[Federal Register Volume 89, Number 94 (Tuesday, May 14, 2024)]
[Rules and Regulations]
[Pages 42062-42327]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-08988]
[[Page 42061]]
Vol. 89
Tuesday,
No. 94
May 14, 2024
Part II
Environmental Protection Agency
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40 CFR Part 98
Greenhouse Gas Reporting Rule: Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems; Final Rule
Federal Register / Vol. 89 , No. 94 / Tuesday, May 14, 2024 / Rules
and Regulations
[[Page 42062]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 98
[EPA-HQ-OAR-2023-0234; FRL-10246-02-OAR]
RIN 2060-AV83
Greenhouse Gas Reporting Rule: Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: The Environmental Protection Agency (EPA) is amending
requirements that apply to the petroleum and natural gas systems source
category of the Greenhouse Gas Reporting Rule to ensure that reporting
is based on empirical data, accurately reflects total methane emissions
and waste emissions from applicable facilities, and allows owners and
operators of applicable facilities to submit empirical emissions data
that appropriately demonstrate the extent to which a charge is owed
under the Waste Emissions Charge. The EPA is also amending certain
requirements that apply to the general provisions, general stationary
fuel combustion, and petroleum and natural gas systems source
categories of the Greenhouse Gas Reporting Rule to improve calculation,
monitoring, and reporting of greenhouse gas data for petroleum and
natural gas systems facilities. This action also establishes and amends
confidentiality determinations for the reporting of certain data
elements to be added or substantially revised in these amendments.
DATES: This rule is effective January 1, 2025, except for Sec. 98.233
(amendatory instruction 12), Sec. 98.236 (amendatory instruction 16),
and Sec. 98.238 (amendatory instruction 19) which are effective July
15, 2024. The incorporation by reference of certain material listed in
this final rule is approved by the Director of the Federal Register as
of January 1, 2025.
ADDRESSES: The EPA has established a docket for this action under
Docket ID. No. EPA-HQ-OAR-2023-0234. All documents in the docket are
listed in the https://www.regulations.gov index. Although listed in the
index, 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. Publicly available docket materials are available
either electronically in https://www.regulations.gov or in hard copy at
the EPA Docket Center, WJC West Building, Room 3334, 1301 Constitution
Ave. NW, Washington, DC. This Docket Facility is open from 8:30 a.m. to
4:30 p.m., Monday through Friday, excluding legal holidays. The
telephone number for the Public Reading Room is (202) 566-1744 and the
telephone number for the Air Docket is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Jennifer Bohman, Climate Change
Division, Office of Atmospheric Programs (MC-6207A), Environmental
Protection Agency, 1200 Pennsylvania Ave. NW, Washington, DC 20460;
telephone number: (202) 343-9548; email address: [email protected].
For technical information, please go to the Greenhouse Gas Reporting
Program (GHGRP) website, https://www.epa.gov/ghgreporting. To submit a
question, select Help Center, followed by ``Contact Us.''
World Wide Web (WWW). In addition to being available in the docket,
an electronic copy of this final rule will also be available through
the WWW. Following the Administrator's signature, a copy of this final
rule will be posted on the EPA's GHGRP website at https://www.epa.gov/ghgreporting.
SUPPLEMENTARY INFORMATION:
Regulated entities. These final revisions affect certain entities
that must submit annual greenhouse gas (GHG) reports under the GHGRP
(40 CFR part 98). These are amendments to existing regulations and will
affect owners or operators of petroleum and natural gas systems that
directly emit GHGs. Regulated categories and entities include, but are
not limited to, those listed in table 1 of this preamble:
[GRAPHIC] [TIFF OMITTED] TR14MY24.000
Table 1 of this preamble is not intended to be exhaustive, but
rather provides a guide for readers regarding facilities likely to be
affected by this action. This table lists the types of facilities that
the EPA is now aware could potentially be affected by this action.
Other types of facilities than those listed in the table could also be
subject to reporting requirements. To determine whether you will be
affected by this action, you should carefully examine the applicability
criteria found in 40 CFR part 98, subpart A (General Provisions) and 40
CFR part 98, subpart W (Petroleum and Natural Gas Systems). If you have
questions regarding the applicability of this action to a particular
facility, consult the person listed in the FOR FURTHER INFORMATION
CONTACT section.
