
all components in the vent gas to determine the NHV for the vent gas.
For the net heating value of each individual component, use the net
heating value at 25 [deg]C and 1 atmosphere.
(D) A grab sampling system capable of collecting an evacuated
canister sample for subsequent compositional analysis at least once
every eight hours. Subsequent compositional analysis of the samples
must be performed according to ASTM D1945-14 (R2019) (incorporated by
reference, see Sec. 60.17). To determine the NHV of the vent gas,
determine the product of the volume fraction of the individual
component in the vent gas and the net heating value of that
[[Page 17191]]
individual component. Sum the products for all components in the vent
gas to determine the NHV for the vent gas. For the net heating value of
each individual component, use the net heating value at 25 [deg]C and 1
atmosphere.
(iii) For an unassisted or pressure-assisted flare or enclosed
combustion device, if you demonstrate according to the methods
described in paragraphs (d)(8)(iii)(A) through (F) of this section that
the NHV of the inlet gas to the enclosed combustion device or flare
consistently exceeds the applicable operating limit specified in Sec.
60.5415c(e)(1)(vii)(B) or (C)(1), continuous monitoring of the NHV is
not required, but you must conduct the ongoing sampling in paragraph
(d)(8)(iii)(G) of this section. For flares and enclosed combustion
devices that use only perimeter assist air and do not use steam assist
or premix assist air, if you demonstrate according to the methods
described in paragraphs (d)(8)(iii)(A) through (F) of this section that
the NHV of the inlet gas to the enclosed combustion device or flare
consistently exceeds 300 Btu/scf, continuous monitoring of the NHV is
not required, but you must conduct the ongoing sampling in paragraph
(d)(8)(iii)(G) of this section. For an unassisted or pressure-assisted
flare or enclosed combustion device, in lieu of conducting the
demonstration outlined in paragraphs (d)(8)(iii)(A) through (D) of this
section, you may conduct the demonstration outlined in paragraph
(d)(8)(iii)(H) of this section, but you must still comply with
paragraphs (d)(8)(iii)(E) through (G) of this section.
(A) Continuously monitor or collect a sample of the inlet gas to
the enclosed combustion device or flare twice daily to determine the
average NHV of the gas stream for 14 consecutive operating days. If you
do not continuously monitor the NHV, the minimum time of collection for
each individual sample be at least one hour. Consecutive samples must
be separated by at least 6 hours. If inlet gas flow is intermittent
such that there are not at least 28 samples over the 14 operating day
period, you must continue to collect samples of the inlet gas beyond
the 14 operating day period until you collect a minimum of 28 samples.
(B) If you collect samples twice per day, count the number of
samples where the NHV value is less than 1.2 times the applicable
operating limit specified in Sec. 60.5415c(e)(1)(vii)(B) or (C)(1), or
paragraph (d)(8)(iii) of this section (i.e., values that are less than
240, 360, or 960 Btu/scf, as applicable) during the sample collection
period in paragraph (d)(8)(iii)(A) of this section.
(C) If you continuously sample the inlet stream for 14 days, count
the number of hourly average NHV values that are less than the
applicable operating limit specified in Sec. 60.5415c(e)(1)(vii)(B) or
(C)(1), or paragraph (d)(8)(iii) of this section (i.e., values that are
less than 200, 300, or 800 Btu/scf, as applicable), during the sample
collection period in paragraph (d)(8)(iii)(A) of this section.
(D) If there are no samples counted under paragraph (d)(8)(iii)(B)
of this section or there are no hourly values counted under paragraph
(d)(8)(iii)(C) of this section, the gas stream is considered to
consistently exceed the applicable NHV operating limit and on-going
continuous monitoring is not required.
(E) If process operations are revised that could impact the NHV of
the gas sent to the enclosed combustion device or flare, such as the
removal or addition of process equipment, and at any time the
Administrator requires, re-evaluation of the gas stream must be
performed according to paragraphs (d)(8)(iii)(A) through (D) of this
section to ensure the gas stream still consistently exceeds the
applicable operating limit specified in Sec. 60.5415c(e)(1)(vii)(B) or
(C)(1), or paragraph (d)(8)(iii) of this section.
(F) When collecting samples under paragraph (d)(8)(iii)(A) of this
section, the owner or operator must account for any sources of inert
gases that can be sent to the enclosed combustion device or flare
(e.g., streams from compressors in acid gas service, streams from
enhanced oil recovery facilities). The report in Sec.
60.5420c(b)(10)(v)(I) and the records of the demonstration in Sec.
60.5420c(c)(10)(vi) must note whether the enclosed combustion device or
flare has the potential to receive inert gases, and if so, whether the
sampling included periods where the highest percentage of inert gases
were sent to the enclosed combustion device or flare. If the
introduction of inerts is intermittent and does not occur during the
initial demonstration, the introduction of inerts will be considered a
revision to process operations that triggers a re-evaluation under
paragraph (d)(8)(iii)(E) of this section. If conditions at the site did
not allow sampling during periods where the introduction of inert gases
was at the highest percentage possible, increasing the percentage of
inerts will be considered a revision to process operations that
triggers a re-evaluation under paragraph (d)(8)(iii)(E) of this
section.
(G) You must collect three samples of the inlet gas to the enclosed
combustion device or flare at least once every 5 years. The minimum
time of collection for each individual sample must be at least one
hour. The samples must be taken during the period with the lowest
expected NHV (i.e., the period with the highest percentage of inerts).
The first set of periodic samples must be taken, or continuous
monitoring commenced, no later than 60 calendar months following the
last sample taken under paragraph (d)(8)(iii)(A) of this section.
Subsequent periodic samples must be taken, or continuous monitoring
commenced, no later than 60 calendar months following the previous
sample. If any sample has an NHV value less than 1.2 times the
applicable operating limit specified in Sec. 60.5415c(e)(1)(vii)(B) or
(C)(1), or paragraph (d)(8)(iii) of this section (i.e., values that are
less than 240, 360, or 960 Btu/scf, as applicable), you must conduct
the monitoring required by paragraph (d)(8)(ii) of this section.
(H) You may request an alternative test method under Sec.
60.5412c(d) to demonstrate that the flare or enclosed combustion device
reduces methane and VOC in the gases vented to the device by 95.0
percent by weight or greater. You must use an alternative test method
that demonstrates compliance with the combustion efficiency limit; you
may not use an alternative test method that demonstrates compliance
with NHVcz and NHVdil in lieu of measuring
combustion efficiency directly. You must measure data values at the
frequency specified in the alternative test method and conduct the
quality assurance and quality control requirements outlined in the
alternative test method at the frequency outlined in the alternative
test method. You must monitor the combustion efficiency of the flare
continuously for 14 days. If there are no values of the combustion
efficiency measured by the alternative test method that are less than
95.0 percent, the gas stream is considered to consistently exceed the
applicable NHV operating limit, and you are not required to
continuously monitor the NHV of the inlet gas to the flare or enclosed
combustion device.
(iv) Except as noted in paragraphs (d)(8)(iv)(A) through (E) of
this section, a continuous parameter monitoring system for measuring
the flow of gas to the enclosed combustion device or flare. You may use
direct flow meters or other parameter monitoring systems combined with
engineering calculations, such as inlet line pressure, line size, and
burner nozzle dimensions, to satisfy this requirement. The
[[Page 17192]]
monitoring instrument must have an accuracy of 10 percent
or better at the maximum expected flow rate.
(A) Pressure-assisted flares and pressure-assisted enclosed
combustion devices are not required to have a continuous parameter
monitoring system for measuring the inlet flow of gas to the device if
you install, calibrate, maintain, and operate a backpressure regulator
valve calibrated to open at the minimum pressure set point
corresponding to the minimum inlet gas flow rate. The set point must be
consistent with manufacturer specifications for minimum flow or
pressure and must be supported by an engineering evaluation. At least
annually, you must confirm that the backpressure regulator valve set
point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(B) Unassisted flares are not required to have a continuous
parameter monitoring system for measuring the inlet flow of gas to the
device if you meet the conditions in paragraphs (d)(8)(iv)(B)(1) and
(2) of this section.
(1) You must demonstrate, based on the maximum potential pressure
of units manifolded to the flare and applicable engineering
calculations for the manifolded closed vent system, that the maximum
flow rate to the flare cannot cause the flare tip velocity to exceed
18.3 meter/second (60 feet/second). If there are changes to the process
or control device that can be reasonably expected to impact the maximum
flow rate to the flare, you must conduct a new demonstration to
determine whether the maximum flow rate to the flare is less than 18.3
meter/second (60 feet/second).
(2) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an engineering evaluation. At
least annually, you must confirm that the backpressure regulator valve
set point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(C) Unassisted enclosed combustion devices are not required to have
a continuous parameter monitoring system for measuring the inlet flow
of gas to the device if you meet the conditions in paragraphs
(d)(8)(iv)(C)(1) and (2) of this section.
(1) You must demonstrate, based on the maximum potential pressure
of units manifolded to the enclosed combustion device and applicable
engineering calculations for the manifolded closed vent system, that
the maximum flow rate to the enclosed combustion device cannot cause
the maximum inlet flow rate established in accordance with paragraph
(f)(1) of this section to be exceeded. If there are changes to the
process or control device that can be reasonably expected to impact the
maximum flow rate to the enclosed combustion device, you must conduct a
new demonstration to determine whether the maximum flow rate to the
enclosed combustor is less than the maximum inlet flow rate established
in accordance with paragraph (f)(1) of this section.
(2) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an engineering evaluation. At
least annually, you must confirm that the backpressure regulator valve
set point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(D) Air-assisted flares or enclosed combustion devices that use
only perimeter assist air and have no assist steam or premix assist air
are not required to have a continuous parameter monitoring system for
measuring the inlet flow of gas to the device or the flow of assist air
if you meet the conditions in paragraphs (d)(8)(iv)(D)(1) and (2) of
this section. For these flares and enclosed combustion devices,
NHVcz is assumed to be equal to the vent gas NHV.
(1) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an engineering evaluation. At
least annually, you must confirm that the backpressure regulator valve
set point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(2) You must demonstrate, based on the maximum flow rate of
perimeter assist air to the enclosed combustion device or flare and
applicable engineering calculations, that the NHVdil can
never be less than the minimum required NHVdil. The
demonstration must clearly document why the maximum flow rate of
perimeter assist air will never exceed the rate used in the
demonstration. You must use the minimum flow rate of vent gas allowed
by your backpressure regulator valve and the minimum expected value of
the NHV of the inlet gas to the enclosed combustion device or flare
based on previous sampling results or process knowledge of the streams
sent to the enclosed combustion device or flare in your demonstration.
You must update this demonstration if there are changes to the
backpressure regulator valve, the backpressure regulator valve set
point, or the maximum flow rate of perimeter assist air. You must also
update this demonstration if any sampling results of the NHV of the
inlet gas to the enclosed combustion device or flare under paragraphs
(d)(8)(ii) or (iii) of this section are lower than the NHV vent gas
value used in your demonstration.
(E) Air-assisted flares or enclosed combustion devices that use
only premix assist air and have no assist steam or perimeter assist air
are not required to have a continuous parameter monitoring system for
measuring the inlet flow of gas to the device or the flow of assist air
if you meet the conditions in paragraphs (d)(8)(iv)(E)(1) and (2) of
this section.
(1) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an engineering evaluation. At
least annually, you must confirm that the backpressure regulator valve
set point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(2) You must demonstrate, based on the maximum flow rate of premix
assist air to the enclosed combustion device or flare and applicable
engineering calculations, that the NHVcz will never be less
than the minimum required NHVcz. The demonstration must
clearly document why the maximum flow rate of premix assist air will
never exceed
[[Page 17193]]
the rate used in the demonstration. You must use the minimum flow rate
of vent gas allowed by your backpressure regulator valve in and the
minimum expected value of the NHV of the inlet gas to the enclosed
combustion device or flare based on previous sampling results or
process knowledge of the streams sent to the enclosed combustion device
or flare in your demonstration. You must update this demonstration if
there are changes to the backpressure regulator valve, the backpressure
regulator valve set point, or the maximum flow rate of premix assist
air. You must also update this demonstration if any sampling results of
the NHV of the inlet gas to the enclosed combustion device or flare
under paragraphs (d)(8)(ii) or (iii) of this section are lower than the
NHV vent gas value used in your demonstration.
(v) Conduct inspections monthly and at other times as requested by
the Administrator to monitor for visible emissions from the combustion
device using section 11 of Method 22 of appendix A to this part or
conduct visible emissions monitoring according to paragraph (h) of this
section. The observation period shall be 15 minutes or once the amount
of time visible emissions is present has exceeded 1 minute. Devices
must be operated with no visible emissions, except for periods not to
exceed a total of 1 minute during any 15-minute period.
(vi) If you use a flare or enclosed combustion device that is air-
assisted or steam-assisted, you must also meet the following
requirements.
(A) Except as allowed by paragraph (d)(8)(iv)(E) of this section,
you must monitor and calculate NHVcz as specified in Sec.
63.670(m) of this chapter. Additionally, for flares and enclosed
combustion devices that use only perimeter assist air and do not use
steam assist or premix assist air, the NHVcz is equal to the
vent gas NHV. When NHVcz is equal to the vent gas NHV, you
are not required to continuously monitor NHVcz if you meet
the requirements in paragraph (d)(8)(iii) of this section.
(B) Except as allowed by paragraph (d)(8)(iv)(D) of this section,
for each flare using perimeter assist air, you must also monitor and
calculate NHVdil as specified in Sec. 63.670(n) of this
chapter. If the only assist air provided to the flare or enclosed
combustion control device is perimeter assist air intentionally
entrained in lower and/or upper steam at the flare tip and the
effective diameter is 9 inches or greater, you are only required to
comply with the NHVcz limit specified in paragraph
(f)(8)(vi)(A) of this section.
(C) Except as allowed by paragraph (d)(8)(iv) of this section, you
must monitor the flare vent gas and assist gas as specified in Sec.
63.670(i) of this chapter.
(D) You must determine the flare vent gas net heating value as
specified in Sec. 63.670(l) of this chapter using one of the methods
specified in paragraph (d)(8)(ii) of this section. Where the phrase
``petroleum refinery'' is used, for purposes of this subpart, it will
refer to flares controlling an affected facility under this subpart. If
you are not required to continuously monitor the NHV of the inlet gas
because you have demonstrated that it consistently exceeds the
applicable operating limit as provided in paragraph (d)(8)(iii) of this
section, you must use the lowest net heating value measured in the
sampling program in paragraph (d)(8)(iii) of this section for the
calculations performed in paragraphs (d)(8)(vi)(A) and (B) of this
section. You must update this value if a subsequent sampling result of
the NHV of the inlet gas to the enclosed combustion device or flare
under paragraph (d)(8)(iii) of this section is lower than the NHV vent
gas value used in your calculations.
(e) Calculate the value of the applicable monitored parameter in
accordance with paragraphs (e)(1) through (5) of this section.
(1) You must calculate the daily average value for condenser outlet
temperature for each operating day, using the data recorded by the
monitoring system. If the emissions unit operation is continuous, the
operating day is a 24-hour period. If the emissions unit operation is
not continuous, the operating day is the total number of hours of
control device operation per 24-hour period. Valid data points must be
available for 75 percent of the operating hours in an operating day to
compute the daily average.
(2) You must use the 5-minute readings from the heat sensing
devices to assess the presence of a pilot or combustion flame.
(3) You must use the regeneration cycle time (i.e., duration of the
carbon bed steaming cycle) for each regenerative-type carbon adsorption
system to calculate the average parameter to compare with the maximum
steam mass flow or volumetric flow during each carbon bed regeneration
cycle and the maximum carbon bed temperature during the steaming cycle.
The carbon bed temperature after the regeneration cycle should not be
averaged; you must use the carbon bed temperature measured within 15
minutes of completing the cooling cycle to compare with the minimum
carbon bed temperature after the regeneration cycle.
(4) You must use 15-minute blocks to calculate NHVcz and
NHVdil.
(5) For all operating parameters others than those described in
paragraphs (e)(1) through (4) of this section, you must calculate the
3-hour rolling average of each monitored parameter. For each operating
hour, calculate the hourly value of the operating parameter from your
continuous monitoring system. Average the three most recent hours of
data to determine the 3-hour average. Determine the 3-hour rolling
average by recalculating the 3-hour average each hour.
(f) For each operating parameter monitor installed in accordance
with the requirements of paragraph (d) of this section, you must comply
with paragraph (f)(1) of this section for all control devices. When
condensers are installed, you must also comply with paragraph (f)(2) of
this section.
(1) You must establish a minimum operating parameter value or a
maximum operating parameter value, as appropriate for the control
device, to define the conditions at which the control device must be
operated to continuously achieve the applicable performance
requirements of Sec. 60.5412c(a)(1) or (2). You must establish each
minimum or maximum operating parameter value as specified in paragraphs
(f)(1)(i) through (iv) of this section.
(i) If you conduct performance tests in accordance with the
requirements of Sec. 60.5413c(b) to demonstrate that the control
device achieves the applicable performance requirements specified in
Sec. 60.5412c(a)(1) or (2), then you must establish the minimum
operating parameter value or the maximum operating parameter value
based on values measured during the performance test and supplemented,
as necessary, by a condenser or carbon adsorption system design
analysis or control device manufacturer recommendations or a
combination of both. If you operate an enclosed combustion device, you
must establish the maximum inlet flow rate based on values measured
during the performance test and you may establish the minimum inlet
flow rate based on control device manufacturer recommendations.
(ii) If you use a condenser or carbon adsorption system design
analysis in accordance with the requirements of Sec. 60.5413c(c) to
demonstrate that the control device achieves the applicable performance
requirements specified in Sec. 60.5412c(a)(2), then you must establish
the minimum operating
[[Page 17194]]
parameter value or the maximum operating parameter value based on the
design analysis and supplemented, as necessary, by the manufacturer's
recommendations.
(iii) If you operate a control device where the performance test
requirement was met under Sec. 60.5413c(d) to demonstrate that the
control device achieves the applicable performance requirements
specified in Sec. 60.5412c(a)(1), then your control device inlet gas
flow rate must be equal to or greater than the minimum inlet gas flow
rate and equal to or less than the maximum inlet gas flow rate
determined by the manufacturer.
(iv) If you operate an enclosed combustion device where the
combustion zone temperature is not an indicator of destruction
efficiency or a control device where the performance test requirement
was met under Sec. 60.5413c(d), you must maintain the NHV of the gas
sent to the enclosed combustion device, the NHVcz, and the
NHVdil above the applicable limits specified in Sec.
60.5412c(a)(1)(iv)(A) through (D).
(2) If you use a condenser as specified in paragraph (d)(1)(v) of
this section, you must establish a condenser performance curve showing
the relationship between condenser outlet temperature and condenser
control efficiency, according to the requirements of paragraphs
(f)(2)(i) and (ii) of this section.
(i) If you conduct a performance test in accordance with the
requirements of Sec. 60.5413c(b) to demonstrate that the condenser
achieves the applicable performance requirements of Sec.
60.5412c(a)(2), then the condenser performance curve must be based on
values measured during the performance test and supplemented as
necessary by control device design analysis, or control device
manufacturer's recommendations, or a combination or both.
(ii) If you use a control device design analysis in accordance with
the requirements of Sec. 60.5413c(c)(1) to demonstrate that the
condenser achieves the applicable performance requirements specified in
Sec. 60.5412c(a)(2), then the condenser performance curve must be
based on the condenser design analysis and supplemented, as necessary,
by the control device manufacturer's recommendations.
(g) A deviation for a control device is determined to have occurred
when the monitoring data or lack of monitoring data result in any one
of the criteria specified in paragraphs (g)(1) through (7) of this
section being met. If you monitor multiple operating parameters for the
same control device during the same operating day and more than one of
these operating parameters meets a deviation criterion specified in
paragraphs (g)(1) through (7) of this section, then a single excursion
is determined to have occurred for the control device for that
operating day.
(1) A deviation occurs when the average value of a monitored
operating parameter determined in accordance with paragraph (e) of this
section is less than the minimum operating parameter limit (and, if
applicable, greater than the maximum operating parameter limit)
established in paragraph (f)(1) of this section; for flares, when the
average value of a monitored operating parameter determined in
accordance with paragraph (e) of this section is above the limits
specified in Sec. 60.5415c(e)(1)(vii)(B); or when the heat sensing
device indicates that there is no pilot or combustion flame present for
any time period. If you use a backpressure regulator valve to maintain
the inlet gas flow to an enclosed combustion device or flare above the
minimum value, a deviation occurs if the annual inspection finds that
the backpressure regulator valve set point is not set correctly or
indicates that the backpressure regulator valve does not fully close
when not in the open position.
(2) If you are subject to Sec. 60.5412c(a)(2), a deviation occurs
when the 365-day average condenser efficiency calculated according to
the requirements specified in Sec. 60.5415c(e)(1)(ix)(D) is less than
95.0 percent.
(3) If you are subject to Sec. 60.5412c(a)(2) and you have less
than 365 days of data, a deviation occurs when the average condenser
efficiency calculated according to the procedures specified in Sec.
60.5415c(e)(1)(ix)(D)(1) or (2) is less than 95.0 percent.
(4) A deviation occurs when the monitoring data are not available
for at least 75 percent of the operating hours in a day.
(5) If the closed vent system contains one or more bypass devices
that could be used to divert all or a portion of the gases, vapors, or
fumes from entering the control device, a deviation occurs when the
requirements of paragraph (g)(5)(i) or (ii) of this section are met.
(i) For each bypass line subject to Sec. 60.5411c(a)(4)(i)(A), the
flow indicator indicates that flow has been detected and that the
stream has been diverted away from the control device to the
atmosphere.
(ii) For each bypass line subject to Sec. 60.5411c(a)(4)(i)(B), if
the seal or closure mechanism has been broken, the bypass line valve
position has changed, the key for the lock-and-key type lock has been
checked out, or the car-seal has broken.
(6) For a combustion control device whose model is tested under
Sec. 60.5413c(d), a deviation occurs when the conditions of paragraphs
(g)(4), (g)(5), or (g)(6)(i) through (vi) of this section are met.
(i) The hourly inlet gas flow rate is less than the minimum inlet
gas flow rate or greater than the maximum inlet gas flow rate
determined by the manufacturer. If you use a backpressure regulator
valve to maintain the inlet gas flow above the minimum value, a
deviation occurs if the annual inspection finds that the backpressure
regulator valve set point is not set correctly or indicates that the
backpressure regulator valve does not fully close when not in the open
position.
(ii) Results of the monthly visible emissions test conducted under
Sec. 60.5413c(e)(3) or monitoring under paragraph (h) of this section
indicate visible emissions exceed 1 minute in any 15-minute period.
(iii) There is no indication of the presence of a pilot or
combustion flame for any 5-minute time period.
(iv) The control device is not maintained in a leak free condition.
(v) The control device is not operated in accordance with the
manufacturer's written operating instructions, procedures and
maintenance schedule.
(vi) The NHV of the vent gas, the NHVcz, or the
NHVdil is below the applicable limit specified in Sec.
60.5412c(a)(1)(iv).
(7) For an enclosed combustion device or flare subject to paragraph
(d)(8) of this section, a deviation occurs when any of the conditions
described by paragraphs (g)(1), (4), or (5) of this section are met or
when the results of the visible emissions monitoring conducted under
paragraph (d)(8)(v) or (h) of this section exceed 1 minute in any 15-
minute period.
(h) For enclosed combustion devices and flares, in lieu of
conducting a visible emissions observation using Method 22 of appendix
A-7 to this part, you may use a video surveillance camera to
continuously monitor and record the flare flame according to the
requirements in paragraphs (h)(1) through (6) of this section.
(1) You must provide real-time high-definition video surveillance
camera output (i.e., at least 720p) at a frame rate of at least 15
frames per second to the control room or other continuously manned
location where the camera
[[Page 17195]]
images may be viewed at the same resolution at any time.
(2) You must record at least one frame every 15 seconds with date
and time stamp.
(3) The camera must be located at a reasonable distance above the
flare flame at an angle suitable for visual emissions observations. The
position of the camera should be such that the sun is not in the field
of view.
(4) The camera must be located no more than 400 m (0.25 miles) from
the emission source.
(5) Operators must look at the video feed at least once daily for
an observation period of at least 1 minute to determine if visible
emissions are present. If visible emissions are present during a daily
observation, the operator must observe the video feed for 15 minutes or
until the amount of time visible emissions is present has exceeded 1
minute, whichever time period is less.
(6) Enclosed combustion devices and flares must be operated with no
visible emissions, except for periods not to exceed a total of 1 minute
during any 15-minute period.
(i) If you use an enclosed combustion device or flare using an
alternative test method approved under Sec. 60.5412c(d), you must
comply with paragraphs (i)(1) through (6) of this section.
(1) You must measure data values at the frequency specified in the
alternative test method.
(2) You must prepare a monitoring plan that covers each control
device for designated facilities within each company-defined area. The
monitoring plan must address the monitoring system design, data
collection, and the quality assurance and quality control elements
outlined in the alternative test method and in paragraphs (i)(2)(i)
through (iii) of this section. You must operate and maintain each
monitoring system in accordance with the procedures in your monitoring
plan.
(i) The performance criteria and design specifications for the
monitoring system equipment.
(ii) Location of monitoring system in relation to the monitored
control device.
(iii) Ongoing reporting and recordkeeping procedures.
(3) You must conduct the quality assurance and quality control
requirements outlined in the alternative test method at the frequency
outlined in the alternative test method.
(4) If required by Sec. 60.5412c(d)(4), you must conduct the
inspections required by paragraph (d)(8)(v) of this section.
(5) If required by Sec. 60.5412c(d)(5), you must install the pilot
or combustion flame monitoring system required by paragraph (d)(8)(i)
of this section.
(6) A deviation for the control device is determined to have
occurred when the monitoring data or lack of monitoring data result in
any one of the criteria specified in paragraphs (i)(6)(i) through (v)
of this section being met.
(i) A deviation occurs if the combustion efficiency is less than
95.0 percent, the combustion zone NHV is less than 270 Btu/scf, or the
NHV dilution parameter is less than 22 Btu/sqft.
(ii) A deviation occurs when the monitoring data are not available
for at least 75 percent of the operating hours in a day.
(iii) A deviation occurs when any of the conditions described by
paragraph (g)(5) of this section are met.
(iv) If required by paragraph (i)(4) of this section to conduct
visible emissions inspections, a deviation occurs when the results of
the visible emissions monitoring conducted under paragraph (d)(8)(v) or
(h) of this section exceeds 1 minute in any 15-minute period.
(v) If required by paragraph (i)(5) of this section to install a
pilot or combustion flame monitoring system, a deviation occurs when
there is no indication of the presence of a pilot or combustion flame
for any 5-minute period.
(j) You must submit annual reports for control devices as required
in Sec. 60.5420c(b)(1) and (10). You must maintain records as
specified in Sec. 60.5420c(c)(10).
Model Rule--Recordkeeping and Reporting
Sec. 60.5420c What are my notification, reporting, and recordkeeping
requirements?
(a) Notifications. You must submit notifications according to
paragraphs (a)(1) and (2) of this section if you own or operate one or
more of the designated facilities specified in Sec. 60.5386c for which
you commenced construction, modification, or reconstruction on or
before December 6, 2022. You must submit the notification in paragraph
(a)(4) of this section if you undertake well closure activities as
specified in Sec. 60.5397c(l).
(1) Notification of Compliance Report. For each designated facility
subject to the requirements specified under this subpart, an owner or
operator is required to submit a statement of compliance with the
applicable requirements of this subpart on or before 60 days after the
state plan compliance date. Where a designated facility's compliance
status is consistent with what was specified in the final compliance
plan increment of progress report, the notification of compliance
report would include a statement indicating that compliance is
consistent with what was specified in the designated facility's final
compliance plan. Where a designated facility's compliance status
differs from what was specified in the final compliance plan increment
of progress report, the notification of compliance report would
indicate how the designated facility's status differs from what was
stated in the final compliance plan.
(2) Notifications. If you own or operate a process unit equipment
designated facility located at an onshore natural gas processing plant,
you must submit the notifications required in Sec. Sec. 60.7(a)(1),
(3), and (4) and 60.15(d). If you own or operate a well, centrifugal
compressor, reciprocating compressor, process controller, pump, storage
vessel, collection of fugitive emissions components at a well site, or
collection of fugitive emissions components at a compressor station
designated facility, you are not required to submit the notifications
required in Sec. Sec. 60.7(a)(1), (3), and (4) and 60.15(d).
(3) Notification to Administrator. An owner or operator who
commences well closure activities must submit the following notices to
the Administrator according to the schedule in paragraph (a)(4)(i) and
(ii) of this section. The notification shall include contact
information for the owner or operator; the United States Well Number;
the latitude and longitude coordinates for each well at the well site
in decimal degrees to an accuracy and precision of five (5) decimals of
a degree using the North American Datum of 1983. You must submit
notifications in portable document format (PDF) following the
procedures specified in paragraph (d) of this section.
(i) You must submit a well closure plan to the Administrator within
30 days of the cessation of production from all wells located at the
well site.
(ii) You must submit a notification of the intent to close a well
site 60 days before you begin well closure activities.
(b) Reporting requirements. You must submit annual reports
containing the information specified in paragraphs (b)(1) through (13)
of this section following the procedure specified in paragraph (b)(14)
of this section. You must submit performance test reports as specified
in paragraph (b)(11) or (12) of this section, if applicable. The
initial annual report is due no later than 90 days after the end of the
initial compliance period as determined according to Sec. 60.5410c.
Subsequent annual reports are due no later than the
[[Page 17196]]
same date each year as the initial annual report. If you own or operate
more than one designated facility, you may submit one report for
multiple designated facilities provided the report contains all of the
information required as specified in paragraphs (b)(1) through (13) of
this section. Annual reports may coincide with title V reports as long
as all the required elements of the annual report are included. You may
arrange with the Administrator a common schedule on which reports
required by this part may be submitted as long as the schedule does not
extend the reporting period. You must submit the information in
paragraph (b)(1)(v) of this section, as applicable, for your well
designated facility which undergoes a change of ownership during the
reporting period, regardless of whether reporting under (b)(2) through
(3) of this section is required for the well designated facility.
(1) The general information specified in paragraphs (b)(1)(i)
through (v) of this section is required for all reports.
(i) The company name, facility site name associated with the
designated facility, U.S. Well ID or U.S. Well ID associated with the
designated facility, if applicable, and address of the designated
facility. If an address is not available for the site, include a
description of the site location and provide the latitude and longitude
coordinates of the site in decimal degrees to an accuracy and precision
of five (5) decimals of a degree using the North American Datum of
1983.
(ii) An identification of each designated facility being included
in the annual report.
(iii) Beginning and ending dates of the reporting period.
(iv) A certification by a certifying official of truth, accuracy,
and completeness. This certification shall state that, based on
information and belief formed after reasonable inquiry, the statements
and information in the document are true, accurate, and complete. If
your report is submitted via CEDRI, the certifier's electronic
signature during the submission process replaces the requirement in
this paragraph (b)(1)(iv).
(v) Identification of each well designated facility for which
ownership changed due to sale or transfer of ownership including the
United States Well Number; the latitude and longitude coordinates of
the well designated facility in decimal degrees to an accuracy and
precision of five (5) decimals of a degree using the North American
Datum of 1983; and the information in paragraph (b)(1)(v)(A) or (B) of
this section, as applicable.
(A) The name and contact information, including the phone number,
email address, and mailing address, of the owner or operator to which
you sold or transferred ownership of the well designated facility
identified in paragraph (b)(1)(v) of this section.
(B) The name and contact information, including the phone number,
email address, and mailing address, of the owner or operator from whom
you acquired the well designated facility identified in paragraph
(b)(1)(v) of this section.
(2) For each well designated facility that is subject to Sec.
60.5390c(a)(1) or (2), your annual report is required to include the
information specified in paragraphs (b)(2)(i) and (ii) of this section,
as applicable.
(i) For each well designated facility where all gas well liquids
unloading operations comply with Sec. 60.5390c(a)(1), your annual
report must include the information specified in paragraphs
(b)(2)(i)(A) through (C) of this section, as applicable.
(A) Identification of each well designated facility (U.S. Well ID
or U.S. Well ID associated with the well designated facility) that
conducts a gas well liquid unloading operation during the reporting
period using a method that does not vent to the atmosphere and the
technology or technique used. If more than one non-venting technology
or technique is used, you must identify all of the differing non-
venting liquids unloading methods used during the reporting period.
(B) Number of gas well liquids unloading operations conducted
during the year where the well designated facility identified in
(b)(2)(i)(A) had unplanned venting to the atmosphere and best
management practices were conducted according to your best management
practice plan, as required by Sec. 60.5390c(c). If no venting events
occurred, the number would be zero. Other reported information required
to be submitted where unplanned venting occurs is specified in
paragraphs (b)(2)(i)(B)(1) and (2) of this section.
(1) Log of best management practice plan steps used during the
unplanned venting to minimize emissions to the maximum extent possible.
(2) The number of liquids unloading events during the year where
deviations from your best management practice plan occurred, the date
and time the deviation began, the duration of the deviation in hours,
documentation of why best management practice plan steps were not
followed, and what steps, in lieu of your best management practice plan
steps, were followed to minimize emissions to the maximum extent
possible.
(C) The number of liquids unloading events where unplanned
emissions are vented to the atmosphere during a gas well liquids
unloading operation where you complied with best management practices
to minimize emissions to the maximum extent possible.
(ii) For each well designated facility where all gas well liquids
unloading operations comply with Sec. 60.5390c(b) and (c) best
management practices, your annual report must include the information
specified in paragraphs (b)(2)(ii)(A) through (E) of this section.
(A) Identification of each well designated facility that conducts a
gas well liquids unloading during the reporting period.
(B) Number of liquids unloading events conducted during the
reporting period.
(C) Log of best management practice plan steps used during the
reporting period to minimize emissions to the maximum extent possible.
(D) The number of liquids unloading events during the year that
best management practices were conducted according to your best
management practice plan.
(E) The number of liquids unloading events during the year where
deviations from your best management practice plan occurred, the date
and time the deviation began, the duration of the deviation in hours,
documentation of why best management practice plan steps were not
followed, and what steps, in lieu of your best management practice plan
steps, were followed to minimize emissions to the maximum extent
possible.
(3) For each associated gas well at your well designated facility
that is subject to Sec. 60.5391c, your annual report is required to
include the applicable information specified in paragraphs (b)(3)(i)
through (v) of this section, as applicable.
(i) For each associated gas well at your well designated facility
that complies with Sec. 60.5391c(a)(1), (2), (3), or (4) your annual
report is required to include the information specified in paragraphs
(b)(3)(i)(A) and (B) of this section.
(A) An identification of each existing associated gas well that
complies with Sec. 60.5391c(a)(1), (2), (3), or (4).
(B) The information specified in paragraphs (b)(3)(i)(B)(1) through
(3) of this section for each incident when the associated gas was
temporarily routed to a flare or control device in accordance with
Sec. 60.5377c(c).
(1) The reason in Sec. 60.5377c(c)(1), (2), (3), or (4) for each
incident.
[[Page 17197]]
(2) The start date and time of each incident of routing associated
gas to the flare or control device, along with the total duration in
hours of each incident.
(3) Documentation that all CVS requirements specified in Sec.
60.5411c(a) and (c) and all applicable flare or control device
requirements specified in Sec. 60.5412c were met during each period
when the associated gas is routed to the flare or control device.
(ii) For all instances where you temporarily vent the associated
gas in accordance with Sec. 60.5391c(d), you must report the
information specified in paragraphs (b)(3)(ii)(A) through (D) of this
section. This information is required to be reported if you are
routinely complying with Sec. 60.5391c(a) or Sec. 60.5391c(b) or
temporarily complying with Sec. 60.5391c(c). In addition to this
information for each incident, you must report the cumulative duration
in hours of venting incidents and the cumulative VOC and methane
emissions in pounds for all incidents in the calendar year.
(A) The reason in Sec. 60.5377c(d)(1), (2), or (3) for each
incident.
(B) The start date and time of each incident of venting the
associated gas, along with the total duration in hours of each
incident.
(C) The methane emissions in pounds that were emitted during each
incident.
(D) The total duration of venting for all incidents in the year,
along with the cumulative methane emissions in pounds that were
emitted.
(iii) For each associated gas well at your well designated facility
that complies with the requirements of Sec. 60.5391c(b) by routing
your associated gas to a control device that reduces methane emissions
by at least 95.0 percent, your annual report must include the
information specified in paragraphs (b)(3)(iii)(A) through (C) of this
section, and paragraph (D) or (E) of this section. The information in
paragraphs (b)(3)(iii)(A) and (B) of this section is only required in
the initial annual report.
(A) Identification of the associated gas well using the control
device and the information in paragraphs (b)(10)(v) of this section.
(B) The information specified in paragraphs (b)(10)(i) through (iv)
of this section.
(C) Identification of each instance when associated gas was vented
and not routed to a control device that reduces methane emissions by at
least 95.0 percent in accordance with paragraph (c)(3)(ii) of this
section.
(D) For each associated gas well that complies with the
requirements of Sec. 60.5391c(b) because it has demonstrated that
annual methane emissions are 40 tons per year or less, provide records
of the calculation of annual methane emissions determined in accordance
with Sec. 60.5391c(e)(1).
(E) For each associated gas well facility that complies with the
requirements of Sec. 60.5391c(c) because it has demonstrated that it
is not feasible to comply with Sec. 60.5391c(a)(1), (2), (3), or (4)
due to technical reasons, provide each annual demonstration and
certification of the technical reason that it is not feasible to comply
with Sec. 60.5377c(a)(1), (2), (3), and (4) in accordance with Sec.
60.5377c(b)(2)(i), (ii), and (iii).
(iv) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i)
and (ii) of this section, you must provide the information specified in
Sec. 60.5424c.
(v) For each deviation recorded as specified in paragraph
(c)(2)(iii) of this section, the date and time the deviation began, the
duration of the deviation in hours, and a description of the deviation.
If no deviations occurred during the reporting period, you must include
a statement that no deviations occurred during the reporting period.
(4) For each centrifugal compressor equipped with a wet seal
(including self-contained wet seal centrifugal compressors) and
centrifugal compressor equipped with sour seal oil separator and
capture system that is a designated facility, the information specified
in paragraphs (b)(4)(i) through (vii) of this section, as applicable.
For each centrifugal compressor equipped with a dry seal that is a
designated facility, the information specified in paragraphs (b)(4)(i)
through (xi) of this section.
(i) An identification of each centrifugal compressor.
(ii) For each deviation that occurred during the reporting period
and recorded as specified in paragraph (c)(3) of this section, the date
and time the deviation began, the duration of the deviation in hours,
and a description of the deviation. If no deviations occurred during
the reporting period, you must include a statement that no deviations
occurred during the reporting period.
(iii) If complying with Sec. 60.5392c(a)(1) and (2) wet and dry
seal centrifugal compressor requirements, the cumulative number of
hours of operation since initial startup, since 36 months after the
state plan submittal deadline (as specified in Sec. 60.5362c(c)), or
since the previous volumetric flow rate measurement, as applicable,
which have elapsed prior to conducting your volumetric flow rate
measurement or emissions screening.
(iv) A description of the method used and the results of the
volumetric emissions measurement or emissions screening, as applicable.
(v) If required to comply with Sec. 60.5392c(a)(5), the
information specified in paragraphs (b)(10)(i) through (iv) of this
section.
(vi) If complying with Sec. 60.5392c(a)(4) with a control device,
identification of the centrifugal compressor with the control device
and the information in paragraph (b)(10)(v) of this section.
(vii) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i)
and (ii) of this section, you must provide the information specified in
Sec. 60.5424c.
(viii) Number and type of seals on delay of repair and explanation
for each delay of repair.
(ix) Date of planned shutdown(s) that occurred during the reporting
period if there are any seals that have been placed on delay of repair.
(5) For each reciprocating compressor designated facility, the
information specified in paragraphs (b)(5)(i) through (vii) of this
section, as applicable.
(i) The cumulative number of hours of operation since initial
startup, since 36 months after the state plan submittal deadline (as
specified in Sec. 60.5362c(c)), since the previous volumetric flow
rate measurement, or since the previous reciprocating compressor rod
packing replacement, as applicable, which have elapsed prior to
conducting your volumetric flow rate measurement or emissions
screening. Alternatively, a statement that emissions from the rod
packing are being routed to a process or control device through a
closed vent system.
(ii) If applicable, for each deviation that occurred during the
reporting period and recorded as specified in paragraph (c)(4)(i) of
this section, the date and time the deviation began, duration of the
deviation in hours and a description of the deviation. If no deviations
occurred during the reporting period, you must include a statement that
no deviations occurred during the reporting period.
(iii) A description of the method used and the results of the
volumetric flow rate measurement or emissions screening, as applicable.
(iv) If complying with Sec. 60.5393c(d), the information in
paragraphs (b)(10)(i) through (v) of this section.
(v) Number and type of rod packing replacements/repairs on delay of
repair and explanation for each delay of repair.
[[Page 17198]]
(vi) Date of planned shutdown(s) that occurred during the reporting
period if there are any rod packing replacements/repairs that have been
placed on delay of repair.
(vii) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i)
and (ii) of this section, you must provide the information specified in
Sec. 60.5424c.
(6) For each process controller designated facility, the
information specified in paragraphs (b)(6)(i) through (iii) of this
section in your initial annual report and in subsequent annual reports
for each process controller designated facility that is constructed,
modified, or reconstructed during the reporting period. Each annual
report must contain the information specified in paragraphs (b)(6)(iv)
through (x) of this section for each process controller designated
facility.
(i) An identification of each existing process controller that is
driven by natural gas, as required by Sec. 60.5394c(d), that allows
traceability to the records required in paragraph (c)(5)(i) of this
section.
(ii) For each process controller in the designated facility
complying with Sec. 60.5394c(a), you must report the information
specified in paragraphs (b)(6)(ii)(A) and (B) of this section, as
applicable.
(A) An identification of each process controller complying with
Sec. 60.5394c(a)(1) by routing the emissions to a process.
(B) An identification of each process controller complying with
Sec. 60.5394c(a)(1) by using a self-contained natural gas-driven
process controller.
(iii) For each process controller designated facility located at a
site in Alaska that does not have access to electrical power and that
complies with Sec. 60.5394c(b), you must report the information
specified in paragraphs (b)(6)(iii)(A), (B), or (C) of this section, as
applicable.
(A) For each process controller complying with Sec. 60.5394c(b)(1)
process controller bleed rate requirements, you must report the
information specified in paragraphs (b)(6)(iii)(A)(1) and (2) of this
section.
(1) The identification of process controllers designed and operated
to achieve a bleed rate less than or equal to 6 scfh.
(2) Where necessary to meet a functional need, the identification
and demonstration of why it is necessary to use a process controller
with a natural gas bleed rate greater than 6 scfh.
(B) An identification of each intermittent vent process controller
complying with the requirements in paragraph Sec. 60.5394c(b)(2).
(C) An identification of each process controller complying with the
requirements in Sec. 60.5394c(b) by routing emissions to a control
device in accordance with Sec. 60.5394c(b)(3).
(iv) Identification of each process controller which changes its
method of compliance during the reporting period and the applicable
information specified in paragraphs (b)(6)(v) through (ix) of this
section for the new method of compliance.
(v) For each process controller in the designated facility
complying with the requirements of Sec. 60.5394c(a) by routing the
emissions to a process, you must report the information specified in
paragraphs (b)(10)(i) through (iii) of this section.
(vi) For each process controller in the designated facility
complying with the requirements of Sec. 60.5394c(a) by using a self-
contained natural gas-driven process controller, you must report the
information specified in paragraphs (b)(6)(vi)(A) and (B) of this
section.
(A) Dates of each inspection required under Sec. 60.5416c(b); and
(B) Each defect or leak identified during each natural gas-driven-
self-contained process controller system inspection, and the date of
repair or date of anticipated repair if repair is delayed.
(vii) For each process controller in the designated facility
complying with the requirements of Sec. 60.5394c(b)(2), you must
report the information specified in paragraphs (b)(6)(vii)(A) and (B)
of this section.
(A) Dates and results of the intermittent vent process controller
monitoring required by Sec. 60.5394c(b)(2)(ii).
(B) For each instance in which monitoring identifies emissions to
the atmosphere from an intermittent vent controller during idle
periods, the date of repair or replacement or the date of anticipated
repair or replacement if the repair or replacement is delayed, and the
date and results of the re-survey after repair or replacement.
(viii) For each process controller designated facility complying
with Sec. 60.5394c(b)(3) by routing emissions to a control device, you
must report the information specified in paragraph (b)(10) of this
section.
(ix) For each deviation that occurred during the reporting period,
the date and time the deviation began, the duration of the deviation in
hours, and a description of the deviation. If no deviations occurred
during the reporting period, you must include a statement that no
deviations occurred during the reporting period.
(x) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs
(b)(6)(ii)(B) and (b)(10)(i) and (ii) of this section, you must provide
the information specified in Sec. 60.5424c.
(7) For each storage vessel designated facility, the information in
paragraphs (b)(7)(i) through (x) of this section.
(i) An identification, including the location, of each existing
storage vessel designated facility. The location of the storage vessel
designated facility shall be in latitude and longitude coordinates in
decimal degrees to an accuracy and precision of five (5) decimals of a
degree using the North American Datum of 1983.
(ii) Documentation of the methane emission rate determination
according to Sec. 60.5386c(e)(1) for each tank battery that became a
designated facility during the reporting period or is returned to
service during the reporting period.
(iii) For each deviation that occurred during the reporting period
and recorded as specified in paragraph (c)(6)(iii) of this section, the
date and time the deviation began, duration of the deviation in hours
and a description of the deviation. If no deviations occurred during
the reporting period, you must include a statement that no deviations
occurred during the reporting period.
(iv) For each storage vessel designated facility complying with
Sec. 60.5396c(a)(2) with a control device, report the identification
of the storage vessel designated facility with the control device and
the information in paragraph (b)(10)(v) of this section.
(v) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i)
and (ii) of this section, you must provide the information specified in
Sec. 60.5424c.
(vi) If required to comply with Sec. 60.5396c(b)(1), the
information in paragraphs (b)(10)(i) through (iv) of this section.
(vii) You must identify each storage vessel designated facility
that is removed from service during the reporting period as specified
in Sec. 60.5396c(c)(1)(ii), including the date the storage vessel
designated facility was removed from service. You must identify each
storage vessel that that is removed from service from a storage vessel
designated facility during the reporting period as specified in Sec.
60.5396c(c)(2)(iii), including identifying the impacted storage vessel
designated facility and the date each
[[Page 17199]]
storage vessel was removed from service.
(viii) You must identify each storage vessel designated facility or
portion of a storage vessel designated facility returned to service
during the reporting period as specified in Sec. 60.5396c(c)(4),
including the date the storage vessel designated facility or portion of
a storage vessel designated facility was returned to service.
(ix) You must identify each storage vessel designated facility that
no longer complies with Sec. 60.5396c(a)(3) and instead complies with
Sec. 60.5396c(a)(2). You must identify whether the change in the
method of compliance was due to fracturing or refracturing or whether
the change was due to an increase in the monthly emissions
determination. If the change was due to an increase in the monthly
emissions determination, you must provide documentation of the
emissions rate. You must identify the date that you complied with Sec.
60.5396c(a)(2) and must submit the information in (b)(7)(iii) through
(vii) of this section.
(x) You must submit a statement that you are complying with Sec.
60.112b(a)(1) or (2), if applicable, in your initial annual report.
(8) For the fugitive emissions components designated facility,
report the information specified in paragraphs (b)(8)(i) through (iv)
of this section, as applicable.
(i)(A) Designation of the type of site (i.e., well site,
centralized production facility, or compressor station) at which the
fugitive emissions components designated facility is located.
(B) For the fugitive emissions components designated facility at a
well site or centralized production facility that became a designated
facility during the reporting period, you must include the date of the
startup of production or the date of the first day of production after
modification. For the fugitive emissions components designated facility
at a compressor station that became a designated facility during the
reporting period, you must include the date of startup or the date of
modification.
(C) For the fugitive emissions components designated facility at a
well site, you must specify what type of well site it is (i.e., single
wellhead only well site, small wellsite, multi-wellhead only well site,
or a well site with major production and processing equipment).
(D) For the fugitive emissions components designated facility at a
well site where during the reporting period you complete the removal of
all major production and processing equipment such that the well site
contains only one or more wellheads, you must include the date of the
change to status as a wellhead only well site.
(E) For the fugitive emissions components designated facility at a
well site where you previously reported under paragraph (b)(8)(i)(D) of
this section the removal of all major production and processing
equipment and during the reporting period major production and
processing equipment is added back to the well site, the date that the
first piece of major production and processing equipment is added back
to the well site.
(F) For the fugitive emissions components designated facility at a
well site where during the reporting period you undertake well closure
requirements, the date of the cessation of production from all wells at
the well site, the date you began well closure activities at the well
site, and the dates of the notifications submitted in accordance with
paragraph (a)(5) of this section.
(ii) For each fugitive emissions monitoring survey performed during
the annual reporting period, the information specified in paragraphs
(b)(8)(ii)(A) through (G) of this section.
(A) Date of the survey.
(B) Monitoring instrument or, if the survey was conducted by
visual, audible, or olfactory methods, notation that AVO was used.
(C) Any deviations from the monitoring plan elements under Sec.
60.5397c(c)(1), (2), and (7), (c)(8)(i), or (d) or a statement that
there were no deviations from these elements of the monitoring plan.
(D) Number and type of components for which fugitive emissions were
detected.
(E) Number and type of fugitive emissions components that were not
repaired as required in Sec. 60.5397c(h).
(F) Number and type of fugitive emission components (including
designation as difficult-to-monitor or unsafe-to-monitor, if
applicable) on delay of repair and explanation for each delay of
repair.
(G) Date of planned shutdown(s) that occurred during the reporting
period if there are any components that have been placed on delay of
repair.
(iii) For well closure activities which occurred during the
reporting period, the information in paragraphs (b)(8)(iii)(A) and (B)
of this section.
(A) A status report with dates for the well closure activities
schedule developed in the well closure plan. If all steps in the well
closure plan are completed in the reporting period, the date that all
activities are completed.
(B) If an OGI survey is conducted during the reporting period, the
information in paragraphs (b)(8)(iii)(B)(1) through (3) of this
section.
(1) Date of the OGI survey.
(2) Monitoring instrument used.
(3) A statement that no fugitive emissions were found, or if
fugitive emissions were found, a description of the steps taken to
eliminate those emissions, the date of the resurvey, the results of the
resurvey, and the date of the final resurvey which detected no
emissions.
(iv) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i)
and (ii) of this section, you must provide the information specified in
Sec. 60.5424c.
(9) For each pump designated facility, the information specified in
paragraphs (b)(9)(i) through (iv) of this section in your initial
annual report. Each annual report must contain the information
specified in paragraphs (b)(9)(v) through (ix) of this section for each
pump designated facility.
(i) The identification of each of your pumps that are driven by
natural gas, as required by Sec. 60.5395c(a) that allows traceability
to the records required by paragraph (c)(14)(i) of this section.
(ii) For each pump designated facility for which there is a control
device on site but it does not achieve a 95.0 percent emissions
reduction, the certification that there is a control device available
on site but it does not achieve a 95.0 percent emissions reduction
required under Sec. 60.5395c(b)(5). You must also report the emissions
reduction percentage the control device is designed to achieve.
(iii) For each pump designated facility for which there is no
control device or vapor recovery unit on site, the certification
required under Sec. 60.5395c(b)(6) that there is no control device or
vapor recovery unit on site.
(iv) For each pump designated facility for which it is technically
infeasible to route the emissions to a process or control device, the
certification of technically infeasibility required under Sec.
60.5395c(b)(7).
(v) For any pump designated facility which has previously reported
as required under paragraphs (b)(9)(i) through (iv) of this section and
for which a change in the reported condition has occurred during the
reporting period, provide the identification of the pump designated
facility and the date that the pump designated facility meets one of
the change conditions described in
[[Page 17200]]
paragraphs (b)(9)(v)(A) through (C) of this section.
(A) If you install a control device or vapor recovery unit, you
must report that a control device or vapor recovery unit has been added
to the site and that the pump designated facility now is required to
comply with Sec. 60.5395c(b)(1) or (3), as applicable.
(B) If your pump designated facility previously complied with Sec.
60.5395c(b)(1) or (3), as applicable. by routing emissions to a process
or a control device and the process or control device is subsequently
removed from the site or is no longer available such that there is no
ability to route the emissions to a process or control device at the
location, or that it is not technically feasible to capture and route
the emissions to another control device or process located on site,
report that you are no longer complying with the applicable
requirements of Sec. 60.5395c(b)(1) or (3) and submit the information
provided in paragraphs (b)(9)(v)(B)(1) or (2) of this section.
(1) Certification that there is no control device or vapor recovery
unit on site.
(2) Certification of the engineering assessment that it is
technically infeasible to capture and route the emissions to another
control device or process located on site.
(C) If any pump affected facility or individual natural gas-driven
pump changes its method of compliance during the reporting period other
than for the reasons specified in paragraphs (b)(9)(v)(A) and (B) of
this section, identify the new compliance method for each natural gas-
driven pump within the affected facility which changes its method of
compliance during the reporting period and provide the applicable
information specified in paragraphs (b)(9)(ii) through (iv) and (vi)
through (viii) of this section for the new method of compliance.
(vi) For each pump designated facility complying with the
requirements of Sec. 60.5395c(a) or (b)(2) by routing the emissions to
a process, you must report the information specified in paragraphs
(b)(11)(i) through (iv) of this section.
(vii) For each pump designated facility complying with the
requirements of Sec. 60.5395c(b)(3) by routing the emissions to a
control device, you must report the information required under
paragraph (b)(11) of this section.
(viii) For each deviation that occurred during the reporting
period, the date and time the deviation began, the duration of the
deviation in hours, and a description of the deviation. If no
deviations occurred during the reporting period, you must include a
statement that no deviations occurred during the reporting period.
(ix) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i)
and (ii) of this section, you must provide the information specified in
Sec. 60.5424c.