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
AGR acid gas removal unit
AMLD Advanced Mobile Leak Detection
API American Petroleum Institute
[[Page 42063]]
ASTM American Society for Testing and Materials
AVO audio, visual, and olfactory
BOEM U.S. Bureau of Ocean Energy Management
BRE Bryan Research & Engineering
BSER best system of emissions reduction
Btu/scf British thermal units per standard cubic foot
CAA Clean Air Act
CBI confidential business information
CE combustion efficiency
CEMS continuous emissions monitoring system
CenSARA Central States Air Resources Agency
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e carbon dioxide equivalent
CRR cost-to-revenue ratio
DE destruction efficiency
DI&M directed inspection and maintenance
DOE Department of Energy (DOE)
DRE destruction and removal efficiency
e-GGRT electronic Greenhouse Gas Reporting Tool
EG emission guidelines
EIA U.S. Energy Information Administration
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
FAQ frequently asked question
FLIGHT Facility Level Information on Greenhouse gases Tool
FR Federal Register
FTIR Fourier transform infrared
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GOR gas to oil ratio
gpm gallons per minute
GRI Gas Research Institute
GT gas turbines
HHV higher heating value
ICR information collection request
ID identification
IRA Inflation Reduction Act of 2022
IVT Inputs Verification Tool
kg/hr kilograms per hour
LDAR leak detection and repair
LDC local distribution company
LNG liquefied natural gas
m meters
MDEA methyl diethanolamine
MEA monoethanolamine
MMBtu/hr million British thermal units per hour
MMscf million standard cubic feet
mt metric tons
mtCO2e metric tons carbon dioxide equivalent
N2O nitrous oxide
NAICS North American Industry Classification System
NGLs natural gas liquids
NRU nitrogen recovery unit
NSPS new source performance standards
NYSERDA New York State Energy Research and Development Authority
O&M operation and maintenance
OCS AQS Outer Continental Shelf Air Quality System
OEL open-ended line
OEM original equipment manufacturer
OGI optical gas imaging
OMB Office of Management and Budget
OTM other test method
PBI proprietary business information
PHMSA U.S. Pipeline and Hazardous Materials Safety Administration
ppm parts per million
ppmv parts per million by volume
PRA Paperwork Reduction Act
PRD pressure relief device
psig pounds per square inch gauge
PTE potential to emit
RFA Regulatory Flexibility Act
RFI Request for Information
RICE reciprocating internal combustion engines
RY reporting year
SCADA supervisory control and data acquisition
scf standard cubic feet
scf/hr/device standard cubic feet per hour per device
TCEQ Texas Commission on Environmental Quality
THC total hydrocarbon
TOC total organic carbon
TSD technical support document
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
VISR Video Imaging Spectro-Radiometry
VOC volatile organic compound(s)
WEC waste emissions charge
WWW World Wide Web
Table of Contents
I. Background
A. How is this preamble organized?
B. Executive Summary
C. Background on This Final Rule
D. Legal Authority
E. Relationship to Other Clean Air Act Section 136 Actions
F. Relationship to Clean Air Act Section 111
II. Overview and Rationale for Final Amendments to 40 CFR Part 98,
Subpart W
A. Revisions To Address Potential Gaps in Reporting of Emissions
Data for Specific Sectors
B. Revisions To Add New Emissions Calculation Methodologies or
Improve Existing Emissions Calculation Methodologies
C. Revisions to Reporting Requirements To Improve Verification
and Transparency of the Data Collected
D. Technical Amendments, Clarifications, and Corrections
III. Final Amendments to Part 98 and Summary of Comments and
Responses
A. General and Applicability Amendments
B. Other Large Release Events
C. New and Additional Emission Sources
D. Reporting for the Onshore Petroleum and Natural Gas
Production and Onshore Petroleum and Natural Gas Gathering and
Boosting Industry Segments
E. Natural Gas Pneumatic Device Venting and Natural Gas Driven
Pneumatic Pump Venting
F. Acid Gas Removal Unit Vents
G. Dehydrator Vents
H. Liquids Unloading
I. Gas Well Completions and Workovers With Hydraulic Fracturing
J. Blowdown Vent Stacks
K. Atmospheric Storage Tanks
L. Flared Transmission Storage Tank Vent Emissions
M. Associated Gas Venting and Flaring
N. Flare Stack Emissions
O. Compressors
P. Equipment Leak Surveys
Q. Equipment Leaks by Population Count
R. Offshore Production
S. Combustion Equipment
T. Leak Detection and Measurement Methods
U. Industry Segment-Specific Throughput Quantity Reporting
V. Other Final Minor Revisions or Clarifications
IV. Effective Date of the Final Amendments
A. Amendments That Are Effective on January 1, 2025
B. Amendments That Are Effective July 15, 2024
V. Final Confidentiality and Reporting Determinations for Certain
Data Reporting Elements
A. EPA's Approach To Assess Data Elements
B. Final Confidentiality Determinations and Emissions Data
Designations
C. Final Reporting Determinations for Inputs to Emission
Equations
VI. Impacts of the Final Amendments
A. Cost Analysis
B. Cost-to-Revenue Ratio Analysis
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and 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 That Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act and 1 CFR
part 51
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act (CRA)