(10) For each well, centrifugal compressor, reciprocating
compressor, storage vessel, process controller, pump, or process unit
equipment designated facility which uses a closed vent system routed to
a control device to meet the emissions reduction standard, you must
submit the information in paragraphs (b)(10)(i) through (v) of this
section. For each centrifugal compressor, reciprocating compressor,
process controller, pump, storage vessel, or process unit equipment
which uses a closed vent system to route to a process, you must submit
the information in paragraphs (b)(10)(i) through (iv) of this section.
For each centrifugal compressor and storage vessel equipped with a
cover, you must submit the information in paragraphs (b)(10)(i) and
(ii).
(i) Dates of each inspection required under Sec. 60.5416c(a) and
(b).
(ii) Each defect or emissions identified during each inspection and
the date of repair or the date of anticipated repair if the repair is
delayed.
(iii) Date and time of each bypass alarm or each instance the key
is checked out if you are subject to the bypass requirements of Sec.
60.5416c(a)(4).
(iv) You must submit the certification signed by the qualified
professional engineer or in-house engineer according to Sec.
60.5411c(c) for each closed vent system routing to a control device or
process in the reporting year in which the certification is signed.
(v) If you comply with the emissions standard for your well,
centrifugal compressor, reciprocating compressor, storage vessel,
process controller, pump, or process unit equipment designated facility
with a control device, the information in paragraphs (b)(10)(v)(A)
through (L) of this section, unless you use an enclosed combustion
device or flare using an alternative test method approved under Sec.
60.5412c(d). If you use an enclosed combustion device or flare using an
alternative test method approved under Sec. 60.5412c(d), the
information in paragraphs (b)(10)(v)(A) through (C) and (L) through (P)
of this section.
(A) Identification of the control device.
(B) Make, model, and date of installation of the control device.
(C) Identification of the designated facility controlled by the
device.
(D) For each continuous parameter monitoring system used to
demonstrate compliance for the control device, a unique continuous
parameter monitoring system identifier and the make, model number, and
date of last calibration check of the continuous parameter monitoring
system.
(E) For each instance where there is a deviation of the control
device in accordance with Sec. 60.5417c(g)(1) through (3) or (5)
through (7) include the date and time the deviation began, the duration
of the deviation in hours, the type of the deviation (e.g., NHV
operating limit, lack of pilot or combustion flame, condenser
efficiency, bypass line flow, visible emissions), and cause of the
deviation.
(F) For each instance where there is a deviation of the continuous
parameter monitoring system in accordance with Sec. 60.5417c(g)(4)
include the date and time the deviation began, the duration of the
deviation in hours, and cause of the deviation.
(G) For each visible emissions test following return to operation
from a maintenance or repair activity, the date of the visible
emissions test or observation of the video surveillance output, the
length of the observation in minutes, and the number of minutes for
which visible emissions were present.
(H) If a performance test was conducted on the control device
during the reporting period, provide the date the performance test was
conducted. Submit the performance test report following the procedures
specified in paragraph (b)(11) of this section.
(I) If a demonstration of the NHV of the inlet gas to the enclosed
combustion device or flare was conducted during the reporting period in
accordance with Sec. 60.5417c(d)(8)(iii), an indication of whether
this is a re-evaluation of vent gas NHV and the reason for the re-
evaluation; the applicable required minimum vent gas NHV; if twice
daily samples of the vent stream were taken, the number of hourly
average NHV values that are less than 1.2 times the applicable required
minimum NHV; if continuous NHV sampling of the vent stream was
conducted, the number of hourly average NHV values that are less than
the required minimum vent gas NHV; if continuous combustion efficiency
monitoring was conducted using an alternative test method approved
under Sec. 60.5412c(d), the number of values of the combustion
efficiency that were less than 95.0 percent; the resulting
determination of whether NHV monitoring is required or not in
accordance with
[[Page 17201]]
Sec. 60.5417c(d)(8)(iii)(D) or (H); and an indication of whether the
enclosed combustion device or flare has the potential to receive inert
gases, and if so, whether the sampling included periods where the
highest percentage of inert gases were sent to the enclosed combustion
device or flare.
(J) If a demonstration was conducted in accordance with Sec.
60.5417c(d)(8)(iv) that the maximum potential pressure of units
manifolded to an enclosed combustion device or flare cannot cause the
maximum inlet flow rate established in accordance with Sec.
60.5417c(f)(1) or a flare tip velocity limit of 18.3 meter/second (60
feet/second) to be exceeded, an indication of whether this is a re-
evaluation of the gas flow and the reason for the re-evaluation; the
demonstration conducted; and applicable engineering calculations.
(K) For each periodic sampling event conducted under Sec.
60.5417c(d)(8)(iii)(G), provide the date of the sampling, the required
minimum vent gas NHV, and the NHV value for each vent gas sample.
(L) For each flare and enclosed combustion device, provide the date
each device is observed with OGI in accordance with Sec.
60.5415c(e)(x) and whether uncombusted emissions were present. Provide
the date each device was visibly observed during an AVO inspection in
accordance with Sec. 60.5415c(e)(x), whether the pilot or combustion
flame was lit at the time of observation, and whether the device was
found to be operating properly.
(M) An identification of the alternative test method used.
(N) For each instance where there is a deviation of the control
device in accordance with Sec. 60.5417c(i)(6)(i) or (iii) through (v)
include the date and time the deviation began, the duration of the
deviation in hours, the type of the deviation (e.g., NHVcz
operating limit, lack of pilot or combustion flame, visible emissions),
and cause of the deviation.
(O) For each instance where there is a deviation of the data
availability in accordance with Sec. 60.5417c(i)(6)(ii) include the
date of each operating day when monitoring data are not available for
at least 75 percent of the operating hours.
(P) If no deviations occurred under paragraphs (b)(11)(v)(N) or (O)
of this section, a statement that there were no deviations for the
control device during the annual report period.
(Q) Any additional information required to be reported as specified
by the Administrator as part of the alternative test method approval
under Sec. 60.5412c(d).
(11) Within 60 days after the date of completing each performance
test (see Sec. 60.8) required by this subpart, except testing
conducted by the manufacturer as specified in Sec. 60.5413c(d), you
must submit the results of the performance test following the
procedures specified in paragraph (d) of this section. Data collected
using test methods that are supported by the EPA's Electronic Reporting
Tool (ERT) as listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at
the time of the test must be submitted in a file format generated using
the EPA's ERT. Alternatively, you may submit an electronic file
consistent with the extensible markup language (XML) schema listed on
the EPA's ERT website. Data collected using test methods that are not
supported by the EPA's ERT as listed on the EPA's ERT website at the
time of the test must be included as an attachment in the ERT or
alternate electronic file.
(12) For combustion control devices tested by the manufacturer in
accordance with Sec. 60.5413c(d), an electronic copy of the
performance test results required by Sec. 60.5413c(d) shall be
submitted via email to [email protected] unless the test
results for that model of combustion control device are posted at the
following website: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.
(13) If you had a super-emitter event during the reporting period,
the start date of the super-emitter event, the duration of the super-
emitter event in hours, and the designated facility associated with the
super-emitter event, if applicable.
(14) You must submit your annual report using the appropriate
electronic report template on the Compliance and Emissions Data
Reporting Interface (CEDRI) website for this subpart and following the
procedure specified in paragraph (d) of this section. If the reporting
form specific to this subpart is not available on the CEDRI website at
the time that the report is due, you must submit the report to the
Administrator at the appropriate address listed in Sec. 60.4. Once the
form has been available on the CEDRI website for at least 90 calendar
days, you must begin submitting all subsequent reports via CEDRI. The
date reporting forms become available will be listed on the CEDRI
website. Unless the Administrator or delegated state agency or other
authority has approved a different schedule for submission of reports,
the report must be submitted by the deadline specified in this subpart,
regardless of the method in which the report is submitted.
(c) Recordkeeping requirements. You must maintain the records
identified as specified in Sec. 60.7(f) and in paragraphs (c)(1)
through (14) of this section. All records required by this subpart must
be maintained either onsite or at the nearest local field office for at
least 5 years. Any records required to be maintained by this subpart
that are submitted electronically via the EPA's CEDRI may be maintained
in electronic format. This ability to maintain electronic copies does
not affect the requirement for facilities to make records, data, and
reports available upon request to a delegated air agency or the EPA as
part of an on-site compliance evaluation.
(1) For each gas well liquids unloading operation at your well
designated facility that is subject to Sec. 60.5390c(a)(1) or (2), the
records of each gas well liquids unloading operation conducted during
the reporting period, including the information specified in paragraphs
(c)(1)(i) through (iii) of this section, as applicable.
(i) For each gas well liquids unloading operation that complies
with Sec. 60.5390c(a)(1) by performing all liquids unloading events
without venting of methane emissions to the atmosphere, comply with the
recordkeeping requirements specified in paragraphs (c)(1)(i)(A) and (B)
of this section.
(A) Identification of each well (i.e., U.S. Well ID or U.S. Well ID
associated with the well designated facility) that conducts a gas well
liquids unloading operation during the reporting period without venting
of methane emissions and the non-venting gas well liquids unloading
method used. If more than one non-venting method is used, you must
maintain records of all the differing non-venting liquids unloading
methods used at the well designated facility complying with Sec.
60.5376c(a)(1).
(B) Number of events where unplanned emissions are vented to the
atmosphere during a gas well liquids unloading operation where you
complied with best management practices to minimize emissions to the
maximum extent possible.
(ii) For each gas well liquids unloading operation that complies
with Sec. 60.5390c(b) and (c) best management practices, maintain
records documenting information specified in paragraphs (c)(1)(ii)(A)
through (D) of this section.
(A) Identification of each well designated facility that conducts
liquids unloading during the reporting period
[[Page 17202]]
that employs best management practices to minimize emissions to the
maximum extent possible.
(B) Documentation of your best management practice plan developed
under paragraph Sec. 60.5390c(c). You may update your best management
practice plan to include additional steps which meet the criteria in
Sec. 60.5390c(c).
(C) A log of each best management practice plan step taken minimize
emissions to the maximum extent possible for each gas well liquids
unloading event.
(D) Documentation of each gas well liquids unloading event where
deviations from your best management practice plan steps occurred, the
date and time the deviation began, the duration of the deviation,
documentation of best management practice plans steps were not
followed, and the steps taken in lieu of your best management practice
plan steps during those events to minimize emissions to the maximum
extent possible.
(iii) For each well designated facility that reduces methane
emissions from well designated facility gas wells that unload liquids
by 95.0 percent by routing emissions to a control device through closed
vent system under Sec. 60.5390c(g), you must maintain the records in
paragraphs (c)(1)(iii)(A) through (E) of this section.
(A) If you comply with the emission reduction standard with a
control device, the information for each control device in paragraph
(c)(10) of this section.
(B) Records of the closed vent system inspection as specified
paragraph (c)(7) of this section.
(C) Records of the cover inspections as specified in paragraph
(c)(8) of this section.
(D) If applicable, the records of bypass monitoring as specified in
paragraph (c)(9) of this section.
(E) Records of the closed vent system assessment as specified in
paragraph (c)(11) of this section.
(2) For each associated gas well, you must maintain the applicable
records specified in paragraphs (c)(2)(i) or (ii) and (vi) of this
section, as applicable.
(i) For each associated gas well that complies with the
requirements of Sec. 60.5391c(a)(1), (2), (3), or (4), you must keep
the records specified in paragraphs (c)(2)(i)(A) and (B) of this
section.
(A) Documentation of the specific method(s) in Sec.
60.5391c(a)(1), (2), (3), or (4) that was used.
(B) For instances where you temporarily route the associated gas to
a flare or control device in accordance with Sec. 60.5377c(c), you
must keep the records specified in paragraphs (c)(2)(i)(B)(1) through
(3) of this section.
(1) The reason in Sec. 60.5377c(c)(1), (2), (3), or (4) for each
incident.
(2) The date of each incident, along with the times when routing
the associated gas to the flare or control device started and ended,
along with the total duration of each incident.
(3) Documentation that all CVS requirements specified in Sec.
60.5411c(a) and (c) and all applicable flare or control device
requirements specified in Sec. 60.5412c are met during each period
when the associated gas is routed to the flare or control device.
(ii) For instances where you temporarily vent the associated gas in
accordance with Sec. 60.5377c(d), you must keep the records specified
in paragraphs (c)(2)(ii)(A) through (D) of this section. These records
are required if you are routinely complying with Sec. 60.5391c(a) or
Sec. 60.5391c(b) or temporarily complying with Sec. 60.5391c(c).
(A) The reason in Sec. 60.5391c(d)(1), (2), or (3) for each
incident.
(B) The date of each incident, along with the times when venting
the associated gas started and ended, along with the total duration of
each incident.
(C) The methane emissions that were emitted during each incident.
(D) The cumulative duration of venting incidents and methane
emissions for all incidents in each calendar year.
(iii) For each associated gas well that complies with the
requirements of Sec. 60.5391c(b) because it has demonstrated that
annual methane emissions are 40 tons per year or less at the initial
compliance date, maintain records of the calculation of annual methane
emissions determined in accordance with Sec. 60.5391c(e)(1).
(iv) For each associated gas well at your well that complies with
the requirements of Sec. 60.5391c(b) because it has demonstrated that
it is not feasible to comply with Sec. 60.5391c(a)(1), (2), (3), or
(4) due to technical reasons, records of each annual demonstration and
certification of the technical reason that it is not feasible to comply
with Sec. 60.5377c(a)(1), (2), (3), and (4) in accordance with Sec.
60.5377c(b)(2)(i), (ii), and (iii), as well as the records required by
paragraph (c)(2)(v) of this section.
(v) For each associated gas well that complies with the
requirements of Sec. 60.5391c(b) by routing your associated gas to a
flare or control device that achieves a 95.0 reduction in methane
emissions, the records in paragraphs (c)(2)(v)(A) through (E) of this
section.
(A) Identification of each instance when associated gas was vented
and not routed to a control device that reduces methane emissions by at
least 95.0 percent in accordance with paragraph (c)(2)(iii) of this
section.
(B) If you comply with the emission reduction standard in Sec.
60.5392c with a control device, the information for each control device
in paragraph (c)(10) of this section.
(C) Records of the closed vent system inspection as specified
paragraph (c)(7) of this section. If you comply with an alternative GHG
standard under Sec. 60.5398c, in lieu of the information specified in
paragraphs (c)(7) of this section, you must maintain records of the
information specified in Sec. 60.5424c.
(D) If applicable, the records of bypass monitoring as specified in
paragraph (c)(9) of this section.
(E) Records of the closed vent system assessment as specified in
paragraph (c)(11) of this section.
(vi) Records of each deviation, the date and time the deviation
began, the duration of the deviation, and a description of the
deviation.
(3) For each centrifugal compressor designated facility, you must
maintain the records specified in paragraphs (c)(3)(i) through (iii) of
this section.
(i) For each centrifugal compressor designated facility, you must
maintain records of deviations in cases where the centrifugal
compressor was not operated in compliance with the requirements
specified in Sec. 60.5392c, including a description of each deviation,
the date and time each deviation began and the duration of each
deviation.
(ii) For each wet seal compressor complying with the emissions
reduction standard in Sec. 60.5392c(a)(3) and (4), you must maintain
the records in paragraphs (c)(3)(ii)(A) through (F) of this section.
For each wet seal compressor complying with the alternative standard in
Sec. 60.5392c(a)(3) and (5) by routing the closed vent system to a
process, you must maintain the records in paragraphs (c)(3)(ii)(C)
through (E) of this section.
(A) If you comply with the emission reduction standard in with a
control device, the information for each control device in paragraph
(c)(10) of this section.
(B) Records of the closed vent system inspection as specified
paragraph (c)(7) of this section. If you comply with an alternative GHG
standard under Sec. 60.5398c, in lieu of the information specified in
paragraphs (c)(7) of this section, you must maintain records of the
information specified in Sec. 60.5424c.
(C) Records of the cover inspections as specified in paragraph
(c)(8) of this section. If you comply with an alternative GHG standard
under Sec. 60.5398c, in lieu of the information
[[Page 17203]]
specified in paragraph (c)(8) of this section, you must maintain the
information specified in Sec. 60.5424c.
(D) If applicable, the records of bypass monitoring as specified in
paragraph (c)(9) of this section.
(E) Records of the closed vent system assessment as specified in
paragraph (c)(11) of this section.
(iii) For each centrifugal compressor designated facility using dry
seals or wet seals and each self-contained wet seal centrifugal
compressor and complying with the standard in Sec. 60.5392c(a)(1) and
(2), you must maintain the records specified in paragraphs
(c)(3)(iii)(A) through (H) of this section.
(A) Records of the cumulative number of hours of operation since
initial startup, since 36 months after the state plan submittal
deadline (as specified in Sec. 60.5362c(c)), or since the previous
volumetric flow rate measurement, as applicable.
(B) A description of the method used and the results of the
volumetric flow rate measurement or emissions screening, as applicable.
(C) Records for all flow meters, composition analyzers and pressure
gauges used to measure volumetric flow rates as specified in paragraphs
(c)(3)(iii)(C)(1) through (7) of this section.
(1) Description of standard method published by a consensus-based
standards organization or industry standard practice.
(2) Records of volumetric flow rate emissions calculations
conducted according to Sec. 60.5392c(a)(2), as applicable.
(3) Records of manufacturer operating procedures and measurement
methods.
(4) Records of manufacturer's recommended procedures or an
appropriate industry consensus standard method for calibration and
results of calibration, recalibration and accuracy checks.
(5) Records which demonstrate that measurements at the remote
location(s) can, when appropriate correction factors are applied,
reliably and accurately represent the actual temperature or total
pressure at the flow meter under all expected ambient conditions. You
must include the date of the demonstration, the data from the
demonstration, the mathematical correlation(s) between the remote
readings and actual flow meter conditions derived from the data, and
any supporting engineering calculations. If adjustments were made to
the mathematical relationships, a record and description of such
adjustments.
(6) Record of each initial calibration or a recalibration which
failed to meet the required accuracy specification and the date of the
successful recalibration.
(D) Date when performance-based volumetric flow rate is exceeded.
(E) The date of successful repair of the compressor seal, including
follow-up performance-based volumetric flow rate measurement to confirm
successful repair.
(F) Identification of each compressor seal placed on delay of
repair and explanation for each delay of repair.
(G) For each compressor seal or part needed for repair placed on
delay of repair because of replacement seal or part unavailability, the
operator must document: the date the seal or part was added to the
delay of repair list, the date the replacement seal or part was
ordered, the anticipated seal or part delivery date (including any
estimated shipment or delivery date provided by the vendor), and the
actual arrival date of the seal or part.
(H) Date of planned shutdowns that occur while there are any seals
or parts that have been placed on delay of repair.
(4) For each reciprocating compressor designated facility, you must
maintain the records in paragraphs (c)(4)(i) through (vi), (7), (9) and
(11) of this section, as applicable. If you comply with an alternative
GHG standard under Sec. 60.5398c, in lieu of the information specified
in paragraph (c)(7) of this section, you must provide the information
specified in Sec. 60.5424c.
(i) For each reciprocating compressor designated facility, you must
maintain records of deviations in cases where the reciprocating
compressor was not operated in compliance with the requirements
specified in Sec. 60.5393c, including a description of each deviation,
the date and time each deviation began and the duration of each
deviation in hours.
(ii) Records of the date of installation of a rod packing emissions
collection system and closed vent system as specified in Sec.
60.5393c(d).
(iii) Records of the cumulative number of hours of operation since
initial startup, since 36 months after the state plan submittal
deadline (as specified in Sec. 60.5362c(c)), or since the previous
volumetric flow rate measurement, as applicable. Alternatively, a
record that emissions from the rod packing are being routed to a
process through a closed vent system.
(iv) A description of the method used and the results of the
volumetric flow rate measurement or emissions screening, as applicable.
(v) Records for all flow meters, composition analyzers and pressure
gauges used to measure volumetric flow rates as specified in paragraphs
(c)(4)(v)(A) through (F) of this section.
(A) Description of standard method published by a consensus-based
standards organization or industry standard practice.
(B) Records of volumetric flow rate calculations conducted
according to paragraphs Sec. 60.5393c(b) or (c), as applicable.
(C) Records of manufacturer's operating procedures and measurement
methods.
(D) Records of manufacturer's recommended procedures or an
appropriate industry consensus standard method for calibration and
results of calibration, recalibration and accuracy checks.
(E) Records which demonstrate that measurements at the remote
location(s) can, when appropriate correction factors are applied,
reliably and accurately represent the actual temperature or total
pressure at the flow meter under all expected ambient conditions. You
must include the date of the demonstration, the data from the
demonstration, the mathematical correlation(s) between the remote
readings and actual flow meter conditions derived from the data, and
any supporting engineering calculations. If adjustments were made to
the mathematical relationships, a record and description of such
adjustments.
(F) Record of each initial calibration or a recalibration which
failed to meet the required accuracy specification and the date of the
successful recalibration.
(vi) Date when performance-based volumetric flow rate is exceeded.
(vii) The date of successful replacement or repair of reciprocating
compressor rod packing, including follow-up performance-based
volumetric flow rate measurement to confirm successful repair.
(viii) Identification of each reciprocating compressor placed on
delay of repair because of rod packing or part unavailability and
explanation for each delay of repair.
(ix) For each reciprocating compressor that is placed on delay of
repair because of replacement rod packing or part unavailability, the
operator must document: the date the rod packing or part was added to
the delay of repair list, the date the replacement rod packing or part
was ordered, the anticipated rod packing or part delivery date
(including any estimated shipment or delivery date provided by the
vendor), and the actual arrival date of the rod packing or part.
(x) Date of planned shutdowns that occur while there are any
reciprocating
[[Page 17204]]
compressors that have been placed on delay of repair due to the
unavailability of rod packing or parts to conduct repairs.
(5) For each process controller designated facility, you must
maintain the records specified in paragraphs (c)(5)(i) through (vii) of
this section.
(i) Records identifying each process controller that is driven by
natural gas and that does not function as an emergency shutdown device.
(ii) For each process controller designated facility complying with
Sec. 60.5394c(a), you must maintain records of the information
specified in paragraphs (c)(5)(ii)(A) and (B) of this section, as
applicable.
(A) If you are complying with Sec. 60.5390c(a) by routing process
controller vapors to a process through a closed vent system, you must
report the information specified in paragraphs (c)(5)(ii)(A)(1) and (2)
of this section.
(1) An identification of all the natural gas-driven process
controllers in the process controller designated facility for which you
collect and route vapors to a process through a closed vent system.
(2) The records specified in paragraphs (c)(7), (9), and (11) of
this section. If you comply with an alternative GHG standard under
Sec. 60.5398c, in lieu of the information specified in paragraph
(c)(7) of this section, you must provide the information specified in
Sec. 60.5424c.
(B) If you are complying with Sec. 60.5394c(a) by using a self-
contained natural gas-driven process controller, you must report the
information specified in paragraphs (c)(5)(ii)(B)(1) through (3) of
this section.
(1) An identification of each process controller complying with
Sec. 60.5394c(a) by using a self-contained natural gas-driven process
controller;
(2) Dates of each inspection required under Sec. 60.5416c(b); and
(3) Each defect or leak identified during each natural gas-driven-
self-contained process controller system inspection, and date of repair
or date of anticipated repair if repair is delayed.
(iii) For each process controller designated facility complying
with Sec. 60.5394c(b)(1) process controller bleed rate requirements,
you must maintain records of the information specified in paragraphs
(c)(5)(iii)(A) and (B) of this section.
(A) The identification of process controllers designed and operated
to achieve a bleed rate less than or equal to 6 scfh and records of the
manufacturer's specifications indicating that the process controller is
designed with a natural gas bleed rate of less than or equal to 6 scfh.
(B) Where necessary to meet a functional need, the identification
of the process controller and demonstration of why it is necessary to
use a process controller with a natural gas bleed rate greater than 6
scfh.
(iv) For each intermittent vent process controller in the
designated facility complying with the requirements in Sec.
60.5394c(b)(2), you must keep records of the information specified in
paragraphs (c)(5)(iv)(A) through (C) of this section.
(A) The identification of each intermittent vent process
controller.
(B) Dates and results of the intermittent vent process controller
monitoring required by Sec. 60.5394c(b)(2)(ii).
(C) For each instance in which monitoring identifies emissions to
the atmosphere from an intermittent vent controller during idle
periods, the date of repair or replacement, or the date of anticipated
repair or replacement if the repair or replacement is delayed and the
date and results of the re-survey after repair or replacement.
(v) For each process controller designated facility complying with
Sec. 60.5394c(b)(3), you must maintain the records specified in
paragraphs (c)(5)(v)(A) and (B) of this section.
(A) An identification of each process controller for which
emissions are routed to a control device.
(B) Records specified in paragraphs (c)(7) and (9) through (12) of
this section. If you comply with an alternative GHG standard under
Sec. 60.5398c, in lieu of the information specified in paragraphs
(c)(7) of this section, you must provide the information specified in
Sec. 60.5424c.
(vi) Records of each change in compliance method, including
identification of each natural gas-driven process controller which
changes its method of compliance, the new method of compliance, and the
date of the change in compliance method.
(vii) Records of each deviation, the date and time the deviation
began, the duration of the deviation, and a description of the
deviation.
(6) For each storage vessel designated facility, you must maintain
the records identified in paragraphs (c)(6)(i) through (vii) of this
section.
(i) You must maintain records of the identification and location in
latitude and longitude coordinates in decimal degrees to an accuracy
and precision of five (5) decimals of a degree using the North American
Datum of 1983 of each storage vessel designated facility.
(ii) Records of each methane emissions determination for each
storage vessel designated facility made under Sec. 60.5396c(e)
including identification of the model or calculation methodology used
to calculate the methane emission rate.
(iii) For each instance where the storage vessel was not operated
in compliance with the requirements specified in Sec. 60.5396c, a
description of the deviation, the date and time each deviation began,
and the duration of the deviation.
(iv) If complying with the emissions reduction standard in Sec.
60.5396c(a)(1), you must maintain the records in paragraphs
(c)(6)(iv)(A) through (E) of this section.
(A) If you comply with the emission reduction standard with a
control device, the information for each control device in paragraph
(c)(10) of this section.
(B) Records of the closed vent system inspection as specified
paragraph (c)(7) of this section. If you comply with an alternative GHG
standard under Sec. 60.5398c, in lieu of the information specified in
paragraph (c)(7) of this section, you must provide the information
specified in Sec. 60.5424c.
(C) Records of the cover inspections as specified in paragraph
(c)(8) of this section. If you comply with an alternative GHG standard
under Sec. 60.5398c, in lieu of the information specified in paragraph
(c)(8) of this section, you must provide the information specified in
Sec. 60.5424c.
(D) If applicable, the records of bypass monitoring as specified in
paragraph (c)(9) of this section.
(E) Records of the closed vent system assessment as specified in
paragraph (c)(11) of this section.
(v) For storage vessels that are skid-mounted or permanently
attached to something that is mobile (such as trucks, railcars, barges,
or ships), records indicating the number of consecutive days that the
vessel is located at a site in the crude oil and natural gas source
category. If a storage vessel is removed from a site and, within 30
days, is either returned to the site or replaced by another storage
vessel at the site to serve the same or similar function, then the
entire period since the original storage vessel was first located at
the site, including the days when the storage vessel was removed, will
be added to the count towards the number of consecutive days.
(vi) Records of the date that each storage vessel designated
facility or portion of a storage vessel designated facility is removed
from service and returned to service, as applicable.
(vii) Records of the date that liquids from the well following
fracturing or refracturing are routed to the storage
[[Page 17205]]
vessel designated facility; or the date that you comply with paragraph
Sec. 60.5396c(a)(2), following a monthly emissions determination which
indicates that methane emissions increase to 14 tpy or greater and the
increase is not associated with fracturing or refracturing of a well
feeding the storage vessel designated facility, and records of the
methane emissions rate and the model or calculation methodology used to
calculate the methane emission rate.
(7) Records of each closed vent system inspection required under
Sec. 60.5416c(a)(1) and (2) and (b) for your well, centrifugal
compressor, reciprocating compressor, process controller, pump, storage
vessel, and process unit equipment designated facility as required in
paragraphs (c)(7)(i) through (iv) of this section.
(i) A record of each closed vent system inspection or no
identifiable emissions monitoring survey. You must include an
identification number for each closed vent system (or other unique
identification description selected by you), the date of the
inspection, and the method used to conduct the inspection (i.e.,
visual, AVO, OGI, Method 21 of appendix A-7 to this part).
(ii) For each defect or emissions detected during inspections
required by Sec. 60.5416c(a)(1) and (2), or (b) you must record the
location of the defect or emissions; a description of the defect; the
maximum concentration reading obtained if using Method 21 of appendix
A-7 to this part; the indication of emissions detected by AVO if using
AVO; the date of detection; the date of each attempt to repair the
emissions or defect; the corrective action taken during each attempt to
repair the defect; and the date the repair to correct the defect or
emissions is completed.
(iii) If repair of the defect is delayed as described in Sec.
60.5416c(b)(6), you must record the reason for the delay and the date
you expect to complete the repair.
(iv) Parts of the closed vent system designated as unsafe to
inspect as described in Sec. 60.5416c(b)(7) or difficult to inspect as
described in Sec. 60.5416c(b)(8), the reason for the designation, and
written plan for inspection of that part of the closed vent system.
(8) A record of each cover inspection required under Sec.
60.5416c(a)(3) for your centrifugal compressor, reciprocating
compressor, or storage vessel as required in paragraphs (c)(8)(i)
through (iv) of this section.
(i) A record of each cover inspection. You must include an
identification number for each cover (or other unique identification
description selected by you), the date of the inspection, and the
method used to conduct the inspection (i.e., AVO, OGI, Method 21 of
appendix A-7 to this part).
(ii) For each defect detected during the inspection you must record
the location of the defect; a description of the defect; the date of
detection; the maximum concentration reading obtained if using Method
21 of appendix A-7 to this part; the indication of emissions detected
by AVO if using AVO; the date of each attempt to repair the defect; the
corrective action taken during each attempt to repair the defect; and
the date the repair to correct the defect is completed.
(iii) If repair of the defect is delayed as described in Sec.
60.5416c(b)(5), you must record the reason for the delay and the date
you expect to complete the repair.
(iv) Parts of the cover designated as unsafe to inspect as
described in Sec. 60.5416c(b)(7) or difficult to inspect as described
in Sec. 60.5416c(b)(8), the reason for the designation, and written
plan for inspection of that part of the cover.
(9) For each bypass subject to the bypass requirements of Sec.
60.5416c(a)(4), you must maintain a record of the following, as
applicable: readings from the flow indicator; each inspection of the
seal or closure mechanism; the date and time of each instance the key
is checked out; date and time of each instance the alarm is sounded.
(10) Records for each control device used to comply with the
emission reduction standard in Sec. 60.5391c(b) for associated gas
wells, Sec. 60.5392c(a)(4) for centrifugal compressor designated
facilities, Sec. 60.5393c(d)(2) for reciprocating compressor
designated facilities, Sec. 60.5394c(b)(3) for your process controller
designated facility in Alaska, Sec. 60.5395c(b)(1) for your pump
designated facility, Sec. 60.5396c(a)(2) for your storage vessel
designated facility, Sec. 60.5390c(f) for well designated facility gas
well liquids unloading, or Sec. 60.5400c(f) or 60.5401c(e) for your
process equipment designated facility, as required in paragraphs
(c)(10)(i) through (viii) of this section. If you use an enclosed
combustion device or flare using an alternative test method approved
under Sec. 60.5412c(d), keep records of the information in paragraphs
(c)(10)(ix) of this section, in lieu of the records required by
paragraphs (c)(10)(i) through (iv) and (vi) through (viii) of this
section.
(i) For a control device tested under Sec. 60.5413c(d) which meets
the criteria in Sec. 60.5413c(d)(11) and (e), keep records of the
information in paragraphs (c)(10)(i)(A) through (E) of this section, in
addition to the records in paragraphs (c)(10)(ii) through (ix) of this
section, as applicable.
(A) Serial number of purchased device and copy of purchase order.
(B) Location of the designated facility associated with the control
device in latitude and longitude coordinates in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using the North
American Datum of 1983.
(C) Minimum and maximum inlet gas flow rate specified by the
manufacturer.
(D) Records of the maintenance and repair log as specified in Sec.
60.5413c(e)(4), for all inspection, repair, and maintenance activities
for each control device failing the visible emissions test.
(E) Records of the manufacturer's written operating instructions,
procedures, and maintenance schedule to ensure good air pollution
control practices for minimizing emissions.
(ii) For all control devices, keep records of the information in
paragraphs (c)(10)(ii)(A) through (G) of this section, as applicable.
(A) Make, model, and date of installation of the control device,
and identification of the designated facility controlled by the device.
(B) Records of deviations in accordance with Sec. 60.5417c(g)(1)
through (7), including a description of the deviation, the date and
time the deviation began, the duration of the deviation, and the cause
of the deviation.
(C) The monitoring plan required by Sec. 60.5417c(c)(2).
(D) Make and model number of each continuous parameter monitoring
system.
(E) Records of minimum and maximum operating parameter values,
continuous parameter monitoring system data (including records that the
pilot or combustion flame is present at all times), calculated averages
of continuous parameter monitoring system data, and results of all
compliance calculations.
(F) Records of continuous parameter monitoring system equipment
performance checks, system accuracy audits, performance evaluations, or
other audit procedures and results of all inspections specified in the
monitoring plan in accordance with Sec. 60.5417c(c)(2). Records of
calibration gas cylinders, if applicable.
[[Page 17206]]
(G) Periods of monitoring system malfunctions, repairs associated
with monitoring system malfunctions and required monitoring system
quality assurance or quality control activities Records of repairs on
the monitoring system.
(iii) For each carbon adsorption system, records of the schedule
for carbon replacement as determined by the design analysis
requirements of Sec. 60.5413c(c)(2) and (3) and records of each carbon
replacement as specified in Sec. 60.5412c(c)(1) and Sec.
60.5415c(e)(1)(viii).
(iv) For enclosed combustion devices and flares, records of visible
emissions observations as specified in paragraph (c)(10)(iv)(A) or (B)
of this section.
(A) Records of observations with Method 22 of appendix A-7 to this
part, including observations required following return to operation
from a maintenance or repair activity, which include: company,
location, company representative (name of the person performing the
observation), sky conditions, process unit (type of control device),
clock start time, observation period duration (in minutes and seconds),
accumulated emission time (in minutes and seconds), and clock end time.
You may create your own form including the above information or use
Figure 22-1 in Method 22 of appendix A-7 to this part.
(B) If you monitor visible emissions with a video surveillance
camera, location of the camera and distance to emission source, records
of the video surveillance output, and documentation that an operator
looked at the feed daily, including the date and start time of
observation, the length of observation, and length of time visible
emissions were present.
(v) For enclosed combustion devices and flares, video of the OGI
inspection conducted in accordance with Sec. 60.5415c(e)(x). Records
documenting each enclosed combustion device and flare was visibly
observed during each inspection conducted under Sec. 60.5397c using
AVO in accordance with Sec. 60.5415c(e)(x).
(vi) For enclosed combustion devices and flares, records of each
demonstration of the NHV of the inlet gas to the enclosed combustion
device or flare conducted in accordance with Sec. 60.5417c(d)(8)(iii).
For each re-evaluation of the NHV of the inlet gas, records of process
changes and explanation of the conditions that led to the need to re-
evaluation the NHV of the inlet gas. For each demonstration, record
information on whether the enclosed combustion device or flare has the
potential to receive inert gases, and if so, the highest percentage of
inert gases that can be sent to the enclosed combustion device or flare
and the highest percent of inert gases sent to the enclosed combustion
device or flare during the NHV demonstration. Records of periodic
sampling conducted under Sec. 60.5417c(d)(8)(iii)(G).
(vii) For enclosed combustion devices and flares, if you use a
backpressure regulator valve, the make and model of the valve, date of
installation, and record of inlet flow rating. Maintain records of the
engineering evaluation and manufacturer specifications that identify
the pressure set point corresponding to the minimum inlet gas flow
rate, the annual confirmation that the backpressure regulator valve set
point is correct and consistent with the engineering evaluation and
manufacturer specifications, and the annual confirmation that the
backpressure regulator valve fully closes when not in open position.
(viii) For enclosed combustion devices and flares, records of each
demonstration required under Sec. 60.5417c(d)(8)(iv).
(ix) If you use an enclosed combustion device or flare using an
alternative test method approved under Sec. 60.5412c(d), keep records
of the information in paragraphs (c)(10)(ix)(A) through (H) of this
section, in lieu of the records required by paragraphs (c)(10)(i)
through (iv) and (vi) through (viii) of this section.
(A) An identification of the alternative test method used.
(B) Data recorded at the intervals required by the alternative test
method.
(C) Monitoring plan required by Sec. 60.5417c(i)(2).
(D) Quality assurance and quality control activities conducted in
accordance with the alternative test method.
(E) If required by Sec. 60.5412c(d)(4) to conduct visible
emissions observations, records required by paragraph (c)(10)(iv) of
this section.
(F) If required by Sec. 60.5412c(d)(5) to conduct pilot or
combustion flame monitoring, record indicating the presence of a pilot
or combustion flame and periods when the pilot or combustion flame is
absent.
(G) For each instance where there is a deviation of the control
device in accordance with Sec. 60.5417c(i)(6)(i) through (v), the date
and time the deviation began, the duration of the deviation in hours,
and cause of the deviation.
(H) Any additional information required to be recorded as specified
by the Administrator as part of the alternative test method approval
under Sec. 60.5412c(d).
(11) For each closed vent system routing to a control device or
process, the records of the assessment conducted according to Sec.
60.5411c(c):
(i) A copy of the assessment conducted according to Sec.
60.5411c(c)(1); and
(ii) A copy of the certification according to Sec.
60.5411c(c)(1)(i) and (ii).
(12) A copy of each performance test submitted under paragraphs
(b)(11) or (12) of this section.
(13) For the fugitive emissions components designated facility,
maintain the records identified in paragraphs (c)(13)(i) through (vii)
of this section.
(i) The date of the startup of production or the date of the first
day of production after modification for the fugitive emissions
components designated facility at a well site and the date of startup
or the date of modification for the fugitive emissions components
designated facility at a compressor station.
(ii) For the fugitive emissions components designated facility at a
well site, you must maintain records specifying what type of well site
it is (i.e., single wellhead only well site, small wellsite, multi-
wellhead only well site, or a well site with major production and
processing equipment.)
(iii) For the fugitive emissions components designated facility at
a well site where you complete the removal of all major production and
processing equipment such that the well site contains only one or more
wellheads, record the date the well site completes the removal of all
major production and processing equipment from the well site, and, if
the well site is still producing, record the well ID or separate tank
battery ID receiving the production from the well site. If major
production and processing equipment is subsequently added back to the
well site, record the date that the first piece of major production and
processing equipment is added back to the well site.
(iv) The fugitive emissions monitoring plan as required in Sec.
60.5397c(b), (c), and (d).
(v) The records of each monitoring survey as specified in
paragraphs (c)(13)(v)(A) through (I) of this section.
(A) Date of the survey.
(B) Beginning and end time of the survey.
(C) Name of operator(s), training, and experience of the
operator(s) performing the survey.
(D) Monitoring instrument or method used.
[[Page 17207]]
(E) Fugitive emissions component identification when Method 21 of
appendix A-7 to this part is used to perform the monitoring survey.
(F) Ambient temperature, sky conditions, and maximum wind speed at
the time of the survey. For compressor stations, operating mode of each
compressor (i.e., operating, standby pressurized, and not operating-
depressurized modes) at the station at the time of the survey.
(G) Any deviations from the monitoring plan or a statement that
there were no deviations from the monitoring plan.
(H) Records of calibrations for the instrument used during the
monitoring survey.
(I) Documentation of each fugitive emission detected during the
monitoring survey, including the information specified in paragraphs
(c)(13)(v)(I)(1) through (9) of this section.
(1) Location of each fugitive emission identified.
(2) Type of fugitive emissions component, including designation as
difficult-to-monitor or unsafe-to-monitor, if applicable.
(3) If Method 21 of appendix A-7 to this part is used for
detection, record the component ID and instrument reading.
(4) For each repair that cannot be made during the monitoring
survey when the fugitive emissions are initially found, a digital
photograph or video must be taken of that component or the component
must be tagged for identification purposes. The digital photograph must
include the date that the photograph was taken and must clearly
identify the component by location within the site (e.g., the latitude
and longitude of the component or by other descriptive landmarks
visible in the picture). The digital photograph or identification
(e.g., tag) may be removed after the repair is completed, including
verification of repair with the resurvey.
(5) The date of first attempt at repair of the fugitive emissions
component(s).
(6) The date of successful repair of the fugitive emissions
component, including the resurvey to verify repair and instrument used
for the resurvey.
(7) Identification of each fugitive emission component placed on
delay of repair and explanation for each delay of repair.
(8) For each fugitive emission component placed on delay of repair
for reason of replacement component unavailability, the operator must
document: the date the component was added to the delay of repair list,
the date the replacement fugitive component or part thereof was
ordered, the anticipated component delivery date (including any
estimated shipment or delivery date provided by the vendor), and the
actual arrival date of the component.
(9) Date of planned shutdowns that occur while there are any
components that have been placed on delay of repair.
(vi) For well closure activities, you must maintain the information
specified in paragraphs (c)(13)(vi)(A) through (G) of this section.
(A) The well closure plan developed in accordance with Sec.
60.5397c(l) and the date the plan was submitted.
(B) The notification of the intent to close the well site and the
date the notification was submitted.
(C) The date of the cessation of production from all wells at the
well site.
(D) The date you began well closure activities at the well site.
(E) Each status report for the well closure activities reported in
paragraph (b)(8)(iv)(A) of this section.
(F) Each OGI survey reported in paragraph (b)(8)(iv)(B) of this
section including the date, the monitoring instrument used, and the
results of the survey or resurvey.
(G) The final OGI survey video demonstrating the closure of all
wells at the site. The video must include the date that the video was
taken and must identify the well site location by latitude and
longitude.
(vii) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs
(c)(13)(iv) and (v) of this section, you must maintain the records
specified in Sec. 60.5424c.
(14) For each pump designated facility, you must maintain the
records identified in paragraphs (c)(14)(i) through (viii) of this
section.
(i) Identification of each pump that is driven by natural gas and
that is in operation 90 days or more per calendar year.
(ii) If you are complying with Sec. 60.5395c(a) or (b)(1) by
routing pump vapors to a process through a closed vent system,
identification of all the natural gas-driven pumps in the pump
designated facility for which you collect and route vapors to a process
through a closed vent system and the records specified in paragraphs
(c)(7), (9), and (11) of this section. If you comply with an
alternative GHG and VOC standard under Sec. 60.5398c, in lieu of the
information specified in paragraph (c)(7) of this section, you must
provide the information specified in Sec. 60.5424c.
(iii) If you are complying with Sec. 60.5395c(b)(1) by routing
pump vapors to control device achieving a 95.0 percent reduction in
methane emissions, you must keep the records specified in paragraphs
(c)(7) and (c)(9) through (c)(12) of this section. If you comply with
an alternative GHG and VOC standard under Sec. 60.5398c, in lieu of
the information specified in paragraph (c)(7) of this section, you must
provide the information specified in Sec. 60.5424c.
(iv) If you are complying with Sec. 60.5395c(b)(3) by routing pump
vapors to a control device achieving less than a 95.0 percent reduction
in methane emissions, you must maintain records of the certification
that there is a control device on site but it does not achieve a 95.0
percent emissions reduction and a record of the design evaluation or
manufacturer's specifications which indicate the percentage reduction
the control device is designed to achieve.
(v) If you have less than three natural gas-driven diaphragm pumps
in the pump designated facility, and you do not have a vapor recovery
unit or control device installed on site by the compliance date, you
must retain a record of your certification required under Sec.
60.5395c(b)(4), certifying that there is no vapor recovery unit or
control device on site. If you subsequently install a control device or
vapor recovery unit, you must maintain the records required under
paragraphs (c)(14)(ii) and (iii) or (iv) of this section, as
applicable.
(vi) If you determine, through an engineering assessment, that it
is technically infeasible to route the pump designated facility
emissions to a process or control device, you must retain records of
your demonstration and certification that it is technically infeasible
as required under Sec. 60.5395c(b)(7).
(vii) If the pump is routed to a process or control device that is
subsequently removed from the location or is no longer available such
that there is no option to route to a process or control device, you
are required to retain records of this change and the records required
under paragraph (c)(14)(vi) of this section.
(viii) Records of each change in compliance method, including
identification of each natural gas-driven pump which changes its method
of compliance, the new method of compliance, and the date of the change
in compliance method.
(ix) Records of each deviation, the date and time the deviation
began, the duration of the deviation, and a description of the
deviation.
(d) Electronic reporting. If you are required to submit
notifications or reports following the procedure specified in this
paragraph (d), you must
[[Page 17208]]
submit notifications or reports to the EPA via CEDRI, which can be
accessed through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/). The EPA will make all the information submitted through
CEDRI available to the public without further notice to you. Do not use
CEDRI to submit information you claim as CBI. Although we do not expect
persons to assert a claim of CBI, if you wish to assert a CBI claim for
some of the information in the report or notification, you must submit
a complete file in the format specified in this subpart, including
information claimed to be CBI, to the EPA following the procedures in
paragraphs (g)(1) and (2) of this section. Clearly mark the part or all
of the information that you claim to be CBI. Information not marked as
CBI may be authorized for public release without prior notice.
Information marked as CBI will not be disclosed except in accordance
with procedures set forth in 40 CFR part 2. All CBI claims must be
asserted at the time of submission. Anything submitted using CEDRI
cannot later be claimed CBI. Furthermore, under CAA section 114(c),
emissions data is not entitled to confidential treatment, and the EPA
is required to make emissions data available to the public. Thus,
emissions data will not be protected as CBI and will be made publicly
available. You must submit the same file submitted to the CBI office
with the CBI omitted to the EPA via the EPA's CDX as described earlier
in this paragraph (d).
(1) The preferred method to receive CBI is for it to be transmitted
electronically using email attachments, File Transfer Protocol, or
other online file sharing services. Electronic submissions must be
transmitted directly to the OAQPS CBI Office at the email address
[email protected], and as described above, should include clear CBI
markings. ERT files should be flagged to the attention of the Group
Leader, Measurement Policy Group; all other files should be flagged to
the attention of the Oil and Natural Gas Sector Lead. If assistance is
needed with submitting large electronic files that exceed the file size
limit for email attachments, and if you do not have your own file
sharing service, please email [email protected] to request a file
transfer link.
(2) If you cannot transmit the file electronically, you may send
CBI information through the postal service to the following address:
U.S. EPA, Attn: OAQPS Document Control Officer, Mail Drop: C404-02, 109
T.W. Alexander Drive, P.O. Box 12055, RTP, NC 27711. ERT files should
be sent to the secondary attention of the Group Leader, Measurement
Policy Group, and all other files should be sent to the secondary
attention of the Oil and Natural Gas Sector Lead. The mailed CBI
material should be double wrapped and clearly marked. Any CBI markings
should not show through the outer envelope.
(e) Claims of EPA system outage. If you are required to
electronically submit a notification or report through CEDRI in the
EPA's CDX, you may assert a claim of EPA system outage for failure to
timely comply with that requirement. To assert a claim of EPA system
outage, you must meet the requirements outlined in paragraphs (e)(1)
through (7) of this section.
(1) You must have been or will be precluded from accessing CEDRI
and submitting a required report within the time prescribed due to an
outage of either the EPA's CEDRI or CDX systems.
(2) The outage must have occurred within the period of time
beginning five business days prior to the date that the submission is
due.
(3) The outage may be planned or unplanned.
(4) You must submit notification to the Administrator in writing as
soon as possible following the date you first knew, or through due
diligence should have known, that the event may cause or has caused a
delay in reporting.
(5) You must provide to the Administrator a written description
identifying:
(i) The date(s) and time(s) when CDX or CEDRI was accessed and the
system was unavailable;
(ii) A rationale for attributing the delay in reporting beyond the
regulatory deadline to EPA system outage;
(iii) A description of measures taken or to be taken to minimize
the delay in reporting; and
(iv) The date by which you propose to report, or if you have
already met the reporting requirement at the time of the notification,
the date you reported.
(6) The decision to accept the claim of EPA system outage and allow
an extension to the reporting deadline is solely within the discretion
of the Administrator.
(7) In any circumstance, the report must be submitted
electronically as soon as possible after the outage is resolved.
(f) Claims of force majeure. If you are required to electronically
submit a report or notification through CEDRI in the EPA's CDX, you may
assert a claim of force majeure for failure to timely comply with that
requirement. To assert a claim of force majeure, you must meet the
requirements outlined in paragraphs (f)(1) through (5) of this section.
(1) You may submit a claim if a force majeure event is about to
occur, occurs, or has occurred or there are lingering effects from such
an event within the period of time beginning five business days prior
to the date the submission is due. For the purposes of this section, a
force majeure event is defined as an event that will be or has been
caused by circumstances beyond the control of the designated facility,
its contractors, or any entity controlled by the designated facility
that prevents you from complying with the requirement to submit a
report electronically within the time period prescribed. Examples of
such events are acts of nature (e.g., hurricanes, earthquakes, or
floods), acts of war or terrorism, or equipment failure or safety
hazard beyond the control of the designated facility (e.g., large scale
power outage).
(2) You must submit notification to the Administrator in writing as
soon as possible following the date you first knew, or through due
diligence should have known, that the event may cause or has caused a
delay in reporting.
(3) You must provide to the Administrator:
(i) A written description of the force majeure event;
(ii) A rationale for attributing the delay in reporting beyond the
regulatory deadline to the force majeure event;
(iii) A description of measures taken or to be taken to minimize
the delay in reporting; and
(iv) The date by which you propose to report, or if you have
already met the reporting requirement at the time of the notification,
the date you reported.
(4) The decision to accept the claim of force majeure and allow an
extension to the reporting deadline is solely within the discretion of
the Administrator.
(5) In any circumstance, the reporting must occur as soon as
possible after the force majeure event occurs.
Sec. 60.5421c What are my additional recordkeeping requirements for
process unit equipment designated facilities?
You must maintain a record of each equipment leak monitoring
inspection and each leak identified under Sec. 60.5400c and Sec.
60.5401c as specified in paragraphs (b)(1) through (16) of this
section. The record must be maintained either onsite or at the nearest
local field office for at least 5 years. Any records required to be
maintained that are submitted electronically via the EPA's CEDRI may be
maintained in electronic format. This ability to maintain electronic
copies does not affect the requirement for facilities to make records,
data, and reports available
[[Page 17209]]
upon request to a delegated air agency or the EPA as part of an on-site
compliance evaluation.
(a) You may comply with the recordkeeping requirements for multiple
process unit equipment designated facilities in one recordkeeping
system if the system identifies each record by each facility.
(b) You must maintain the monitoring inspection records specified
in paragraphs (b)(1) through (16) of this section.
(1) Note that connectors need not be individually identified if all
connectors in a designated area or length of pipe subject to the
provisions of this subpart are identified as a group, and the number of
connectors subject is indicated.
(2) Date and start and end times of the monitoring inspection.
(3) Inspector name.
(4) Leak determination method used for the monitoring inspection
(i.e., OGI, Method 21, or AVO).
(5) Monitoring instrument identification (OGI and Method 21 only).
(6) Type of equipment monitored.
(7) Process unit identification.
(8) The records specified in Section 12 of appendix K to this part,
for each monitoring inspection conducted with OGI.
(9) The records in paragraph (b)(9)(i) through (vii) of this
section, for each monitoring inspection conducted with Method 21 of
appendix A-7 to this part.
(i) Instrument reading.
(ii) Date and time of instrument calibration and initials of
operator performing the calibration.
(iii) Calibration gas cylinder identification, certification date,
and certified concentration.
(iv) Instrument scale used.
(v) A description of any corrective action taken if the meter
readout could not be adjusted to correspond to the calibration gas
value in accordance with section 10.1 of Method 21 of appendix A-7 to
this part.
(vi) Results of the daily calibration drift assessment.
(vii) If you make your own calibration gas, a description of the
procedure used.
(10) For visual inspections of pumps in light liquid service, keep
the records specified in paragraphs (b)(10)(i) through (iii) of this
section, for each monitored equipment:
(i) Date of inspection.
(ii) Inspector name.
(iii) Result of inspection (i.e., visual indications of liquids
dripping from the pump seal or no visual indications of liquids
dripping from the pump seal).
(11) For each leak detected, the records specified in paragraphs
(b)(11)(i) through (v) of this section:
(i) The instrument and operator identification numbers and the
process unit and equipment identification numbers. For leaks identified
via visual, olfactory, audible methods, enter the specific sensory
method for instrument identification number.
(ii) The date the leak was detected.
(iii) For each attempt to repair the leak, record:
(A) The date.
(B) The repair method applied.
(C) Indication of whether a leak was still detected following each
attempt to repair the leak.
(vi) The date of successful repair of the leak and the method of
monitoring used to confirm the repair, as specified in paragraph
(b)(11)(vi)(A) through (C) of this section.
(A) If Method 21 of appendix A-7 to this part is used to confirm
the repair, maintain a record of the maximum instrument reading
measured by Method 21 of appendix A-7 to this part.
(B) If OGI conducted in accordance with appendix K to this part is
used to confirm the repair, maintain a record of video footage of the
repair confirmation.
(C) If the leak is repaired by eliminating AVO indications of a
leak, maintain a record of the specific sensory method used to confirm
that the evidence of the leak is eliminated.
(v) For each repair delayed beyond 15 calendar days after detection
of the leak, record:
(A) ``Repair delayed'' and the reason for the delay.
(B) The signature of the certifying official who made the decision
that repair could not be completed without a process shutdown.
(C) The expected date of successful repair of the leak.
(D) Dates of process unit shutdowns that occur while the equipment
is unrepaired.
(12) A list of identification numbers for equipment that are
designated for no detectable emissions complying with the provisions of
Sec. 60.5401c.
(13) A list of identification numbers for valves, pumps, and
connectors that are designated as unsafe-to-monitor, an explanation for
each valve, pump, or connector stating why the valve, pump, or
connector is unsafe-to-monitor, and the plan for monitoring each valve,
pump, or connector.