L. Judicial Review
M. Determination Under CAA Section 307(d)
N. Severability
I. Background
A. How is this preamble organized?
The first section of this preamble contains background information
on the August 1, 2023 proposed amendments (88 FR 50282, hereafter
referred to as ``2023 Subpart W Proposal'') and on this final rule, as
well as a summary of the final revisions. This section also discusses
the EPA's legal authority under the Clean Air Act (CAA) to
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promulgate (including subsequent amendments to) the Greenhouse Gas
Reporting Rule, codified at 40 CFR part 98 (hereafter referred to as
``part 98''), generally and 40 CFR part 98, subpart W (hereafter
referred to as ``subpart W'') in particular. This section also
discusses the EPA's legal authority to make confidentiality
determinations for new or revised data elements corresponding to these
amendments or for existing data elements for which the EPA is
finalizing a new determination. Section II. of this preamble describes
the types of amendments included in this final rulemaking and includes
the rationale for each type of change. Section III. of this preamble
contains detailed information on the revisions to 40 CFR part 98,
subpart A (General Provisions), subpart C (General Stationary Fuel
Combustion Sources) and subpart W. Section IV. of this preamble
explains the effective date of the final revisions and how the
revisions are required to be implemented in reporting year (RY) 2024
and RY2025 reports. Section V. of this preamble discusses the final
confidentiality determinations for new or substantially revised (i.e.,
requiring additional or different data to be reported) data reporting
elements, as well as for certain existing data elements for which the
EPA is finalizing a new determination. Section VI. of this preamble
discusses the impacts of the amendments. Finally, section VII. of this
preamble describes the statutory and Executive Order requirements
applicable to this action.
B. Executive Summary
In August 2022, Congress passed, and President Biden signed, the
Inflation Reduction Act of 2022 (IRA) into law. Section 60113 of the
IRA amended the CAA by adding section 136, ``Methane Emissions and
Waste Reduction Incentive Program for Petroleum and Natural Gas
Systems.'' CAA section 136(c), ``Waste Emissions Charge,'' directs the
Administrator to impose and collect a charge on methane
(CH4) emissions that exceed statutorily specified waste
emissions thresholds from owners or operators of applicable facilities
that report more than 25,000 metric tons carbon dioxide equivalent
(mtCO2e) pursuant to the Greenhouse Gas Reporting Rule's
requirements for the petroleum and natural gas systems source category
(codified as subpart W in the EPA's Greenhouse Gas Reporting Rule
regulations). Further, CAA section 136(h) requires that the EPA shall,
within two years after the date of enactment of section 60113 of the
IRA, revise the requirements of subpart W to ensure the reporting under
subpart W (and corresponding waste emissions charges under CAA section
136) is based on empirical data, accurately reflects the total
CH4 emissions (and waste emissions) from the applicable
facilities, and allow owners and operators of applicable facilities to
submit empirical emissions data, in a manner to be prescribed by the
Administrator, to demonstrate the extent to which a charge is owed
under CAA section 136.
On August 1, 2023, the EPA proposed revisions to 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 in the 2023
Subpart W Proposal. The EPA proposed revisions to include reporting of
additional emissions or emissions sources to address potential gaps in
the total CH4 emissions reported by facilities to subpart W.
The EPA also proposed several revisions to add new or revise existing
calculation methodologies to improve the accuracy of reported
emissions, incorporate additional empirical data and to 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 future implementation of CAA section 136, as directed by CAA
section 136(h). For example, the EPA proposed new calculation
methodologies for equipment leaks and natural gas pneumatic devices to
allow for the use of direct measurement. The EPA also proposed several
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. For example,
the EPA proposed to disaggregate reporting requirements within the
Onshore Petroleum and Natural Gas Production and Onshore Petroleum and
Natural Gas Gathering and Boosting industry segments, with most
emissions and activity data for Onshore Petroleum and Natural Gas
Production and Onshore Petroleum and Natural Gas Gathering and Boosting
being disaggregated to at least the well-pad site and gathering and
boosting site level, respectively. The EPA also proposed other
technical amendments, corrections, and clarifications that would
improve understanding of the rule. These revisions primarily included
revisions of requirements to better reflect the EPA's intent or
editorial changes. The 2023 Subpart W Proposal also indicated that the
EPA would be undertaking one or more separate actions in the future to
implement the remainder of CAA section 136.