(14) A list of identification numbers for valves that are
designated as difficult-to-monitor, an explanation for each valve
stating why the valve is difficult-to-monitor, and the schedule for
monitoring each valve.
(15) A list of identification numbers for equipment that is in
vacuum service.
(16) A list of identification numbers for equipment you designate
as having the potential to emit methane less than 300 hr/yr.
(17) A list of identification numbers for valves where it was
infeasible to replace leaking valves with low-e valves or repack
existing valves with low-e packing technology, including the reasoning
for why it was infeasible.
Sec. 60.5422c What are my additional reporting requirements for
process unit equipment designated facilities?
(a) You must submit semiannual reports using the appropriate
electronic report template on the CEDRI website for this subpart and
following the procedure specified in Sec. 60.5420c(d). If the
reporting form specific to this subpart is not available on the CEDRI
website at the time that the report is due, submit the report to the
Administrator at the appropriate address listed in Sec. 60.4. Once the
form has been available on the CEDRI website for at least 90 calendar
days, you must begin submitting all subsequent reports via CEDRI. The
date reporting forms become available will be listed on the CEDRI
website. Unless the Administrator or delegated state agency or other
authority has approved a different schedule for submission of reports,
the report must be submitted within 45 days after the end of the
semiannual reporting period, regardless of the method in which the
report is submitted.
(b) The initial semiannual report must include the following
information:
(1) The general information specified in paragraph (c)(1) of this
section.
(2) For each process unit:
(i) Process unit identification.
(ii) Number of valves subject to the monitoring requirements of
Sec. 60.5400c(b) and Sec. 60.5401c(f).
(iii) Number of pumps subject to the monitoring requirements of
Sec. 60.5400c(b) and Sec. 60.5401c(b).
(iv) Number of connectors subject to the monitoring requirements of
Sec. 60.5400c(b) and Sec. 60.5401c(h).
(v) Number of pressure relief devices subject to the monitoring
requirements of Sec. 60.5400c(b) and Sec. 60.5401c(c).
(vi) The information in paragraphs (c)(3) and (4) of this section.
(c) All subsequent semiannual reports must include the following
information:
(1) The general information specified in paragraphs (c)(1)(i)
through (iii) of this section.
(i) The company name, facility site name, and address of the
designated facility.
[[Page 17210]]
(ii) Beginning and ending dates of the reporting period.
(iii) A certification by a certifying official of truth, accuracy,
and completeness. This certification shall state that, based on
information and belief formed after reasonable inquiry, the statements
and information in the document are true, accurate, and complete. If
your report is submitted via CEDRI, the certifier's electronic
signature during the submission process replaces the requirement in
this paragraph (c)(1)(iii).
(2) Process unit identification for each process unit.
(3) For each month during the semiannual reporting period for each
process unit report:
(i) Number of valves for which leaks were detected as described in
Sec. 60.5400c(b) or Sec. 60.5401c(f).
(ii) Number of valves for which leaks were not repaired as required
in Sec. 60.5400c(h) or Sec. 60.5401c(i) and the number of instances
where it was technically infeasible to replace leaking valves with low-
e valves or repack existing valves with low-e packing technology,
including the reasoning for why it was technically infeasible.
(iii) Number of pumps for which leaks were detected as described
Sec. 60.5400c(b) or Sec. 60.5401c(b).
(iv) Number of pumps for which leaks were not repaired as required
in Sec. 60.5400c(h) or Sec. 60.5401c(i).
(v) Number of connectors for which leaks were detected as described
in Sec. 60.5400c(b) or Sec. 60.5401c(h).
(vi) Number of connectors for which leaks were not repaired as
required in Sec. 60.5400c(h) or Sec. 60.5401c(i).
(vii) Number of pressure relief devices for which leaks were
detected as described in Sec. 60.5400c(b) or Sec. 60.5401c(c).
(viii) Number of pressure relief devices for which leaks were not
repaired as required in Sec. 60.5400c(h) or Sec. 60.5401c(i).
(ix) Number of open-ended valves or lines for which leaks were
detected as described in Sec. 60.5400c(e) of Sec. 60.5401c(d).
(x) Number of open-ended valves or lines for which leaks were not
repaired as required in Sec. 60.5400c(h) or Sec. 60.5401c(i).
(xi) Number of pumps, valves, or connectors in heavy liquid service
or pressure relief device in light liquid or heavy liquid service for
which leaks were detected as described in Sec. 60.5400c(g) or Sec.
60.5401c(g).
(xii) Number of pumps, valves, or connectors in heavy liquid
service or pressure relief device in light liquid or heavy liquid
service for which leaks were not repaired as required in Sec.
60.5400c(h) or Sec. 60.5401c(i).
(xiii) The facts that explain each delay of repair and, where
appropriate, why a process unit shutdown was technically infeasible.
(4) Dates of process unit shutdowns which occurred within the
semiannual reporting period.
(5) Revisions to items reported according to paragraph (b) of this
section if changes have occurred since the initial report or subsequent
revisions to the initial report.
Sec. 60.5424c What are my additional recordkeeping and reporting
requirements if I comply with the alternative GHG standards for
fugitive emissions components designated facilities and covers and
closed vent systems?
This section provides notification, reporting, and recordkeeping
requirements for owners and operators who choose to comply with an
alternative GHG standard as specified in Sec. 60.5398c for fugitive
emissions components designated facilities and the alternative
continuous inspection and monitoring requirements for covers and closed
vent systems. You must submit an annual report in accordance with the
schedule in Sec. 60.5420c(b) which includes the information in
paragraphs (a)(1), (b), and (d) of this section, as applicable. You
must submit the notification in paragraph (a)(2) of this section and
maintain the records in paragraphs (c) and (e) of this section, as
applicable.
(a) Notifications. If you choose to comply with an alternative GHG
standard as specified in Sec. 60.5398c for fugitive emissions
components designated facilities and the alternative continuous
inspection and monitoring requirements for covers and closed vent
systems, you must submit the notification in paragraph (a)(1) of this
section. If you are required by Sec. 60.5398c(c)(8) to develop a mass
emission rate reduction plan, you must submit the notification in
paragraph (a)(2) of this section.
(1) A notification to the Administrator of adoption of the
alternative standards in the annual report required by Sec.
60.5420c(b)(3) through (10).
(2) A notification, which includes the submittal of the mass
emission rate reduction plan required by Sec. 60.5398c(c)(8). You must
submit the mass emission rate reduction plan to the Administrator
within 60 days of the initial exceedance of the action level.
(b) If you comply with the periodic screening requirements of Sec.
60.5398c(b), you must submit the information in paragraphs (b)(1)
through (6) of this section in the annual report required by Sec.
60.5420c(b)(3) through (10).
(1) Date of each periodic screening during the reporting period and
date that results of the periodic screening were received.
(2) Alternative test method and technology used for each screening
and the spatial resolution of the technology (i.e., facility-level,
area-level, or component level).
(3) Any deviations from the monitoring plan developed under Sec.
60.5398c(b)(1) or a statement that there were no deviations from the
monitoring plan.
(4) Results from each periodic screening during the reporting
period. If the results of the periodic screening indicate a confirmed
detection of emissions from a designated facility, you must submit the
information in paragraphs (b)(4)(i) through (iv) of this section.
(i) The date that the monitoring survey of your entire or the
required portion of your fugitive emissions components designated
facility was conducted.
(ii) The date that you completed the instrument inspections of all
required covers and closed vent systems(s).
(iii) The date that you conducted the visual inspection for
emissions of all required closed vent systems and covers.
(iv) For each fugitive emission from a fugitive emissions
components designated facility and all emissions or defects of each
cover and closed vent system, you must submit the information in
paragraphs (b)(4)(iv)(A) through (D) of this section.
(A) Number and type of components for which fugitive emissions were
detected.
(B) Each emission or defect identified during the inspection for
each cover and closed vent system.
(C) Date of repair for each fugitive emission from a fugitive
emissions components designated facility or each emission or defect for
each cover and closed vent system.
(D) Number and type of fugitive emission components and
identification of each cover or closed vent system placed on delay of
repair and an explanation for each delay of repair.
(5) The information in paragraphs (b)(5)(i) through (iv) of this
section if you are required to conduct OGI surveys in accordance with
Sec. 60.5398c(b)(1)(i) or if you replace a periodic screening event
with an OGI survey in accordance with Sec. 60.5398c(b)(1)(iv).
(i) The date of the OGI survey.
[[Page 17211]]
(ii) Number and type of components for which fugitive emissions
were detected.
(iii) Number and type of fugitive emissions components that were
not repaired as required in Sec. 60.5397c(h).
(iv) Number and type of fugitive emission components placed on
delay of repair and an explanation for each delay of repair.
(6) Any additional information regarding the performance of the
periodic screening technology as specified by the Administrator, as
part of the alternative test method approval described in Sec.
60.5398b(d).
(c) If you comply with the periodic screening requirements of Sec.
60.5398c(b), you must maintain the records in paragraphs (c)(1) through
(11) of this section in addition to the records as specified in Sec.
60.5420c(c)(2) through (8) and (c)(13) and (14).
(1) The monitoring plan as required in Sec. 60.5398c(b)(2).
(2) Date of each periodic screening and date that results of the
periodic screening were received.
(3) Name of screening operator.
(4) Alternative test method and technology used for screening, as
well as the aggregate detection threshold for the technology and the
spatial resolution of the technology (i.e., facility-level, area-level,
or component-level).
(5) Records of calibrations for technology used during the
screening, if calibration is required by the alternative test method
approved in accordance with Sec. 60.5398b(d).
(6) Results from periodic screening. If the results of the periodic
screening indicate a confirmed detection of emissions from a designated
facility, you must maintain the records in paragraphs (c)(6)(i) through
(v) of this section.
(i) The date of the inspection of the fugitive emissions components
and inspection of covers and closed vent system, as specified in Sec.
60.5398c(b)(5).
(ii) Name of operator(s) performing the survey or inspection.
(iii) For surveys and instrument inspections, identification of the
monitoring instrument(s) used.
(iv) Records of calibrations for the instrument(s) used during the
survey or instrument inspection, as applicable.
(v) For each fugitive emission from a fugitive emissions components
designated facility and each leak or defect for each cover and closed
vent system inspection, you must maintain the records in paragraphs
(c)(6)(v)(A) through (F) of this section.
(A) The location of the fugitive emissions identified using a
unique identifier for the source of the emissions and the type of
fugitive emissions component.
(B) The location of the emission or defect from a cover or closed
vent system using a unique identifier for the source of the emission or
defect.
(C) If a defect of a closed vent system, cover, or control device
is identified, a description of the defect.
(D) The date of repair for each fugitive emission from a fugitive
emissions components designated facility or each emission or defect for
each cover and closed vent system.
(E) Number and type of fugitive emission components and
identification of each cover or closed vent system placed on delay of
repair and an explanation for each delay of repair.
(F) For each fugitive emission component placed on delay of repair
for reason of replacement component unavailability, the operator must
document: the date the component was added to the delay of repair list,
the date the replacement fugitive component or part thereof was
ordered, the anticipated component delivery date (including any
estimated shipment or delivery date provided by the vendor), and the
actual arrival date of the component.
(7) The date the investigative analysis was initiated, and the
result of the investigative analysis conducted in accordance with Sec.
60.5398c(b)(5)(vi) and (vii), as applicable.
(8) Dates of implementation and completion of action(s) taken as a
result of the investigative analysis and a description of the action(s)
taken in accordance with Sec. 60.5398c(b)(5)(vi) and (vii), as
applicable.
(9) The information in paragraphs (c)(9)(i) through (vii) of this
section if you are required to conduct OGI surveys in accordance with
Sec. 60.5398c(b)(1)(i) or if you replace a periodic screening event
with an OGI survey in accordance with Sec. 60.5398c(b)(1)(iv).
(i) The date of the OGI survey.
(ii) Location of each fugitive emission identified.
(iii) Type of fugitive emissions component for which fugitive
emissions were detected.
(iv) The date of first attempt at repair of the fugitive emissions
component(s).
(v) The date of successful repair of the fugitive emissions
component(s), including the resurvey to verify the repair.
(vi) Identification of each fugitive emissions component placed on
delay of repair and an explanation for each delay of repair.
(vii) For each fugitive emission component placed on delay of
repair for reason of replacement component unavailability, the operator
must document: the date the component was added to the delay of repair
list, the date the replacement fugitive component or part thereof was
ordered, the anticipated component delivery date (including any
estimated shipment or delivery date provided by the vendor), and the
actual arrival date of the component.
(10) Any deviations from the monitoring plan or a statement that
there were no deviations from the monitoring plan.
(11) All records required by the alternative approved in accordance
with Sec. 60.5398b(d).
(d) If you comply with the continuous monitoring system
requirements of Sec. 60.5398c(c), you must submit the information in
paragraphs (d)(1) through (6) of this section in the annual report
required by Sec. 60.5420c(b)(3) through (10).
(1) The start date and end date for each period where the emissions
rate determined in accordance with Sec. 60.5398c(c)(6) exceeded one of
the action levels determined in accordance with Sec. 60.5398c(c)(4).
Include which action level was exceeded (the 7-day or 90-day rolling
average), the numerical value of the action level, and the mass
emission rate calculated by the continuous monitoring system in the
report.
(2) The date the investigative analysis was initiated, and the
result of the investigative analysis conducted in accordance with Sec.
60.5398c(c)(7), as applicable.
(3) Dates of implementation and completion of action(s) taken to
reduce the mass emission rate and a description of the action(s) taken
in accordance with Sec. 60.5398c(c)(7), as applicable.
(4) If there are no instances reported under paragraph (d)(1) of
this section, report your numerical action levels and the highest 7-day
rolling average and highest 90-day rolling average determined by your
continuous monitoring system during the reporting period.
(5) The start date for each instance where the 12-month rolling
average operational downtime of the system exceeded 10 percent and the
value of the 12-month rolling average operational downtime during the
period. If there were no instances during the reporting period where
the 12-month rolling average operational downtime of the system
exceeded 10 percent, report the highest value of the 12-month rolling
average operational downtime during the reporting period.
(6) Any additional information regarding the performance of the
continuous monitoring system as
[[Page 17212]]
specified by the Administrator, as part of the alternative test method
approval described in Sec. 60.5398b(d).
(e) If you comply with the continuous monitoring system
requirements of Sec. 60.5398c(c), you must maintain the records in
paragraphs (e)(1) through (15) of this section.
(1) The monitoring plan required by Sec. 60.5398c(c)(2).
(2) Date of commencement of continuous monitoring with your
continuous monitoring system.
(3) The detection threshold of the continuous monitoring system.
(4) The results of checks for power and function in accordance with
Sec. 60.5398c(c)(1)(ii).
(5) The beginning and end of each period of operational downtime
for the system.
(6) Each rolling 12-month average operational downtime for the
system, calculated in accordance with Sec. 60.5398c(c)(1)(ii)(D).
(7) The 7-day rolling average and 90-day rolling average action
levels for the site determined in accordance with Sec. 60.5398c(c)(4).
(8) The information in paragraphs (e)(8)(i) through (v) of this
section each time you establish site-specific baseline emissions in
accordance with Sec. 60.5398c(c)(5).
(i) Records of inspections of fugitive emissions components,
covers, and closed vent systems required by Sec. 60.5398c(c)(5)(i),
including the date of inspection, location of each emission or defect
identified, date of successful repair of each fugitive emissions
component, cover, or closed vent system.
(ii) Records of inspections of control devices required by Sec.
60.5398c(c)(5)(ii), including the date of the inspection and the
results of the inspection.
(iii) The start date and time and end date and time of any
maintenance activities that occurred during the 30 operating day
period.
(iv) The site-level emission rate for each day during the 30
operating day period.
(v) The calculated site-specific baseline emission rate.
(9) Each methane mass emission rate reading determined by the
system.
(10) Each daily, 7-day, and 90-day average mass emission rate which
was determined in accordance with Sec. 60.5398c(c)(6). If you exceed
the 90-day action level, you must also keep records of the 30-day
average mass emission rate following completion of the initial actions
to reduce the average mass emission rate, in accordance with Sec.
60.5398c(c)(8)(i).
(11) The results of each comparison of the emissions rate
determined in accordance with Sec. 60.5398c(c)(6) to the action level
determined in accordance with Sec. 60.5398c(c)(4).
(12) The date the investigative analysis was initiated, and the
result of the investigative analysis conducted in accordance with Sec.
60.5398c(c)(7), as applicable.
(13) Dates of implementation and completion of action(s) taken to
reduce the mass emission rate below the action level and a description
of the action(s) taken in accordance with Sec. 60.5398c(c)(7), as
applicable.
(14) Each mass emission rate reduction plan developed in accordance
with Sec. 60.5398c(c)(8), as applicable. You must keep records of the
actions taken in accordance with the plan and the date such actions are
taken.
(15) Any additional information regarding the performance of the
continuous monitoring technology as specified by the Administrator, as
part of the alternative test method approval described in Sec.
60.5398b(d).
Sec. 60.5425c What parts of the General Provisions apply to me?
Table 4 to this subpart shows which parts of the General Provisions
in Sec. Sec. 60.1 through 60.19 apply to you.
Model Rule--Definitions
Sec. 60.5430c What definitions apply to this subpart?
As used in this subpart, all terms not defined herein shall have
the meaning given them in the Act or in subpart A of this part; and the
following terms shall have the specific meanings given them.
Access to electrical power means commercial line power is available
onsite, with sufficient capacity to support the required power loading
of onsite equipment, and which provides reliable and consistent power.
Acid gas means a gas stream of hydrogen sulfide (H2S)
and carbon dioxide (CO2) that has been separated from sour
natural gas by a sweetening unit.
Alaskan North Slope means the approximately 69,000 square-mile area
extending from the Brooks Range to the Arctic Ocean.
API Gravity means the weight per unit volume of hydrocarbon liquids
as measured by a system recommended by the American Petroleum Institute
(API) and is expressed in degrees.
Artificial lift equipment means mechanical pumps including, but not
limited to, rod pumps and electric submersible pumps used to flowback
fluids from a well.
Associated gas means the natural gas from wells operated primarily
for oil production that is released from the liquid hydrocarbon during
the initial stage of separation after the wellhead. Associated gas
production begins at the startup of production after the flow back
period ends. Gas from wildcat or delineation wells is not associated
gas.
Average aggregate detection threshold means:
(1) For the purposes of Sec. 60.5398c, the average of all site-
level detection thresholds from a single deployment (e.g., a singular
flight that surveys multiple well sites, centralized production
facility, and/or compressor stations) of a technology; and
(2) For the purposes of Sec. 60.5388c, the average of all site-
level detection thresholds from a single deployment in the same basin
and field.
Bleed rate means the rate in standard cubic feet per hour at which
natural gas is continuously vented (bleeds) from a process controller.
Capital expenditure means, as an alternative to the definition in
Sec. 60.2, an expenditure for a physical or operational change to an
existing facility that:
(1) Exceeds P, the product of the facility's replacement cost, R,
and an adjusted annual asset guideline repair allowance, A, as
reflected by the following equation: P = R x A, where:
(i) The adjusted annual asset guideline repair allowance, A, is the
product of the percent of the replacement cost, Y, and the applicable
basic annual asset guideline repair allowance, B, divided by 100 as
reflected by the following equation: A = Y x (B / 100);
(ii) The percent Y is determined from the following equation: Y =
(CPI of date of construction/most recently available CPI of date of
project), where the ``CPI-U, U.S. city average, all items'' must be
used for each CPI value; and
(iii) The applicable basic annual asset guideline repair allowance,
B, is 4.5.
(2) [Reserved]
Centralized production facility means one or more storage vessels
and all equipment at a single surface site used to gather, for the
purpose of sale or processing to sell, crude oil, condensate, produced
water, or intermediate hydrocarbon liquid from one or more offsite
natural gas or oil production wells. This equipment includes, but is
not limited to, equipment used for storage, separation, treating,
dehydration, artificial lift, combustion, compression, pumping,
metering, monitoring, and flowline. Process vessels and process tanks
are not considered storage vessels or storage tanks. A centralized
production facility is located upstream of the natural gas
[[Page 17213]]
processing plant or the crude oil pipeline breakout station and is a
part of producing operations.
Centrifugal compressor means any machine for raising the pressure
of a natural gas by drawing in low pressure natural gas and discharging
significantly higher-pressure natural gas by means of mechanical
rotating vanes or impellers. Screw, sliding vane, and liquid ring
compressors are not centrifugal compressors for the purposes of this
subpart.
Centrifugal compressor equipped with sour seal oil separator and
capture system means a wet seal centrifugal compressor system which has
an intermediate closed process that degasses most of the gas entrained
in the sour seal oil and sends that gas to either another process or
combustion device (i.e., degassed emissions are recovered). The de-gas
emissions are routed back to a process or combustion device directly
from the intermediate closed degassing process; after the intermediate
closed process the oil is ultimately recycled for recirculation in the
seals to the lube oil tank where any small amount of residual gas is
released through a vent.
Certifying official means one of the following:
(1) For a corporation: A president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business
function, or any other person who performs similar policy or decision-
making functions for the corporation, or a duly authorized
representative of such person if the representative is responsible for
the overall operation of one or more manufacturing, production, or
operating facilities with a designated facility subject to this subpart
and either:
(i) The facilities employ more than 250 persons or have gross
annual sales or expenditures exceeding $25 million (in second quarter
1980 dollars); or
(ii) The Administrator is notified of such delegation of authority
prior to the exercise of that authority. The Administrator reserves the
right to evaluate such delegation;
(2) For a partnership (including but not limited to general
partnerships, limited partnerships, and limited liability partnerships)
or sole proprietorship: A general partner or the proprietor,
respectively. If a general partner is a corporation, the provisions of
paragraph (1) of this definition apply;
(3) For a municipality, State, Federal, or other public agency:
Either a principal executive officer or ranking elected official. For
the purposes of this part, a principal executive officer of a Federal
agency includes the chief executive officer having responsibility for
the overall operations of a principal geographic unit of the agency
(e.g., a Regional Administrator of EPA); or
(4) For designated facilities:
(i) The designated representative in so far as actions, standards,
requirements, or prohibitions under title IV of the CAA or the
regulations promulgated thereunder are concerned; or
(ii) The designated representative for any other purposes under
this part.
Closed vent system means a system that is not open to the
atmosphere and that is composed of hard-piping, ductwork, connections,
and, if necessary, flow-inducing devices that transport gas or vapor
from a piece or pieces of equipment to a control device or back to a
process.
Coil tubing cleanout means the process where an operator runs a
string of coil tubing to the packed proppant within a well and jets the
well to dislodge the proppant and provide sufficient lift energy to
flow it to the surface. Coil tubing cleanout includes mechanical
methods to remove solids and/or debris from a wellbore.
Collection system means any infrastructure that conveys gas or
liquids from the well site to another location for treatment, storage,
processing, recycling, disposal, or other handling.
Completion combustion device means any ignition device, installed
horizontally or vertically, used in exploration and production
operations to combust otherwise vented emissions from completions.
Completion combustion devices include pit flares.
Compressor mode means the operational and pressurized status of a
compressor. For both centrifugal compressors and reciprocating
compressors, ``mode'' refers to either: Operating-mode, standby-
pressurized-mode, or not-operating-depressurized-mode.
Compressor station means any permanent combination of one or more
compressors that move natural gas at increased pressure through
gathering or transmission pipelines, or into or out of storage. This
includes, but is not limited to, gathering and boosting stations and
transmission compressor stations. The combination of one or more
compressors located at a well site, centralized production facility, or
an onshore natural gas processing plant, is not a compressor station
for purposes of Sec. 60.5386c(e) and Sec. 60.5397c.
Condensate means hydrocarbon liquid separated from natural gas that
condenses due to changes in the temperature, pressure, or both, and
remains liquid at standard conditions.
Connector means flanged, screwed, or other joined fittings used to
connect two pipe lines or a pipe line and a piece of process equipment
or that close an opening in a pipe that could be connected to another
pipe. Joined fittings welded completely around the circumference of the
interface are not considered connectors for the purpose of this
regulation.
Continuous bleed means a continuous flow of pneumatic supply
natural gas to a process controller.
Crude oil and natural gas source category means:
(1) Crude oil production, which includes the well and extends to
the point of custody transfer to the crude oil transmission pipeline or
any other forms of transportation; and
(2) Natural gas production, processing, transmission, and storage,
which include the well and extend to, but do not include, the local
distribution company custody transfer station.
Custody meter means the meter where natural gas or hydrocarbon
liquids are measured for sales, transfers, and/or royalty
determination.
Custody meter assembly means an assembly of fugitive emissions
components, including the custody meter, valves, flanges, and
connectors necessary for the proper operation of the custody meter.
Custody transfer means the transfer of crude oil or natural gas
after processing and/or treatment in the producing operations, or from
storage vessels or automatic transfer facilities or other such
equipment, including product loading racks, to pipelines or any other
forms of transportation.
Dehydrator means a device in which an absorbent directly contacts a
natural gas stream and absorbs water in a contact tower or adsorption
column (absorber).
Delineation well means a well drilled in order to determine the
boundary of a field or producing reservoir.
Deviation means any instance in which a designated source subject
to this subpart, or an owner or operator of such a source:
(1) Fails to meet any requirement or obligation established by this
subpart including, but not limited to, any emission limit, operating
limit, or work practice standard;
(2) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any designated source required to
obtain such a permit; or
(3) Fails to meet any emission limit, operating limit, or work
practice
[[Page 17214]]
standard of this subpart during startup, shutdown, or malfunction,
regardless of whether or not such failure is permitted by this subpart.
Distance piece means an open or enclosed casing through which the
piston rod travels, separating the compressor cylinder from the
crankcase.
Double block and bleed system means two block valves connected in
series with a bleed valve or line that can vent the line between the
two block valves.
Duct work means a conveyance system such as those commonly used for
heating and ventilation systems. It is often made of sheet metal and
often has sections connected by screw or crimping. Hard-piping is not
ductwork.
Emergency shutdown device means a device which functions
exclusively to protect personnel and/or prevent physical damage to
equipment by shutting down equipment or gas flow during unsafe
conditions resulting from an unexpected event, such as a pipe break or
fire. For the purposes of this subpart, an emergency shutdown device is
not used for routine control of operating conditions.
Equipment, as used in the standards and requirements of this
subpart relative to the process unit equipment designated facility at
onshore natural gas processing plants, means each pump, pressure relief
device, open-ended valve or line, valve, and flange or other connector
that has the potential to emit methane and any device or system
required by those same standards and requirements of this subpart.
Field gas means feedstock gas entering the natural gas processing
plant.
Field gas gathering means the system used transport field gas from
a field to the main pipeline in the area.
First attempt at repair means an action taken for the purpose of
stopping or reducing fugitive emissions to the atmosphere. First
attempts at repair include, but are not limited to, the following
practices where practicable and appropriate: Tightening bonnet bolts;
replacing bonnet bolts; tightening packing gland nuts; or injecting
lubricant into lubricated packing.
Flare means a thermal oxidation system using an open (without
enclosure) flame. Completion combustion devices as defined in this
section are not considered flares.
Flow line means a pipeline used to transport oil and/or gas to a
processing facility or a mainline pipeline.
Flowback means the process of allowing fluids and entrained solids
to flow from a well following a treatment, either in preparation for a
subsequent phase of treatment or in preparation for cleanup and
returning the well to production. The term flowback also means the
fluids and entrained solids that emerge from a well during the flowback
process. The flowback period begins when material introduced into the
well during the treatment returns to the surface following hydraulic
fracturing or refracturing. The flowback period ends when either the
well is shut in and permanently disconnected from the flowback
equipment or at the startup of production. The flowback period includes
the initial flowback stage and the separation flowback stage.
Screenouts, coil tubing cleanouts, and plug drill-outs are not
considered part of the flowback process.
Fuel gas means gases that are combusted to derive useful work or
heat.
Fuel gas system means the offsite and onsite piping and flow and
pressure control system that gathers gaseous stream(s) generated by
onsite operations, may blend them with other sources of gas, and
transports the gaseous stream for use as fuel gas in combustion devices
or in-process combustion equipment, such as furnaces and gas turbines,
either singly or in combination.
Fugitive emissions means, for the purposes of Sec. 60.5397c, any
indication of emissions observed from a fugitive emissions component
using AVO, an indication of visible emissions observed from an OGI
instrument, or an instrument reading of 500 ppmv or greater using
Method 21 of appendix A-7 to this part.
Fugitive emissions component means any component that has the
potential to emit fugitive emissions of methane at a well site,
centralized production facility, or compressor station, such as valves
(including separator dump valves), connectors, pressure relief devices,
open-ended lines, flanges, covers and closed vent systems not subject
to Sec. 60.5411c, thief hatches or other openings on a storage vessel
not subject to Sec. 60.5396c, compressors, instruments, meters, and
yard piping.
Gas to oil ratio (GOR) means the ratio of the volume of gas at
standard temperature and pressure that is produced from a volume of oil
when depressurized to standard temperature and pressure.
Hard-piping means pipe or tubing that is manufactured and properly
installed using good engineering judgment and standards such as ASME
B31.3, Process Piping (available from the American Society of
Mechanical Engineers, P.O. Box 2300, Fairfield, NJ 07007-2300).
Hydraulic fracturing means the process of directing pressurized
fluids containing any combination of water, proppant, and any added
chemicals to penetrate tight formations, such as shale or coal
formations, that subsequently require high rate, extended flowback to
expel fracture fluids and solids during completions.
Hydraulic refracturing means conducting a subsequent hydraulic
fracturing operation at a well that has previously undergone a
hydraulic fracturing operation.
In gas/vapor service means that the piece of equipment contains
process fluid that is in the gaseous state at operating conditions.
In heavy liquid service means that the piece of equipment is not in
gas/vapor service or in light liquid service.
In light liquid service means that the piece of equipment contains
a liquid that meets the conditions specified in Sec. 60.5402c(d)(2) or
Sec. 60.5406c.
In vacuum service means that equipment is operating at an internal
pressure which is at least 5 kilopascals (kPa) (0.7 psia) below ambient
pressure.
In wet gas service means that a compressor or piece of equipment
contains or contacts the field gas before the extraction step at a gas
processing plant process unit.
Initial calibration value, as used in the standards and
requirements of this subpart relative to the process unit equipment
designated facility at onshore natural gas processing plants, means the
concentration measured during the initial calibration at the beginning
of each day required in Sec. 60.5403c, or the most recent calibration
if the instrument is recalibrated during the day (i.e., the calibration
is adjusted) after a calibration drift assessment.
Initial flowback stage means the period during a well completion
operation which begins at the onset of flowback and ends at the
separation flowback stage.
Intermediate hydrocarbon liquid means any naturally occurring,
unrefined petroleum liquid.
Intermittent vent natural gas-driven process controller means a
process controller that is not designed to have a continuous bleed rate
but is instead designed to only release natural gas to the atmosphere
as part of the actuation cycle.
Liquefied natural gas unit means a unit used to cool natural gas to
the point at which it is condensed into a liquid which is colorless,
odorless, non-corrosive and non-toxic.
Liquid collection system means tankage and/or lines at a well site
to contain liquids from one or more wells or to convey liquids to
another site.
[[Page 17215]]
Liquids dripping means any visible leakage from the seal, including
spraying, misting, clouding, and ice formation.
Liquids unloading means the unloading of liquids that have
accumulated over time in gas wells, which are impeding or halting
production. Routine well maintenance activities, including workovers,
screenouts, coil tubing cleanouts, or any other activity that requires
a rig or other machinery are not considered liquids unloading.
Local distribution company (LDC) custody transfer station means a
metering station where the LDC receives a natural gas supply from an
upstream supplier, which may be an interstate transmission pipeline or
a local natural gas producer, for delivery to customers through the
LDC's intrastate transmission or distribution lines.
Low-e valve means a valve (including its specific packing assembly)
for which the manufacturer has issued a written warranty or performance
guarantee that it will not emit fugitives at greater than 100 ppm in
the first five years. A valve may qualify as a low-e valve if it is as
an extension of another valve that has qualified as a low-e valve.
Low-e packing means a valve packing product for which the
manufacturer has issued a written warranty or performance guarantee
that it will not emit fugitives at greater than 100 ppm in the first
five years. Low-e injectable packing is a type of low-e packing product
for which the manufacturer has also issued a written warranty or
performance guarantee and that can be injected into a valve during a
``drill-and-tap'' repair of the valve.
Major production and processing equipment means reciprocating or
centrifugal compressors, glycol dehydrators, heater/treaters,
separators, control devices, natural gas-driven process controllers,
natural gas-driven pumps, and storage vessels or tank batteries
collecting crude oil, condensate, intermediate hydrocarbon liquids, or
produced water, for the purpose of determining whether a well site is a
wellhead only well site.
Maximum average daily throughput means the following:
(1) The earliest calculation of daily average throughput,
determined as described in paragraph (2) or (3) of this definition, to
a tank battery over the days that production is routed to that tank
battery during the 30-day PTE evaluation period employing generally
accepted methods specified in Sec. 60.5386c(e)(2).
(2) If throughput to the tank battery is measured on a daily basis
(e.g., via level gauge automation or daily manual gauging), the maximum
average daily throughput is the average of all daily throughputs for
days on which throughput was routed to the tank battery during the 30-
day evaluation period; or
(3) If throughput to the tank battery is not measured on a daily
basis (e.g., via manual gauging at the start and end of loadouts), the
maximum average daily throughput is the highest, of the average daily
throughputs, determined for any production period to that tank battery
during the 30-day evaluation period, as determined by averaging total
throughput to that tank battery over each production period. A
production period begins when production begins to be routed to a tank
battery and ends either when throughput is routed away from that tank
battery or when a loadout occurs from that tank battery, whichever
happens first. Regardless of the determination methodology, operators
must not include days during which throughput is not routed to the tank
battery when calculating maximum average daily throughput for that tank
battery.
Multi-wellhead only well site means a well site that contains two
or more wellheads and no major production and processing equipment.
Natural gas-driven diaphragm pump means a positive displacement
pump powered by pressurized natural gas that uses the reciprocating
action of flexible diaphragms in conjunction with check valves to pump
a fluid. A pump in which a fluid is displaced by a piston driven by a
diaphragm is not considered a diaphragm pump for purposes of this
subpart. A lean glycol circulation pump that relies on energy exchange
with the rich glycol from the contactor is not considered a diaphragm
pump.
Natural gas-driven piston pump means a positive displacement pump
powered by pressurized natural gas that moves and pressurizes fluid by
using one or more reciprocating pistons. A pump in which a fluid is
displaced by a piston driven by a diaphragm is considered a piston pump
for purposes of this subpart. A lean glycol circulation pump that
relies on energy exchange with the rich glycol from the contactor is
not considered a piston pump.
Natural gas-driven process controller means a process controller
powered by pressurized natural gas.
Natural gas liquids means the hydrocarbons, such as ethane,
propane, butane, and pentane that are extracted from field gas.
Natural gas processing plant (gas plant) means any processing site
engaged in the extraction of natural gas liquids from field gas,
fractionation of mixed natural gas liquids to natural gas products, or
both. A Joule-Thompson valve, a dew point depression valve, or an
isolated or standalone Joule-Thompson skid is not a natural gas
processing plant.
Natural gas transmission means the pipelines used for the long-
distance transport of natural gas (excluding processing). Specific
equipment used in natural gas transmission includes the land, mains,
valves, meters, boosters, regulators, storage vessels, dehydrators,
compressors, and their driving units and appurtenances, and equipment
used for transporting gas from a production plant, delivery point of
purchased gas, gathering system, storage area, or other wholesale
source of gas to one or more distribution area(s).
No detectable emissions means, for the purposes of Sec. Sec.
60.5401c and 60.5406c, that the equipment is operating with an
instrument reading of less than 500 ppmv above background, as
determined by Method 21 of appendix A-7 to this part.
No identifiable emissions means, for the purposes of covers, closed
vent systems, and self-contained natural gas-driven process controllers
and as determined according to the provisions of Sec. 60.5416c, that
no emissions are detected by AVO means when inspections are conducted
by AVO; no emissions are imaged with an OGI camera when inspections are
conducted with OGI; and equipment is operating with an instrument
reading of less than 500 ppmv above background, as determined by Method
21 of appendix A-7 to this part when inspections are conducted with
Method 21.
Nonfractionating plant means any gas plant that does not
fractionate mixed natural gas liquids into natural gas products.
Non-natural gas-driven process controller means an instrument that
is actuated using other sources of power than pressurized natural gas;
examples include solar, electric, and instrument air.
Onshore means all facilities except those that are located in the
territorial seas or on the outer continental shelf.
Open-ended valve or line or open-ended vent line means any valves,
except safety relief valves, having one side of the valve seat in
contact with process fluid and one side open to the atmosphere, either
directly or through open piping.
Plug drill-out means the removal of a plug (or plugs) that was used
to isolate different sections of the well.
Process controller means an automated instrument used for
[[Page 17216]]
maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature.
Pressure release means the emission of materials resulting from
system pressure being greater than set pressure of the pressure relief
device.
Pressure vessel means a storage vessel that is used to store
liquids or gases and is designed not to vent to the atmosphere as a
result of compression of the vapor headspace in the pressure vessel
during filling of the pressure vessel to its design capacity.
Pressurized mode means when the compressor contains natural gas
that is maintained at a pressure higher than the atmospheric pressure.
Process improvement means routine changes made for safety and
occupational health requirements, for energy savings, for better
utility, for ease of maintenance and operation, for correction of
design deficiencies, for bottleneck removal, for changing product
requirements, or for environmental control.
Process unit means components assembled for the extraction of
natural gas liquids from field gas, the fractionation of the liquids
into natural gas products, or other operations associated with the
processing of natural gas products. A process unit can operate
independently if supplied with sufficient feed or raw materials and
sufficient storage facilities for the products.
Process unit shutdown means a work practice or operational
procedure that stops production from a process unit or part of a
process unit during which it is technically feasible to clear process
material from a process unit or part of a process unit consistent with
safety constraints and during which repairs can be accomplished. The
following are not considered process unit shutdowns:
(1) An unscheduled work practice or operational procedure that
stops production from a process unit or part of a process unit for less
than 24 hours.
(2) An unscheduled work practice or operational procedure that
would stop production from a process unit or part of a process unit for
a shorter period of time than would be required to clear the process
unit or part of the process unit of materials and start up the unit,
and would result in greater emissions than delay of repair of leaking
components until the next scheduled process unit shutdown.
(3) The use of spare equipment and technically feasible bypassing
of equipment without stopping production.
Produced water means water that is extracted from the earth from an
oil or natural gas production well, or that is separated from crude
oil, condensate, or natural gas after extraction.
Qualified Professional Engineer means an individual who is licensed
by a state as a Professional Engineer to practice one or more
disciplines of engineering and who is qualified by education, technical
knowledge and experience to make the specific technical certifications
required under this subpart. Professional engineers making these
certifications must be currently licensed in at least one state in
which the certifying official is located.
Quarter means a 3-month period. For purposes of standards for
process unit equipment designated facilities at onshore natural gas
processing plants, the first quarter concludes on the last day of the
last full month during the 180 days following initial startup.
Reciprocating compressor means a piece of equipment that increases
the pressure of a process gas by positive displacement, employing
linear movement of the driveshaft.
Reciprocating compressor rod packing means a series of flexible
rings in machined metal cups that fit around the reciprocating
compressor piston rod to create a seal limiting the amount of
compressed natural gas that escapes to the atmosphere, or other
mechanism that provides the same function.
Recovered gas means gas recovered through the separation process
during flowback.
Recovered liquids means any crude oil, condensate or produced water
recovered through the separation process during flowback.
Reduced emissions completion means a well completion following
fracturing or refracturing where gas flowback that is otherwise vented
is captured, cleaned, and routed to the gas flow line or collection
system, re-injected into the well or another well, used as an onsite
fuel source, or used for other useful purpose that a purchased fuel or
raw material would serve, with no direct release to the atmosphere.
Reduced sulfur compounds means H2S, carbonyl sulfide
(COS), and carbon disulfide (CS2).
Removed from service means that a storage vessel designated
facility has been physically isolated and disconnected from the process
for a purpose other than maintenance in accordance with Sec.
60.5396c(c)(1).
Repaired means the following:
(1) For the purposes of fugitive emissions components designated
facilities, that fugitive emissions components are adjusted, replaced,
or otherwise altered, in order to eliminate fugitive emissions as
defined in Sec. 60.5397c and resurveyed as specified in Sec.
60.5397c(h)(4) and it is verified that emissions from the fugitive
emissions components are below the applicable fugitive emissions
definition.
(2) For the purposes of process unit equipment designated
facilities, that equipment is adjusted, or otherwise altered, in order
to eliminate a leak as defined in Sec. Sec. 60.5400c and 60.5401c and
is re-monitored as specified in Sec. 60.5400c(b) and (b)(1) or Sec.
60.5403c, respectively, to verify that emissions from the equipment are
below the applicable leak definition. Pumps in light liquid service
subject to Sec. 60.5400c(c)(2) or Sec. 60.5401c(b)(1)(ii) are not
subject to re-monitoring.
Replacement cost means the capital needed to purchase all the
depreciable components in a facility.
Returned to service means that a storage vessel designated facility
that was removed from service has been:
(1) Reconnected to the original source of liquids or has been used
to replace any storage vessel designated facility; or
(2) Installed in any location covered by this subpart and
introduced with crude oil, condensate, intermediate hydrocarbon liquids
or produced water.
Routed to a process or route to a process means the emissions are
conveyed via a closed vent system to any enclosed portion of a process
that is operational where the emissions are predominantly recycled and/
or consumed in the same manner as a material that fulfills the same
function in the process and/or transformed by chemical reaction into
materials that are not regulated materials and/or incorporated into a
product; and/or recovered.
Salable quality gas means natural gas that meets the flow line or
collection system operator specifications, regardless of whether such
gas is sold.
Screenout means an attempt to clear proppant from the wellbore to
dislodge the proppant out of the well.
Self-contained process controller means a natural gas-driven
process controller that releases gas into the downstream piping and not
to the atmosphere, resulting in zero methane emissions.
Self-contained wet seal centrifugal compressor means:
(1) A wet seal centrifugal compressor system that is a closed
process that ports the degassing emissions into the natural gas line at
the compressor suction (i.e., degassed emissions are recovered) or
which has an intermediate closed process that degasses most of the gas
entrained in the seal oil and sends that gas to another process. The
de-gas
[[Page 17217]]
emissions are routed back to suction or process directly from the
closed or intermediate closed degassing process; after the closed or
intermediate closed degassing process the oil is ultimately recycled
for recirculation in the seals to the lube oil tank where any small
amount of residual gas is released through a vent.
(2) A wet seal centrifugal compressor equipped with mechanical wet
seals, where (1) a differential pressure is maintained on the system
and there is no off gassing of the lube oil, and (2) the mechanical
seal is integrated into the compressor housing.
Sensor means a device that measures a physical quantity or the
change in a physical quantity such as temperature, pressure, flow rate,
pH, or liquid level.
Separation flowback stage means the period during a well completion
operation when it is technically feasible for a separator to function.
The separation flowback stage ends either at the startup of production,
or when the well is shut in and permanently disconnected from the
flowback equipment.
Separator dump valve means, for purposes of the fugitive emission
standards in Sec. Sec. 60.5397c and 60.5398c, a liquid-control valve
in a separator that controls the liquid level within the separator
vessel.
Single wellhead only well site means a wellhead only well site that
contains only one wellhead and no major production and processing
equipment.
Small well site means, for purposes of the fugitive emissions
standards in Sec. Sec. 60.5397c and 60.5398c, a well site that
contains a single wellhead, no more than one piece of certain major
production and processing equipment, and associated meters and yard
piping. Small well sites cannot include any controlled storage vessels
(or controlled tank batteries), control devices, or natural gas-driven
process controllers, or natural gas-driven pumps.
Startup of production means the beginning of initial flow following
the end of flowback when there is continuous recovery of salable
quality gas and separation and recovery of any crude oil, condensate,
or produced water, except as otherwise provided in this definition. For
the purposes of the fugitive monitoring requirements of Sec. 60.5397c,
startup of production means the beginning of the continuous recovery of
salable quality gas and separation and recovery of any crude oil,
condensate, or produced water.
Storage vessel means a tank or other vessel that contains an
accumulation of crude oil, condensate, intermediate hydrocarbon
liquids, or produced water, and that is constructed primarily of
nonearthen materials (such as wood, concrete, steel, fiberglass, or
plastic) which provide structural support. A well completion vessel
that receives recovered liquids from a well after startup of production
following flowback for a period which exceeds 60 days is considered a
storage vessel under this subpart. A tank or other vessel shall not be
considered a storage vessel if it has been removed from service in
accordance with the requirements of Sec. 60.5396c(c)(1) until such
time as such tank or other vessel has been returned to service. For the
purposes of this subpart, the following are not considered storage
vessels:
(1) Vessels that are skid-mounted or permanently attached to
something that is mobile (such as trucks, railcars, barges or ships),
and are intended to be located at a site for less than 180 consecutive
days. If you do not keep or are not able to produce records, as
required by Sec. 60.5420c(c)(4)(iv), showing that the vessel has been
located at a site for less than 180 consecutive days, the vessel
described herein is considered to be a storage vessel from the date the
original vessel was first located at the site. This exclusion does not
apply to a well completion vessel as described above.
(2) Process vessels such as surge control vessels, bottoms
receivers or knockout vessels.
(3) Pressure vessels designed to operate in excess of 204.9
kilopascals and without emissions to the atmosphere.
Sulfur production rate means the rate of liquid sulfur accumulation
from the sulfur recovery unit.
Sulfur recovery unit means a process device that recovers element
sulfur from acid gas.
Surface site means any combination of one or more graded pad sites,
gravel pad sites, foundations, platforms, or the immediate physical
location upon which equipment is physically affixed.
Sweetening unit means a process device that removes hydrogen
sulfide and/or carbon dioxide from the sour natural gas stream.
Tank battery means a group of all storage vessels that are
manifolded together for liquid transfer. A tank battery may consist of
a single storage vessel if only one storage vessel is present.
Total Reduced Sulfur (TRS) means the sum of the sulfur compounds
hydrogen sulfide, methyl mercaptan, dimethyl sulfide, and dimethyl
disulfide as measured by Method 16 of appendix A-6 to this part.
Total SO2 equivalents means the sum of volumetric or mass
concentrations of the sulfur compounds obtained by adding the quantity
existing as SO2 to the quantity of SO2 that would
be obtained if all reduced sulfur compounds were converted to
SO2 (ppmv or kg/dscm (lb/dscf)).
UIC Class I oilfield disposal well means a well with a UIC Class I
permit that meets the definition in 40 CFR 144.6(a)(2) and receives
eligible fluids from oil and natural gas exploration and production
operations.
UIC Class II oilfield disposal well means a well with a UIC Class
II permit where wastewater resulting from oil and natural gas
production operations is injected into underground porous rock
formations not productive of oil or gas, and sealed above and below by
unbroken, impermeable strata.
Underground storage vessel means a storage vessel stored below
ground.
Well means a hole drilled for the purpose of producing oil or
natural gas, or a well into which fluids are injected.
Well completion means the process that allows for the flowback of
petroleum or natural gas from newly drilled wells to expel drilling and
reservoir fluids and tests the reservoir flow characteristics, which
may vent produced hydrocarbons to the atmosphere via an open pit or
tank.
Well completion operation means any well completion with hydraulic
fracturing or refracturing occurring at a well completion designated
facility.
Well completion vessel means a vessel that contains flowback during
a well completion operation following hydraulic fracturing or
refracturing. A well completion vessel may be a lined earthen pit, a
tank or other vessel that is skid-mounted or portable. A well
completion vessel that receives recovered liquids from a well after
startup of production following flowback for a period which exceeds 60
days is considered a storage vessel under this subpart.
Well site means one or more surface sites that are constructed for
the drilling and subsequent operation of any oil well, natural gas
well, or injection well. For the purposes of the fugitive emissions
standards at Sec. 60.5397c, a well site does not include:
(1) UIC Class II oilfield disposal wells and disposal facilities;
(2) UIC Class I oilfield disposal wells; and
(3) The flange immediately upstream of the custody meter assembly
and equipment, including fugitive emissions components, located
downstream of this flange.
[[Page 17218]]
Wellhead means the piping, casing, tubing and connected valves
protruding above the earth's surface for an oil and/or natural gas
well. The wellhead ends where the flow line connects to a wellhead
valve. The wellhead does not include other equipment at the well site
except for any conveyance through which gas is vented to the
atmosphere.
Wellhead only well site means, for the purposes of the fugitive
emissions standards at Sec. 60.5397c and the standards in Sec.
60.5398c, a well site that contains one or more wellheads and no major
production and processing equipment.
Wildcat well means a well outside known fields or the first well
drilled in an oil or gas field where no other oil and gas production
exists.
Yard piping means hard-piping at a well site, centralized
production facility, or compressor station that is not part of a closed
vent system.
Sec. Sec. 60.5431c-60.5439c [Reserved]
Table 1 to Subpart OOOOc of Part 60--Designated Facility Presumptive
Standards and Regulated Entity Compliance Dates
------------------------------------------------------------------------
Model rule presumptive Regulated entity
Designated facility standards section compliance dates
------------------------------------------------------------------------
Wells......................... a. Gas wells liquids 36 months after
unloading events-- the state plan
Sec. 60.5390c. submittal
b. Associated gas deadline
wells--Sec. specified in
60.5391c.. Sec.
60.5362c(c).
Centrifugal Compressors....... Sec. 60.5392c.......
Reciprocating Compressors..... Sec. 60.5393c.......
Process Controller............ Sec. 60.5394c.......
Pump.......................... Sec. 60.5395c.......
Storage Vessels............... Sec. 60.5396c.......
Fugitive Emissions Components. a. Primary standards--
Sec. 60.5397c.
b. Alternative
standards for
fugitive emissions
components and covers
and closed vent
systems--Sec.
60.5398c.
Super Emitter Emissions Events Sec. 60.5388c.......
Process Unit Equipment........ a. Onshore natural gas
processing plants--
Sec. 60.5400c.
b. Process unit
equipment alternative
standards--Sec.
60.5401c.
c. Process unit
equipment requirement
exceptions--Sec.
60.5401c.
------------------------------------------------------------------------
Table 2 to Subpart OOOOc of Part 60--Alternative Technology Periodic
Screening Frequency at Well Sites, Centralized Production Facilities,
and Compressor Stations Subject to AVO Inspections With Quarterly OGI or
EPA Method 21 Monitoring
------------------------------------------------------------------------
Minimum detection threshold
Minimum screening frequency of screening technology *
(kg/hr)
------------------------------------------------------------------------
Quarterly.................................. <=1
Bimonthly.................................. <=2
Bimonthly + Annual OGI..................... <=10
Monthly.................................... <=5
Monthly + Annual OGI....................... <=15
------------------------------------------------------------------------
* Based on a probability of detection of 90%.
Table 3 to Subpart OOOOc of Part 60--Alternative Technology Periodic
Screening Frequency at Well Sites and Centralized Production Facilities
Subject to AVO Inspections and/or Semiannual OGI or EPA Method 21
Monitoring
------------------------------------------------------------------------
Minimum detection threshold
Minimum screening frequency of screening technology *
(kg/hr)
------------------------------------------------------------------------
Semiannual................................. <=1
Triannual.................................. <=2
Triannual + Annual OGI..................... <=10
Quarterly.................................. <=5
Quarterly + Annual OGI..................... <=15
Bimonthly.................................. <=15
------------------------------------------------------------------------
* Based on a probability of detection of 90%.
Table 4 to Subpart OOOOc of Part 60--Applicability of General Provisions to Subpart OOOOc
----------------------------------------------------------------------------------------------------------------
General provisions citation Subject of citation Applies to subpart? Explanation
----------------------------------------------------------------------------------------------------------------
Sec. 60.1................. General applicability of Yes.....................
the General Provisions.
Sec. 60.2................. Definitions.............. Yes..................... Additional terms defined in
Sec. 60.5430c.
Sec. 60.3................. Units and abbreviations.. Yes.....................
[[Page 17219]]
Sec. 60.4................. Address.................. Yes.....................
Sec. 60.5................. Determination of Yes.....................
construction or
modification.
Sec. 60.6................. Review of plans.......... Yes.....................
Sec. 60.7................. Notification and record Yes..................... Except that Sec. 60.7 only
keeping. applies as specified in Sec.
Sec. 60.5417c(c) and
60.5420c(a).
Sec. 60.8................. Performance tests........ Yes..................... Except that the format and
submittal of performance
test reports is described in
Sec. 60.5420c(b) and (d).
Performance testing is
required for control devices
used on storage vessels,
centrifugal compressors, and
pumps, except that
performance testing is not
required for a control
device used solely on
pump(s).
Sec. 60.9................. Availability of Yes.....................
information.
Sec. 60.10................ State authority.......... Yes.....................
Sec. 60.11................ Compliance with standards No...................... Requirements are specified in
and maintenance subpart OOOOc.
requirements.
Sec. 60.12................ Circumvention............ Yes.....................
Sec. 60.13................ Monitoring requirements.. Yes..................... Continuous monitors are
required for storage
vessels.
Sec. 60.14................ Modification............. Yes..................... To the extent any provision
in Sec. 60.14 conflicts
with specific provisions in
subpart OOOOc, it is
superseded by subpart OOOOc
provisions.
Sec. 60.15................ Reconstruction........... Yes..................... Except that Sec. 60.15(d)
does not apply to wells
(i.e., well completions,
well liquids unloading,
associated gas wells),
process controllers, pumps,
centrifugal compressors,
reciprocating compressors,
storage vessels, or fugitive
emissions components
designated facilities.
Sec. 60.16................ Priority list............ Yes.....................
Sec. 60.17................ Incorporations by Yes.....................
reference.
Sec. 60.18................ General control device Yes.....................
and work practice
requirements.
Sec. 60.19................ General notification and Yes.....................
reporting requirement.
----------------------------------------------------------------------------------------------------------------
0
34. Add appendix J and appendix K to part 60 to read as follows:
Appendix J to Part 60 [Reserved]
Appendix K to Part 60--Determination of Volatile Organic Compound and
Greenhouse Gas Leaks Using Optical Gas Imaging
1.0 Scope and Application
1.1 Analytes.
------------------------------------------------------------------------
Analytes CAS No.
------------------------------------------------------------------------
Volatile Organic Compounds (VOCs)......... No CAS number assigned.
Methane................................... 74-82-8.
Ethane.................................... 74-84-0.
------------------------------------------------------------------------
1.1.1 This protocol is applicable to the detection of VOCs,
including hazardous air pollutants, and hydrocarbons, such as
methane and ethane.
1.2 Scope. This protocol covers surveys of process equipment
using Optical Gas Imaging (OGI) cameras in sectors where the
majority of constituents (>75 percent by volume) in the emissions
streams have a response factor of at least 0.25 when compared to the
response factor of propane and can be imaged by the equipment
specified in Section 6.0. The specific component focus for the
surveys is determined by the referencing subpart, and can include,
but is not limited to, valves, flanges, connectors, pumps,
compressors, open-ended lines, pressure relief devices, and seal
systems.
1.3 Applicability. This protocol is applicable to facilities
when specified in a referencing subpart. This protocol is intended
to help determine the presence and location of leaks and is not
currently applicable for use in direct emission rate measurements
from sources.
2.0 Summary
2.1 A field portable infrared (IR) camera capable of imaging the
target gas species is employed to survey process equipment and
locate fugitive or leaking gas emissions. By restricting the amount
of incoming thermal radiation to a small bandwidth corresponding to
a region of interaction for the gas species of interest, the camera
provides an image of an invisible gas to the camera operator. The
camera type and manufacturer are not specified in this protocol, but
the camera used must meet the specifications and performance
criteria presented in Section 6. The keys to becoming proficient and
maintaining leak detection proficiency using OGI cameras are proper
camera operator training with sufficient field experience and
conducting OGI surveys frequently throughout the year.
3.0 Definitions
Ambient air temperature means the air temperature in the general
location of the component being surveyed.
Camera configuration means different ways of setting up an OGI
camera that affect its detection capability. Examples of camera
configurations that can be changed include the operating mode (e.g.,
standard versus high sensitivity or enhanced), the lens, the
portability (e.g., handheld versus tripod), and the viewer (e.g.,
OGI camera screen versus an external device like a tablet).
Delta temperature (delta-T or [Delta]T) means the difference in
temperature between the emitted process gas temperature and the
surrounding background temperature. It is an acceptable practice in
the field to assume that the emitted process gas temperature is
equal to the ambient air temperature.
Dwell time means the minimum amount of time required to survey a
scene in order to provide adequate probability of leak detection.
The dwell time is the active time the operator is looking for
potential leaks and does not begin until the scene is in focus and
steady.
Fugitive emission or leak means any emissions observed using OGI
from components regulated by the referencing subpart.
Imaging is the process of producing a visual representation of
emissions that may otherwise be invisible to the naked eye.
Monitoring survey means imaging equipment with an OGI camera at
one site on one day. Changing the site being surveyed or changing
the day of imaging constitutes a new monitoring survey.
OGI camera operator is someone who has completed the training
required in Section 10 and passed the final survey test in Section
10.2.2.4.
Operating envelope means the range of conditions (i.e., wind
speed, delta-T, viewing distance) within which a survey must be
conducted to achieve the quality objective.
Optical gas imaging camera means any field portable
instrumentation that makes
[[Page 17220]]
visible emissions that may otherwise be invisible to the naked eye.
Persistent leak is any leak that is not intermittent in nature.
Referencing subpart means a subpart in this part or in 40 CFR
part 61, 62, 63, or 65 that requires the monitoring of regulated
equipment for fugitive emissions or leaks, for which this protocol
is referenced.
Response factor means the OGI camera's response to a compound of
interest relative to a reference compound at a concentration path-
length of 10,000 parts per million-meter. Response factors are
specific to the OGI camera model and can be obtained from peer
reviewed articles or may be developed according to procedures
specified in Annex 1 of this appendix K.
Senior OGI camera operator is a camera operator who has
conducted OGI surveys for a minimum of 1400 survey hours over the
entirety of his/her career, including at least 40 survey hours in
the past 12 months, and has completed or developed the classroom
camera operator training as defined in Section 10.2.1. Previous 12
months means the 365-calendar days prior to the day of the activity
that requires a senior OGI camera operator. The survey hours spent
by the senior OGI camera operator performing comparative monitoring,
either as part of initial training, retraining, or auditing other
OGI camera operators, can be included when determining the senior
OGI camera operator's experience both over his/her career and the
past 12 months.
Simple scene is defined as a scene that contains 10 or fewer
components in the field of view.
Survey hour is 60 minutes of observation conducted with an OGI
camera. Survey hours do not include periods of time when the OGI
camera operator is on a rest break. The 60 minutes do not need to be
consecutive but are cumulative.
4.0 Interferences
4.1 Interferences from atmospheric conditions can impact the
operator's ability to detect gas leaks. It is recommended that
conditions involving steam, fog, mist, rain, solar glint, high
particulate matter concentrations, and extremely hot backgrounds are
avoided for a survey of acceptable quality.
5.0 Safety
5.1 Site Hazards. Prior to applying this protocol in the field,
the potential hazards at the survey site should be considered;
advance coordination with the site is critical to understand the
conditions and applicable safety policies. Users should be aware of
safety concerns with viewing equipment through a camera while
walking around an industrial setting. Users should also be aware of
hazards related to eye strain, eye fatigue, and mental fatigue that
may occur from prolonged periods of viewing equipment with an OGI
camera. This protocol does not address all of the safety concerns
associated with its use. It is the responsibility of the user of
this protocol to establish appropriate health and safety practices
and determine the applicability of regulatory limitations prior to
implementing this protocol.
5.2 Hazardous Pollutants. Several of the compounds encountered
over the course of implementing this protocol may be irritating or
corrosive to tissues (e.g., heptane) or may be toxic (e.g., benzene,
methyl alcohol, hydrogen sulfide). Nearly all are fire hazards.
Chemical compounds in gaseous emissions should be determined from
process knowledge of the source. Appropriate precautions can be
found in reference documents, such as reference 13.1.
6.0 Equipment and Supplies
6.1 An OGI camera model meeting the following specifications is
required. This testing can be performed by the owner or operator,
the camera manufacturer, or a third party. As required by Section
8.1, this testing must be performed initially, prior to using the
OGI camera to conduct surveys. The determination in Section 6.1.1
must also be made any time the OGI camera will be used to survey
components on equipment that was not previously included in
monitoring surveys or whenever there are process changes that are
expected to cause the gaseous emissions composition to change. The
determination in Section 6.1.2 is only required initially and is
required for each camera operating mode (e.g., standard versus high
sensitivity or enhanced).
6.1.1 The spectral range of infrared radiation measured by the
OGI camera must overlap with a major absorption peak for the
chemical target of interest, meaning the OGI camera must be
sensitive with a response factor of at least 0.25 when compared to
the response factor of propane for the majority of constituents (>75
percent by volume) of the expected gaseous emissions composition.
6.1.2 The OGI camera must be capable of detecting (or producing
a detectable image of) methane emissions of 19 grams per hour (g/hr)
and either n-butane emissions of 29 g/hr or propane emissions of 22
g/hr at a viewing distance of 2.0 meters and a delta-T of 5.0 [deg]C
in an environment of calm wind conditions around 1 meter per second
(m/s) or less, unless the referencing subpart provides detection
rates for a different compound(s) for that subpart.
6.2 The following items are needed for the initial specification
confirmation of each OGI camera model, as required by Sections
6.1.2, and development of operating envelopes, as required by
Section 8:
6.2.1 Methane test gas, chemically pure grade (99.5 percent) or
higher.
6.2.2 n-Butane test gas or propane test gas, chemically pure
grade (99 percent) or higher.
6.2.3 Release orifice, \1/4\ inch (64 millimeter) inner
diameter.
6.2.4 Mass flow controller or rotameter, capable of controlling
the gas emission rate within an accuracy of 5 percent and traceable
to the International System of Units (SI) through an unbroken chain
of comparisons, i.e., calibrations.
6.2.5 An industrial fan, capable of adjusting the sustained
nominal wind speeds at regular intervals, with the ability to
maintain a spatially uniform set speed within 20 percent of the
target wind speed over the area of detection.
6.2.6 A meteorological station capable of providing
representative data on ambient temperature, ambient pressure,
relative humidity, and wind speed and direction at least once every
hour. Follow the calibration and standardization requirements for
meteorological measurements in EPA-454/B-08-002 (incorporated by
reference, see Sec. 60.17). The equipment must meet the following
minimum specifications:
6.2.6.1 Ambient temperature readings accurate to at least 0.50
[deg]C, with a resolution of 0.10 [deg]C or less, and a minimum
range of -20 to 70 [deg]C.
6.2.6.2 Ambient pressure readings accurate to at least 5.0
millibar (mbar), with a resolution of 1.0 mbar or less, and a
minimum range of 700 to 1100 mbar.
6.2.6.3 Wind speed readings accurate to at least 1.0 m/s, with a
resolution of 0.10 m/s or less, and a minimum range of 0.10 to 20 m/
s.
6.2.6.4 Wind direction readings accurate to at least 5 degrees,
with a resolution of 1 degree or less.
6.2.6.5 Relative humidity readings accurate to at least 5.0
percent, with a resolution of 0.50 percent or less, and a minimum
range of 10 to 90 percent noncondensing.
6.2.7 A temperature-controlled background large enough for
viewing the emissions plume and capable of maintaining a uniform
temperature. Uniform is defined as all points on the background
deviating no more than 1.0 [deg]C from the average temperature of
the background.
6.2.8 T-type probe thermocouple and readout, accurate to at 1.0
[deg]C and traceable to the SI through an unbroken chain of
comparisons, i.e., calibrations, for measuring the test gas at or
near the point of release.
6.2.9 T-type surface skin thermocouple and readout, accurate to
at 1.0 [deg]C and traceable to the SI through an unbroken chain of
comparisons, i.e., calibrations, for measuring the background
immediately behind the test gas.
6.2.10 Device to measure the distance between the OGI camera and
the release point (e.g., tape measure, laser measurement tool),
accurate to at least 2.0 centimeters (cm), with a resolution of at
least 1.0 cm and traceable to the SI through an unbroken chain of
comparisons, i.e., calibrations.
7.0 Camera Calibration and Maintenance
7.1 The camera does not require routine calibration for purposes
of gas leak detection but may require calibration if it is used for
thermography (such as with [Delta]T determination features).
Operators should follow manufacturer recommendations regarding
maintenance and calibration, as appropriate.
8.0 Camera Specification Confirmation and Development of the Operating
Envelope
8.1 Determine that the OGI camera meets the specifications in
Section 6.1 prior to conducting surveys with the OGI camera. The
determination in Section 6.1.1 must also be made any time the OGI
camera will be used to survey components on equipment that was not
previously included in monitoring surveys or whenever there are
process changes that are expected to cause the gaseous emissions
composition to
[[Page 17221]]
change. The determination in Section 6.1.2 is only required
initially. The results of this determination must be documented.
8.2 Field conditions such as the viewing distance to the
component to be monitored, wind speed, ambient air temperature, and
the background temperature all have the potential to impact the
ability of the OGI camera operator to detect a leak. It is important
that the OGI camera has been tested under the full range of expected
field conditions in which the OGI camera will be used.
8.3 An operating envelope must be established for field use of
the OGI camera. Imaging must not be performed when the conditions
are outside of the developed operating envelope.
8.3.1 The operating envelope is specific to each model of OGI
camera. The operating envelope can be developed by the owner or
operator, the camera manufacturer, or a third party. The operating
envelope must be developed initially, prior to conducting surveys
with the OGI camera. The operating envelope may be updated or
expanded at any time, following the procedures in this section.
8.3.2 The operating envelope must be confirmed for all potential
configurations that could impact the detection limit, such as high
sensitivity modes, available lenses, and handheld versus tripod.
Conversely, separate operating envelopes may be developed for
different configurations. If, in addition to or in lieu of the
display on the camera itself, an external device (e.g., laptop,
tablet) is intended to be used to visualize the leak in the field,
the operating envelope must be developed while using the external
device. If the external device will not be used at all times, use of
the external device is considered a separate configuration, and the
operating envelope testing must be performed for both
configurations.
8.4 Development of the operating envelope is to be performed
using the test gas composition, flow rate, and orifice diameter
described in Section 6.1.2, and must include the following
variables:
8.4.1 Delta-T, regulated through the use of a temperature-
controlled background encompassing approximately 50 percent of the
field of view, with no potential for solar interference;
8.4.2 Viewing distance from the OGI camera to the component
being imaged; and
8.4.3 Wind speed, controlled through the use of an industrial
fan.
8.5 Determine the operating envelope using the following
procedure:
8.5.1 Set up the methane test gas at a flow rate of 19 g/hr.
8.5.2 For this flow rate, the ability of the OGI camera to
produce an observable image is challenged by ranges of the variables
in Sections 8.4.1 through 8.4.3.
8.5.3 A panel of no less than 4 observers who have been trained
using the OGI camera and who have a demonstrated capability of
detecting gaseous leaks will observe the test gas release for each
combination of delta-T, distance, and wind speed. A test emission is
determined to be observed when at least 75 percent of the observers
(i.e., 3 of the 4 observers) see the image.
8.5.4 Repeat the procedures in Sections 8.5.2 and 8.5.3 using
either an n-butane test gas at a flow rate of 29 g/hr or a propane
test gas at a flow rate of 22 g/hr.
8.5.5 The operating envelope to be used in the field for each
OGI camera configuration tested is the more restrictive operating
envelope developed between the two test gases.
8.5.6 Repeat the procedures in Sections 8.5.1-8.5.5 for each
camera configuration that will be used to conduct surveys in the
field.
8.6 The results of the testing to establish the operating
envelope, including supporting videos, must be documented.
8.7 If an operating envelope has not been developed for an OGI
camera model or an OGI camera operator wants to expand an operating
envelope to account for site-specific conditions, a daily field
check for maximum viewing distance must be completed prior to
conducting a monitoring survey. This daily field check for maximum
viewing distance does not need to be performed if an OGI suvey will
be conducted within an operating envelope developed according to
Sections 8.3 through 8.6.
8.7.1 A complete video record of the daily field check must be
retained with the OGI survey records.
8.7.2 Each OGI camera operator who will conduct the monitoring
survey must complete their own daily field check for maximum viewing
distance using the OGI camera they will use to complete the
monitoring survey. The daily field check must be conducted for each
camera configuration that will be used during the monitoring survey.
8.7.3 The daily field check must be performed using the test gas
composition and orifice diameter described in Section 6.1.2.
8.7.4 The daily field check must be conducted first for methane
at a flow rate of 19 g/hr and then for either n-butane at a flow
rate of 29 g/hr or propane at a flow rate of 22 g/hr. You must use a
flow meter with a minimum accuracy of 5 percent of the mass rate.
The daily field check for the two gases must occur at the same
delta-T and wind speed conditions.
8.7.5 The OGI camera operator must determine the maximum
distance from the gas release point at which the operator is able to
visualize the gas release with the OGI camera. The OGI camera
operator must document this distance, as well as the delta-T and the
wind speed at the time of the daily field check and include this
information with the OGI survey records.
8.7.6 If the daily check results in different maximum viewing
distances for methane and n-butane/propane, the maximum viewing
distance for the day for the OGI camera operator will be the shorter
of the two maximum viewing distances.
8.7.7 If the delta-T in the field decreases below the delta-T
that was recorded for the daily field check or if the wind speed
increases above the wind speed recorded for the daily field check,
the maximum viewing distance determination must be repeated for the
new delta-T and wind speed conditions.
8.7.8 If multiple camera configurations will be used during the
monitoring survey, the OGI camera operator may use the shortest
maximum viewing distance of any configuration for all the
configurations that will be used during the survey, or the OGI
camera operator may use a different maximum viewing distance for
each configuration that will be used during the survey.
9.0 Conducting the Monitoring Survey
Each site must have a monitoring plan that describes the
procedures for conducting a monitoring survey. One monitoring plan
can be used for multiple sites, as long as the plan contains the
relevant information for each site. At a minimum, the monitoring
plan must include the elements in this section.
9.1 The monitoring plan must include a description of a daily
verification check to be performed prior to imaging to confirm that
the camera is operating properly. This verification must consist of
the following at a minimum:
9.1.1 Confirm that the OGI camera software loads successfully
and does not display any error messages upon startup;
9.1.2 Confirm that the OGI camera focuses properly at the
shortest and longest distances that will be imaged;
9.1.3 Confirm that the OGI camera produces a live IR image using
a known emissions source, such as a butane lighter or a propane
cylinder;
9.1.4 Confirm that the OGI camera can perform the delta-T check
function as expected if this function will be used to meet the
requirement in Section 9.2.3.
9.2 The monitoring plan must include a procedure for ensuring
that the monitoring survey is performed only when conditions in the
field are within the operating envelope established in Section 8 or
the conditions established by the daily field check in Section 8.7.
This procedure must include the following:
9.2.1 If the OGI camera operator will use an operating envelope
established under Section 8, a description of how the viewing
distance from the surveyed components, the wind speed, and the
delta-T will be monitored and how the operator will deal with
changes in site conditions during the survey to ensure that the
monitoring survey is conducted within the limits of the operating
envelope;
9.2.2 If the OGI camera operator performs a daily field check
according to Section 8.7, a description of how the OGI camera
operator will monitor viewing distance to ensure the viewing
distance is less than the daily maximum viewing distance and how the
OGI camera operator will monitor the delta-T and wind speed to
ensure the delta-T remains above and the wind speed remains below
those that occurred during the daily field check;
9.2.3 Description of how the operator will ensure an adequate
delta-T is present in order to view potential gaseous emissions,
e.g., using a delta-T check function built into the features of the
OGI camera or using a background temperature reading in the OGI
camera field of view;
9.2.4 Description of how the operator will recognize the
presence of and deal with potential interferences and/or adverse
monitoring conditions, such as steam, fog,
[[Page 17222]]
mist, rain, solar glint, extremely high concentrations of
particulate matter, and hot temperature backgrounds.
9.3 The site must conduct monitoring surveys using a methodology
that ensures that all the components regulated by the referencing
subpart within the unit or area are monitored. This must be achieved
using one of the following three approaches or a combination of
these approaches. The approach(es) chosen and how the approach(es)
will be implemented must be described in the monitoring plan.
9.3.1 Use of a route map or a map with designated observation
locations. The map must be included as part of the monitoring plan,
with a predetermined sequence of process unit monitoring (such as
directional arrows along the monitoring path) depicted or designated
observation locations clearly marked.
9.3.2 Use of visual cues. The facility must develop visual cues
(e.g., tags, streamers, or color-coded pipes) to ensure that all
components regulated by the referencing subpart were monitored. The
monitoring plan must describe what visual cue method is used and how
it will be used to ensure all components are monitored during the
survey.
9.3.3 Use of global positioning system (GPS) route tracing. The
facility must document the path taken during the survey by capturing
GPS coordinates along the survey path, along with date and time
stamps. These locations should be identified by latitude and
longitude coordinates in decimal degrees to an accuracy and
precision of at least five decimals of a degree using the North
American Datum of 1983. GPS coordinates must be recorded frequently
enough to document that all components regulated by the referencing
subpart were monitored. The monitoring plan must describe how often
GPS coordinates will be recorded and how the route tracing will
ensure all components regulated by the referencing subpart are
monitored.
9.4 The monitoring plan must include a procedure that describes
how components will be viewed with the OGI camera.
9.4.1 Components must be imaged from at least two different
angles.
9.4.2 For a simple scene, which is a scene that contains 10 or
fewer components in the field of view, the OGI camera operator must
have a minimum dwell time on each angle of 10 seconds per scene
before changing the angle, distance, or focus and dwelling again.
9.4.3 For scenes other than simple scenes, the operator must
divide the scene into manageable subsections. The OGI camera
operator must have a minimum dwell time of 2 seconds per component
in the field of view for each angle.
9.4.4 It may be necessary to reduce distance or change angles in
order to reduce the number of components in the field of view. An
OGI camera operator may choose to reduce the distance from
components in order to create simple scenes.
9.4.5 The required dwell times stated in this section are
minimum dwell times. Additional dwell time may be necessary to
assess whether each monitored component is leaking or not leaking.
OGI camera operators should use training and knowledge of
environmental conditions and component configurations to increase
dwell time where appropriate.
9.4.6 The dwell time is the time that the OGI camera is in a
particular operating mode and the scene is in focus and held steady
such that an OGI camera operator is able to monitor for leaks.
Changing OGI camera operating modes or viewing angles requires the
OGI camera operator to restart the dwell time.
9.4.7 The procedure must discuss changes, if necessary, to the
imaging mode of the OGI camera that are appropriate to ensure that
leaks from all components regulated by the referencing subpart can
be imaged.
9.5 The monitoring plan must include a plan for avoiding camera
operator fatigue, as physical, mental, and eye fatigue are concerns
with continuous field operation of OGI cameras. The OGI camera
operator should not survey continuously for a period of more than 30
minutes without taking a rest break. Taking a rest break between
surveys of process units may satisfy this requirement; however, for
process units or complex scenes requiring continuous survey periods
of more than 30 minutes, the operator must take a break of at least
5 minutes after every 30 minutes of surveying. Operators can
complete tasks related to the monitoring survey, such as
documentation, during the 5-minute rest break, so long as the
operator is not actively imaging components.
Note: If continuous surveying is desired for extended time
periods, two camera operators can alternate between surveying and
taking breaks.
9.6 The monitoring plan must include a procedure for documenting
monitoring surveys. The information documented must include:
9.6.1 The name of the facility, date, and approximate start and
end times for each monitoring survey.
9.6.2 The weather conditions, including ambient temperature,
wind speed, relative humidity, and sky conditions at the start and
end of each monitoring survey. For monitoring surveys conducted for
more than four hours, record the weather conditions every two hours.
9.7 The site must have a procedure for documenting fugitive
emissions or leaks found during the monitoring survey.
9.7.1 If a leak is found, capture either a short video clip or
photograph of the component associated with the leak. If the leak is
not immediately repaired, the leaking component must be tagged for
repair. The date, time, location of the leak, and an identification
of the component associated with the leak must be recorded and
stored with the OGI survey records. A full recording of the survey
will suffice for this requirement.
9.7.2 If no emissions are found, no recorded footage is required
to demonstrate that the component was not leaking.
9.8 The monitoring plan must include a quality assurance (QA)
verification video for each OGI operator at least once each
monitoring day. The QA verification video must be a minimum of 5
minutes long and document the procedures the operator uses to survey
(e.g., dwell times, angles, distances, backgrounds) and the camera
configuration.
9.9 The monitoring plan must describe the process that will be
used to ensure the validity of the monitoring data as detailed in
Section 11.
10.0 Camera Operator Training
10.1 The facility or company performing the OGI surveys must
have a training plan which ensures and monitors the proficiency of
the camera operators. Training should include classroom instruction
and field training on the OGI camera and external devices,
monitoring techniques, best practices, process knowledge, and other
regulatory requirements related to leak detection that are relevant
to the facility's OGI monitoring efforts. If the facility does not
perform its own OGI monitoring, the facility must ensure that the
training plan for the company performing the OGI surveys adheres to
this requirement.
10.2 Prior to conducting monitoring surveys, camera operators
must complete initial training and demonstrate proficiency with the
OGI camera and any external devices to be utilized for detecting a
potential leak.
10.2.1 At a minimum, the training plan must include the
following classroom training elements as part of the initial
training. Classroom training can be conducted at a physical
location, remotely, or online.
10.2.1.1 Key fundamental concepts of the OGI camera technology,
such as the types of images the camera is capable of visualizing and
the technology basis (theory) behind this capability.
10.2.1.2 Parameters that can affect image detection (e.g., wind
speed, temperature, distance, background, and potential
interferences).
10.2.1.3 Description of the components to be surveyed and
example imagery of the various types of leaks that can be expected.
10.2.1.4 Operating and maintenance instructions for the OGI
camera used at the facility.
10.2.1.5 Procedures for performing the monitoring survey
according to the monitoring plan, including the daily verification
check; how to ensure the monitoring survey is performed only when
the conditions in the field are within the established operating
envelope; the number of angles a component or set of components
should be imaged from; the minimum dwell time for a scene before
changing the angle, distance, and/or focus; how to improve the
background visualization; the procedure for ensuring that all
components regulated by the referencing subpart are visualized; and
required rest breaks.
10.2.1.6 Recordkeeping requirements.
10.2.1.7 Common mistakes and best practices.
10.2.1.8 Discussion of the regulatory requirements related to
leak detection that are relevant to the facility's OGI monitoring
efforts.
10.2.2 At a minimum, the training plan must include the
following field training elements as part of the initial training:
10.2.2.1 A minimum of 3 survey hours with OGI where trainees
observe the techniques and methods of a senior OGI
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camera operator (see definition in Section 3.0) who reinforces the
classroom training elements.
10.2.2.2 A minimum of 12 survey hours with OGI where the trainee
performs the initial OGI survey with a senior OGI camera operator
verifying the results by conducting a side-by-side comparative
survey and providing instruction/correction where necessary.
10.2.2.3 A minimum of 15 survey hours with OGI where the trainee
performs monitoring surveys independently with a senior OGI camera
operator trainer present and the senior OGI camera operator
providing oversight and instruction/correction to the trainee where
necessary.
10.2.2.4 A final monitoring survey test where the trainee
conducts an OGI survey of at least 2 suvey hours and a senior OGI
camera operator follows behind with a second camera to confirm the
OGI survey results. If there are 10 or more leaks identified by the
senior OGI operator, the trainee must achieve no more than 10
percent missed persistent leaks relative to the senior OGI camera
operator to be considered authorized for independent survey
execution. If there are less than 10 leaks identified by the senior
OGI operator, the trainee must achieve zero missed persistent leaks
relative to the senior OGI camera operator to be considered
authorized for independent survey execution.
10.2.2.5 If the trainee doesn't pass the monitoring survey test
in Section 10.2.2.4, the senior OGI operator must discuss the
reasons for the failure with the trainee and provide instruction/
correction on improving the trainee's performance. Following the
discussion with the senior OGI operator, the trainee may repeat the
test in Section 10.2.2.4.
10.3 All OGI camera operators must attend a biennial classroom
training refresher. This refresher can be shorter in duration than
the initial classroom training but must cover all the salient points
necessary to operate the camera (e.g., performing surveys according
to the monitoring plan, best practices, discussion of lessons
learned). Refresher training can be conducted at a physical
location, remotely, or online.
10.4 Performance audits for all OGI camera operators must occur
on a semiannual basis with at least three months between two
consecutive audits. Performance audits must be conducted according
to one of the following procedures:
10.4.1 Performance audit by comparative monitoring. Comparative
monitoring in near real-time is where a senior OGI camera operator
reviews the performance of the employee being audited by performing
an independent monitoring survey.
10.4.1.1 Following a survey conducted by the camera operator
being audited, the senior OGI camera operator will conduct a survey
of at least 2 survey hours in the same area to ensure that no
persistent leaks were missed.
10.4.1.2 If there are 10 or more leaks identified by the senior
OGI operator, the camera operator being audited must achieve no more
than 10 percent missed persistent leaks relative to the senior OGI
camera operator. If there are less than 10 leaks identified by the
senior OGI operator, the camera operator being audited must achieve
zero missed persistent leaks relative to the senior OGI camera
operator. If the camera operator being audited does not achieve this
benchmark, then the camera operator being audited will need to be
retrained as outlined in Section 10.4.3.
10.4.2 Performance audit by video review. The camera operator
being audited must submit unedited and uncut video footage of their
OGI survey technique to a senior OGI camera operator for review.
10.4.2.1 The videos must contain at least 2 survey hours of
survey footage. If a single monitoring survey is less than 2 survey
hours, footage from multiple monitoring surveys may be submitted;
however, all videos necessary to cover a 2-hour period must be
recorded and submitted for review. The senior OGI camera operator
will review the survey technique of the camera operator being
audited, as well as look for any missed leaks.
10.4.2.2 If the senior OGI camera operator finds that the survey
techniques during the video review do not match those described in
the monitoring plan, then the camera operator being audited will
need to be retrained as outlined in Section 10.4.3. Additionally, if
there are 10 or more leaks identified by the senior OGI operator,
the camera operator being audited must achieve no more than 10
percent missed persistent leaks relative to the senior OGI camera
operator. If there are less than 10 leaks identified by the senior
OGI operator, the camera operator being audited must achieve zero
missed persistent leaks relative to the senior OGI camera operator.
If the camera operator being audited does not achieve this
benchmark, then the camera operator being audited will need to be
retrained as outlined in Section 10.4.3.
10.4.3 At a minimum, retraining must consist of the following
elements:
10.4.3.1 A discussion of the reasons for the failure with the
OGI operator being audited and techniques to improve performance.
10.4.3.2 A minimum of 8 survey hours with OGI where the trainee
performs the initial OGI survey with a senior OGI camera operator
verifying the results by conducting a side-by-side comparative
survey and providing instruction/correction where necessary.
10.4.3.3 A minimum of 8 survey hours with OGI where the trainee
performs the survey independently with the senior OGI camera
operator trainer present and the senior OGI camera operator provides
oversight and instruction/correction to the trainee where necessary.
10.4.3.4 The audited camera operator must perform a final
monitoring survey test as described in Section 10.2.2.4 and meet the
requirements in Section 10.2.2.4 to be recertified.
10.4.4 If an OGI operator requires retraining in two consecutive
semiannual audits, the OGI operator must repeat the initial training
requirements in Section 10.2.
10.4.5 If a camera operator is not scheduled to perform an OGI
survey during a semiannual period, then the audit must occur with
the next scheduled monitoring survey.
10.5 If an OGI camera operator has not conducted a monitoring
survey in over 12 months, then the operator must complete the
retraining requirements in Section 10.4.3 prior to conducting
surveys. If an OGI camera operator has not conducted a monitoring
survey in over 24 months, then the operator must complete the
biennial classroom training in Section 10.3 and complete the
retraining requirements in Section 10.4.3 prior to conducting
surveys.
10.6 Previous experience with OGI camera operation can be
substituted for some of the initial training requirements in Section
10.2 as outlined in this Section 10.6.1 and 10.6.2.
10.6.1 OGI camera operators with previous classroom training (at
a physical location, remotely, or online) that included a majority
of the elements listed in Section 10.2.1 do not need to complete the
initial classroom training as described in Section 10.2.1, but if
the date of training is more than two years before March 8, 2024,
the biennial classroom training in Section 10.3 must be completed in
lieu of the initial classroom training in Section 10.2.1.
10.6.2 OGI camera operators who have 40 survey hours of
experience over the 12 calendar months prior to March 8, 2024 may
substitute the retraining requirements in Section 10.4.3, including
the final monitoring survey test, for the initial field training
requirements in Section 10.2.2.
11.0 Quality Assurance and Quality Control
11.1 As part of the facility's monitoring plan, the facility
must have a process which ensures the validity of the monitoring
data. Examples may include routine review and sign-off of the
monitoring data by the camera operator's supervisor, periodic
comparative monitoring using a different camera operator as part of
a continuing training verification plan described in Section 10, or
other due diligence procedures.
11.2 For each monitoring day, the daily OGI camera verification
must be performed as described in Section 9.1. Additionally, the
daily QA verification video for each operator must be recorded as
described in Section 9.8 for each operator for each monitoring day.
11.3 The following table is a summary of the mandatory QA and
quality control (QC) measures in this protocol with the associated
frequency and acceptance criteria. All of the QA/QC data must be
documented and kept with other OGI records.
[[Page 17224]]
Summary Table of QA/QC
----------------------------------------------------------------------------------------------------------------
Parameter QA/QC specification Acceptance criteria Frequency
----------------------------------------------------------------------------------------------------------------
OGI Camera Design................. Spectral bandpass Must overlap with major Once initially (prior to
range. absorption peak of the using the OGI camera to
compound(s) of interest. conduct surveys), when
survey components on
equipment that was not
previously included in
monitoring surveys,
whenever there are
process changes that are
expected to cause the
gaseous emissions
composition to change.
OGI Camera Design................. Initial camera Must be capable of Once initially (prior to
specification detecting (or producing a using the OGI camera to
confirmation. detectable image of) conduct surveys).
methane emissions of 19 g/
hr and either n-butane
emission of 29 g/hr or
propane emissions of 22 g/
hr at a viewing distance
of 2.0 meters and a delta-
T of 5.0 [deg]C in an
environment of calm wind
conditions around 1.0 m/s
or less.
Developing the Operating Envelope. Observation Leak is observed by 3 out Once initially (prior to
confirmation. of 4 panel observers for using the OGI camera to
specific combinations of conduct surveys) and
delta-T, distance, and prior to using a new
wind speed. camera configuration for
which an envelope was
not previously
established. The
operating envelope may
be updated or expanded
at any time, following
the procedures in
Section 8.
Daily Field Check................. Maximum viewing Determine distance at Each monitoring day. Not
distance. which each OGI camera required for OGI camera
operator can visualize operators using
leaks according to operating envelopes
Section 8.7. established according to
Section 8.
OGI Camera Functionality.......... Verification Check... Meet the requirements of Each monitoring day,
Section 9.1 to confirm prior to conducting a
that the OGI camera survey.
software loads
successfully and that the
camera focuses properly,
produces a live IR image,
and, as applicable,
performs the delta-T
check function.
Camera Operator Training.......... Classroom training... Meet the requirements of Prior to conducting
Sections 10.2.1 and 10.3 surveys (except as noted
with the issuing of a in Section 10.6.1), with
certificate or record of a biennial refresher.
attendance.
Camera Operator Training.......... Field training....... Meet the requirements of Except as noted in
Section 10.2.2 while Section 10.6.2, prior to
maintaining the records conducting surveys and
of survey hours by the if retraining is
trainee along with a required following two
certificate or record of consecutive semiannual
completion issued upon audits.
passing the final
monitoring survey test in
Section 10.2.2.4 with the
date of the survey
recorded.
OGI Camera Operator Performance... Semiannual Comparative monitoring or Every 6 months, with at
performance audits. video review. Meet the least 3 months between
benchmarks in Section consecutive audits or at
10.4.1.2 or 10.4.2.2. the next scheduled
monitoring survey if a
camera operator is not
scheduled to perform an
OGI survey during the
semiannual period.
Camera Operator Training.......... Field retraining..... Meet the requirements of After failing to meet the
Section 10.4.3 while benchmarks in Section
maintaining the records 10.4.1.2 or 10.4.2.2
of survey hours by the during a semiannual
trainee along with a audit or after a
certificate or record of prolonged period
completion issued upon (greater than 12 months)
passing the final of not performing OGI
monitoring survey test in surveys. May be
Section 10.2.2.4 with the substituted for initial
date of the survey field training as noted
recorded. in Section 10.6.2.
OGI Camera Operator Performance... QA verification video Record a video that is a Each monitoring day.
minimum of 5 minutes long
that documents the
procedures the operator
uses to survey (e.g.,
dwell times, angles,
distances, backgrounds)
and the camera
configuration.
----------------------------------------------------------------------------------------------------------------
12.0 Recordkeeping
12.1 Records must be kept for a period of 5 years, unless
otherwise noted below or otherwise specified in a referencing
subpart. Records may be retained in hard copy or electronic form.
12.2 The facility must maintain the following records in a
manner that is easily accessible to all OGI camera operators. These
records must be retained for as long as the site performs OGI
surveys. Older versions of these records that are no longer relevant
because they have been replaced by newer versions must be retained
for a period of 5 years past the date on which they are replaced.
12.2.1 Complete site monitoring plan with all the required
elements.
12.2.2 The OGI camera operating envelope limitations.
12.3 All data supporting the OGI camera specification
confirmation (initially and updated as required in Section 8.1) and
development of the operating envelope. While the owner or operator
does not need to have a copy of these records onsite if another
entity performed the camera specification confirmation or
development of the operating envelope, the owner or operator must:
(1) Ensure that the camera specification confirmation and
development of the operating envelope were performed in accordance
with the requirements of this appendix K,
[[Page 17225]]
(2) Ensure easy access to these records, and
(3) Make the records available for review if requested by the
Administrator.
These records must be retained for the entire period that the
OGI camera is used to conduct surveys at the site plus 5 years.
12.4 The training plan for OGI camera operators. The plan must
be retained for as long as the site performs OGI surveys. Older
versions of the plan that are no longer relevant because they have
been replaced by a newer version must be retained for a period of 5
years past the date on which they are replaced. If the facility does
not perform its own OGI monitoring, the owner or operator must:
(1) Ensure that the training plan for the company performing the
OGI surveys adheres to the requirements of this appendix K,
(2) Ensure easy access to the plan, and
(3) Make the plan available for review if requested by the
Administrator.
12.5 For each OGI camera operator, the following records. These
may be kept in a separate location for privacy but must be easily
accessible to program administrators and available for review if
requested by the Administrator. It may be necessary to retain the
records in Section 12.5.3 for longer than 5 years to show the career
experience survey hours for senior OGI camera operators. If the
facility does not perform its own OGI monitoring, the owner or
operator must:
(1) Ensure that the training plan for the company performing the
OGI surveys adheres to the requirements of this appendix K,
(2) Be able to easily access these records, and
(3) Make the records available for review if requested by the
Administrator.
The records must include the following information.
12.5.1 The date of completion of initial OGI camera operator
classroom training;
12.5.2 The date of the passed final site survey test following
the initial OGI camera operator field training or retraining;
12.5.3 The number and date of all surveys performed, and if the
survey is part of initial field training or retraining, the amount
of survey hours and notation of whether the survey was performed by
observing a senior OGI camera operator, side-by-side with a senior
OGI camera operator, or with oversight from a senior OGI camera
operator;
12.5.4 The date and results of semiannual performance audits;
12.5.5 The date of the biennial classroom training refresher;
and
12.5.6 Documentation to support the use of previous experience
as a substitution for initial training requirements, including the
date of previous classroom training and documentation of survey
hours over the 12 calendar months prior to March 8, 2024, as
appropriate.
12.6 Monitoring survey results shall be kept in a manner that is
accessible to those technicians executing repairs and at a minimum
must contain the following:
12.6.1 Daily verification check;
12.6.2 Identification of the site surveyed, the survey date, and
the start and end times of the survey;
12.6.3 Name of the OGI camera operator performing the survey and
identification of the OGI camera used to conduct the survey. The
identification of the OGI camera can be the serial number or an
assigned name/number labeled on the camera, but it must allow an
operator or inspector to tie the camera back to the records
associated with the camera (e.g., maintenance, initial specification
confirmation);
12.6.4 Weather conditions, including the ambient temperature,
wind speed, relative humidity, and sky conditions, at the start and
end of the survey and every two hours (if the survey exceeded four
hours in length);
12.6.5 Video footage or photograph of any leak detected, or
video footage of the entire survey, along with the date, time, and
location of the leak, and identification of the component associated
with the leak;
12.6.6 The daily QA verification video for each operator; and
12.6.7 GPS coordinates for the route taken, if Section 9.3.3 is
used to ensure all components regulated by the referencing subpart
are monitored.
12.7 For each instance that an OGI camera operator uses the
daily field check outlined in Section 8.7 instead of an operating
enveloped established under Section 8, the following records must be
kept with the monitoring survey records required by Section 12.6.
12.7.1 Date and time of each daily field check.
12.7.2 Video record of the daily field check.
12.7.3 Maximum viewing distance determined for each test gas in
each configuration for each OGI camera operator. The overall maximum
viewing distance (or overall maximum viewing distance per
configuration) that will be used for the monitoring day for each OGI
camera operator.
12.7.4 The delta-T and wind speed at the time of the daily field
check.
12.7.5 Documentation of the test gas flow rate and
concentrations during the daily field check.
12.8 Camera maintenance and calibration records over the entire
period that the OGI camera is used to conduct surveys at the site.
Older versions of these records that are no longer relevant because
they have been replaced by newer versions must be retained for a
period of 5 years past the date on which they are replaced. If the
facility does not perform its own OGI monitoring, the owner or
operator must be able to easily access these records and must make
the records available for review if requested by the Administrator.
13.0 References
13.1 U.S. Department of Health and Human Services. (2010). NIOSH
Pocket Guide to Chemical Hazards. NIOSH Publication No. 2010-168c.
Also available from https://www.cdc.gov/niosh/docs/2010-168c/default.html.
13.2 U.S. Environmental Protection Agency. (2023). Technical
Support Document: Optical Gas Imaging Protocol (Appendix K to this
part).
13.3 U.S. Environmental Protection Agency. (2020). Optical Gas
Imaging Stakeholder Input Workshop Presentations and Discussion;
Summary Letter Report.
13.4 Zimmerle, D., T. Vaughn, C. Bell, K. Bennett, P. Deshmukh,
and E. Thoma. (2020). Detection Limits of Optical Gas Imaging for
Natural Gas Leak Detection in Realistic Controlled Conditions.
Environmental Science & Technology, 54(18), 11506-11514. DOI:
10.1021/acs.est.0c01285.
14.0 Annexes
14.1 Annex 1--Development of Response Factors for OGI Cameras.
14.1.1 Introduction.
The purpose of this annex 14.1 is to outline the protocol for
the development of response factors (RFs) for optical gas imaging
(OGI) cameras. As defined in Section 3.0 of this appendix K, a
response factor is the OGI camera's response to a compound of
interest relative to a reference compound at a concentration path-
length of 10,000 parts per million-meter (ppm-m).
14.1.1.1 Nomenclature.
14.1.1.1.1 The definitions listed in Section 3.0 of this
appendix K apply to this annex 14.1.
14.1.1.1.2 Infrared (IR) radiance pixel area. The IR radiance
pixel area is the average of a set of pixel IR radiance for an
instantaneous measurement. There will be three different areas
representing the reference cell, gas cell, and the raw blackbody
surface. The pixel count for each area must be at a minimum of 0.5
percent of the total pixels of the detector. The pixel locations
selected for an area must not change throughout the test.
14.1.1.1.3 Measurement data set. Measurement data set is the
number of time independent IR radiance pixel areas that are taken.
The minimum number of measured IR radiance pixel area within a data
set is 1,000 data points. The number of measured IR radiance pixel
area within a measurement data set should stay consistent throughout
the test.
14.1.1.1.4 Reference Compound. The reference compound is the
compound that provides the reference for determination of the RF
with the compound of interest. The reference compound for this annex
14.1 is propane, unless otherwise specified in a referencing
subpart.
14.1.2 Applicability and Analytical Principle.
14.1.2.1 Applicability. This annex 14.1 applies to the
determination of compound specific RFs through empirical testing for
use with this appendix K. This annex 14.1 does not apply to other
applications of OGI cameras or other instruments. This annex 14.1
does not limit the use of other peer reviewed and published
techniques and RFs per Section 3.0 of this appendix K.
14.1.2.2 Analytical Principle. OGI cameras work by providing an
image or video with each pixel representing a measurement of the IR
radiation. OGI cameras limit measurement to specific wavelengths of
IR through the choice of the detector and generally through the
addition of a bandpass filter. Limiting the measurement to specific
wavelengths of IR allows the OGI camera to focus on a specific
region of interest in order to increase the detection capabilities
of
[[Page 17226]]
particular compounds of interest. The combination of detector and
bandpass filter, in addition to limiting the region of interest,
will allow varying amounts of IR over the specific wavelength
region.
14.1.3.0 Equipment and Supplies.
14.1.3.1 Section 6.0 of this appendix K lists equipment and
supplies that may be used in this annex 14.1.
14.1.3.2 Blackbody Source. A sufficiently large blackbody source
capable of maintaining high emissivity, as well as temperature
stability and homogeneity.
14.1.3.2.1 The blackbody must have an emissivity of 0.95 or
higher in the IR region of interest.
14.1.3.2.2 The source emissive area must have a uniform
temperature, where uniform is defined as all points on the emissive
area deviating no more than 0.10 degree Celsius ([deg]C) from the
average temperature of the emissive area. The temperature readings
must be accurate to at least 0.10 [deg]C. The blackbody must be able
to maintain its temperature within 0.10 [deg]C.
14.1.3.2.3 The source's surface area must be large enough to
allow the OGI camera to take IR measurements of two gas cells and
allow for the proper measurement of IR radiance through the gas and
reference cell and IR radiance of the surface itself.
14.1.3.3 Test gas for each compound of interest, used for
determining the RF. The concentration of the gas in the cylinder
must be vendor certified to 5.0 percent of the cylinder
tag value and be in a balance of nitrogen. The concentration of the
gas must be such that the gas cell concentration is 10,000 ppm-m
with less than 2.0 percent error. Alternatively, the gas standard
may be produced with dilution per Method 205 of 40 CFR part 51
Appendix M with the exception that the mid-supply gas may be vendor
certified to 5.0 percent of the cylinder tag value.
14.1.3.4 Gas Cell. A windowed gas cell that is leak tight and
has the ability to flow gas through the cell. The size of the cell
should be such to allow for 10,000 ppm-m to be viewed by the OGI
camera with less than 2.0 percent error. The windows should be 99
percent transmissive in the IR region of interest and deviate no
more than 0.50 percent transmission over than region of interest.
The cell must have associated temperature, flow, and pressure
measurements.
14.1.3.5 Reference Compound Gas Standard. Propane gas standard,
unless a referencing subpart specifies otherwise, used as the
reference for determination of the RF. The concentration of the gas
in the cylinder must be vendor certified to 2.0 percent
of the cylinder tag value and be in a balance of nitrogen. The
concentration of the gas must be such that the gas cell
concentration is 10,000. ppm-m with less than 2.0 percent error.
14.1.3.6 Reference Cell. A gas cell for the reference compound
gas standard which meets all of the requirements in Section 14.1.3.4
of this annex 14.1.
14.1.3.7 Zero Gas. A 99.99 percent pure diatomic gas, typically
nitrogen, that has no IR response from the OGI camera, used to
assess the detection level of the system and baseline response of
the gas cells.
14.1.3.8 OGI Camera is the specific OGI camera that is being
tested. RFs must be determined for each IR detector and bandpass
filter combination. The OGI camera must have the ability to output
the raw IR radiance at the pixel level.
14.1.3.8.1 The combination of IR detector and bandpass filter
may be consistent over several models such that the developed RFs
may be applicable to more than one model of OGI camera.
14.1.3.8.2 If the OGI camera model has exchangeable bandpass
filters, more than one set of RFs may be needed for the OGI camera
model to account for the differences between filters.
4.0 Pre-Test Preparation and Evaluations.
14.1.4.1 Room Preparation. The room where testing will occur
must be prepared by removing all extraneous thermal sources, or at a
minimum, isolating extraneous thermal sources with IR absorptive
material before any testing is conducted.
14.1.4.2 Reference and Gas Cell Preparation. Perform leak checks
on both the reference and gas cells. Ensure that the temperatures of
the cells are within 0.10 [deg]C and that the pressure measurements
are working.
14.1.4.3 OGI Camera Preparation. Ensure the OGI camera is
operating to manufacturer specifications and able to record in raw
IR radiance on a per pixel basis.
14.1.4.4 Blackbody Preparation and Verification. Prepare the
blackbody by setting the temperature 10.0 [deg]C different than the
gas and reference cell temperatures. Ensure the blackbody is working
correctly by verifying the IR radiance homogeneity of the blackbody
surface with the OGI camera.
14.1.4.5 System Preparation. Ensure the alignment of the cells,
blackbody source, and OGI camera are all fixed in place and cannot
deviate from their position during the testing.
14.1.4.5.1 The reference and gas cell windows must overlap the
blackbody surface in a manner that provides sufficient viewing of
the blackbody surface from the vantage point of the camera.
14.1.4.5.2 The reference and gas cells should be placed
sufficiently away from the blackbody surface. The distance must be
far enough to ensure that the reference and gas cells are not heated
or cooled by the blackbody surface.
14.1.4.5.3 The OGI camera should be located at a distance such
that the field of view allows the requirements of the IR radiance
pixel area to be met. Additionally, the distance must be such that
it does not nominally change the path length of the cell.
14.1.4.5.4 For both the reference cell and the gas cell, the
depth of the cell and concentration of the gas must result in a
concentration 10,000. ppm-m with less than 2 percent error.
14.1.4.6 Initial System Assessment.
14.1.4.6.1 Flow zero gas through both the reference and gas
cell, and ensure the gas cell temperatures are within 0.1 [deg]C.
14.1.4.6.2 Record the temperatures of the gas and reference
cells, the blackbody surface, and the room. Record the pressures in
the reference and gas cells. Record the flowrates into the reference
and gas cells.
14.1.4.6.3 Measure the IR radiance of the reference cell, the
gas cell, and the blackbody surface for a measurement data set. For
the IR radiance pixel area for the blackbody, the blackbody through
the reference cell, and the blackbody through the gas cell,
calculate the average, the standard deviation, and the 99 percent
confidence level for the measurement data set.
14.1.4.6.4 The detection limit for the system will be the
highest 99 percent confidence level of the IR radiance measurement
of the blackbody, blackbody through the reference cell, or blackbody
through the gas cell.
14.1.4.6.5 If the standard deviation of the reference cell's and
the gas cell's average pixel areas of interest have a difference
greater than 5 percent, take corrective actions and repeat the
assessment.
14.1.5.0 Sampling and Analysis Procedure.
14.1.5.1 Flow reference compound gas through the reference cell
and test gas for the compound of interest through the gas cell and
ensure the cell temperatures are within 0.10 [deg]C.
14.1.5.2 Record the temperatures of the gas and reference cells,
the blackbody surface, and the room temperature. Record the
pressures in the reference and gas cells. Record the flowrates into
the reference and gas cells. If using Method 205 of 40 CFR part 51
Appendix M for dilution of the test gas for the compound of
interest, record the appropriate parameters required by the method.
14.1.5.3 Adjust the gas flow if the pressure in the cell is not
within an inch of water of ambient pressure. Ensure cell
temperatures are within 0.10 [deg]C of the room temperature.
14.1.5.4 Measure the IR radiance of the reference cell, the gas
cell, and the blackbody surface for a measurement data set.
Calculate the average of the IR radiance pixel area and the standard
deviation of the IR radiance pixel area for the reference cell, gas
cell, and the blackbody surface for the measurement data set.
14.1.6.0 Post-test Requirements.
14.1.6.1 Post-test Assessment.
14.1.6.1.1 Flow zero gas through both the reference and gas
cells and ensure the cell temperatures are within 0.1 [deg]C.
14.1.6.1.2 Record the temperatures of the gas and reference
cells, the blackbody surface, and the room. Record the pressures in
the reference and gas cells. Record the flowrates into the reference
and gas cells.
14.1.6.1.3 Measure the IR radiance of the reference cell, the
gas cell, and the blackbody surface for a measurement data set.
Calculate the average of the IR radiance pixel area, the standard
deviation of the IR radiance pixel area, and the 99 percent
confidence level of the IR radiance pixel area for the reference
cell, gas cell, and the blackbody surface for the measurement data
set.
14.1.6.1.4 If the average and standard deviation of the
reference cell's and the gas cell's average pixel areas of interest
have a difference greater than 5.0 percent between the pre-test and
post-test assessment, then the test is invalid. Take corrective
actions and repeat the test.
14.1.6.2 When the average of the IR radiance pixel areas for the
compound of
[[Page 17227]]
interest over the measurement set as determined in Section 14.1.5.4
of this annex 14.1 is greater than the detection limit established
in Section 14.1.4.6.4 of this annex 14.1, calculate the RF for the
compound of interest as follows:
[GRAPHIC] [TIFF OMITTED] TR08MR24.043
RF = response factor of the compound of interest (unitless).
IBlackbody = average of the IR radiance pixel areas for
the blackbody over the measurement set as determined in Section
14.1.4.6.3 of this annex 14.1,
W[middot]m-2[middot]sr-1 (watts per square
meter per steradian).
ICompound of interest = average of the IR radiance pixel
areas for the compound of interest over the measurement set as
determined in Section 14.1.5.4 of this annex 14.1,
W[middot]m-2[middot]sr-1.
IGas Cell = average of the IR radiance pixel areas for
the gas cell over the measurement set during the pre-test assessment
as determined in Section 14.1.4.6.3 of this annex 14.1,
W[middot]m-2[middot]sr-1.
IReference Compound = average of the IR radiance pixel
areas for the reference compound over the measurement set as
determined in Section 14.1.5.4 of this annex 14.1,
W[middot]m-2[middot]sr-1.
IReference Cell = average of the IR radiance pixel areas
for the reference cell over the measurement set during the pre-test
assessment as determined in Section 14.1.4.6.3 of this annex 14.1,
W[middot]m-2[middot]sr-1.
14.1.6.3 When the average of the IR radiance pixel areas for the
compound of interest over the measurement set as determined in
Section 14.1.5.4 of this annex 14.1 is less than the detection limit
established in Section 14.1.4.6.4 of this annex 14.1, the RF is
equal to zero.
14.1.7.0 Reporting and Recordkeeping Requirements.
14.1.7.1 Records, including all raw data and calculations, must
be kept for a period of 5 years, unless otherwise noted below or
otherwise specified in a referencing subpart. Records may be
retained in hard copy or electronic form.
14.1.7.2 All records supporting the development of RFs under
this annex 14.1 must be maintained in a manner that is easily
accessible to all OGI camera operators using the RFs. While the
owner or operator does not need to have a copy of these records
onsite if another entity performed the development of the RFs, the
owner or operator must:
(1) Ensure that the RF development was performed in accordance
with the requirements of this annex,
(2) Ensure easy access to these records, and
(3) Make the records available for review if requested by the
Administrator.
These records must be retained for the entire period that the
OGI camera is used to conduct surveys at the site plus 5 years.
Previous versions of these records that are no longer relevant
because they have been replaced by newer versions or because the
specific OGI camera model is no longer being used to conduct surveys
at the site must be retained for a period of 5 years past the date
on which the records are replaced or the OGI camera model is no
longer being used to conduct surveys at the site.
14.1.8.0 References.
14.1.8.1 U.S. Environmental Protection Agency. (2023). Technical
Support Document: Optical Gas Imaging Protocol (appendix K to this
part).
[FR Doc. 2024-00366 Filed 2-23-24; 4:15 pm]
BILLING CODE 6560-50-P