The EPA is finalizing revisions to part 98 included in the 2023
Subpart W Proposal, with some changes made after consideration of
public comments. The final amendments include new reporting
requirements with some revisions from what was proposed for other large
release events, produced water storage tanks, nitrogen removal units,
drilling mud degassing, and crankcase venting. The final amendments
expand the applicability of certain emission sources to new industry
segments as proposed. The final amendments also include new calculation
methods, with some revisions to those proposed, that provide
measurement or monitoring survey options, including for the calculation
of emissions from equipment leaks, combustion slip, crankcase venting,
associated gas, compressors, natural gas pneumatic devices, and
equipment leaks from components at transmission company interconnect
metering and regulating stations, to allow reporters to use appropriate
empirical data for these emission sources as an alternative to
population emission factors. We are also revising calculation methods,
with some revisions based on comments received, to improve the accuracy
or clarity of the existing calculation methods. This action also
finalizes confidentiality determinations for the reporting of data
elements added or substantially revised in these final amendments, and
for certain existing data elements for which no confidentiality
determination has been made previously or for which the EPA proposed to
revise the existing determination.
In some cases, and as further described in section III. of this
preamble, the EPA is not taking final action in this final rule on
certain proposed revisions included in the 2023 Subpart W Proposal. For
example, after review of comments received in response to the proposed
requirements for reporters in the Onshore Petroleum and Natural Gas
Production, Natural Gas Distribution, Onshore Petroleum and Natural Gas
Gathering and Boosting, and Onshore Natural Gas Transmission Pipeline
industry segments that have ownership changes in subpart A, the EPA is
not taking action at this time on the revisions to subpart A regarding
responsibilities for revisions to reports submitted in the years before
the ownership transactions. In consideration of the relationship
between revisions to annual reports for prior years and implementation
requirements for CAA section 136(c)
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proposed on January 26, 2024 (89 FR 5318) (hereafter referred to as the
``2024 WEC Proposal''), the EPA intends to consider those proposed
revisions in coordination with the development of the WEC final rule
and take action, if finalized, on these requirements at the same time.
In some cases, we are not taking final action at this time on certain
revisions to the calculation or monitoring methodologies that would
have revised how data are collected. For example, after review and
consideration of the comments received in response to the proposed
requirements for flares, we are not finalizing requirements to use
continuous flow monitors or continuous parametric monitoring and
continuous composition analyzers or quarterly sampling to determine
flow and composition, respectively, of gas routed to flares. In several
cases, we are also not taking final action at this time on proposed
revisions to add reporting requirements. For example, we are not
finalizing certain proposed reporting requirements for other large
release events when the reporter receives a third-party notification
because all Super-Emitter Program notifications will come from the EPA
and the EPA will already have the information proposed to be reported.
Some of the final amendments, particularly those that allow
reporters to choose from additional calculation methodologies and
submit empirical emissions data will be effective immediately as
optional methodologies. These amendments will apply to reports
submitted by current reporters that are submitted in calendar year 2025
and subsequent years (i.e., starting with reports submitted for RY2024
by March 31, 2025). The remaining final amendments will become
effective on January 1, 2025. Those final revisions, which apply to
both existing and new reporters, will be first implemented for reports
prepared for RY2025 and submitted by March 31, 2026. Reporters who are
newly subject to the rule will be required to implement all
requirements to collect data, including any required monitoring and
recordkeeping, on January 1, 2025.
These final amendments are anticipated to result in an overall
increase in burden for part 98 reporters in cases where the amendments
expand current applicability, add or revise reporting requirements, or
require additional emissions data to be reported. The final revisions
will affect approximately 567 new reporters and 2,510 existing
reporters. The incremental implementation labor costs are $169.4
million per year over the next three years (RY2025 through RY2027), for
a total of $508.3 million for the three years. There is an additional
incremental annualized burden of $14.1 million for operation and
maintenance (O&M) costs in RY2025 and in each subsequent year (RY2026
and RY2027), which reflects changes to monitoring for 2,510 existing
reporters and the 567 additional reporters.
Labor costs increased from $41.4 million per year at proposal to
$169.4 million per year at final, based in part on consideration of
comments received on the estimated labor hours needed to comply with
these amendments at proposal. As detailed in section VI.A. of this
preamble and the Summary of Public Comments and Responses for 2024
Final Revisions and Confidentiality Determinations for Petroleum and
Natural Gas Systems under the Greenhouse Gas Reporting Rule, those
labor hour estimates have been revised, leading to higher labor costs.
C. Background on This Final Rule
This final action builds on previous part 98 rulemakings. The
Greenhouse Gas Reporting Rule was published in the Federal Register
(FR) on October 30, 2009 (74 FR 56260) (hereafter referred to as the
2009 Final Rule). The 2009 Final Rule became effective on December 29,
2009, and requires reporting of GHGs from various facilities and
suppliers, consistent with the 2008 Consolidated Appropriations Act.\1\
Although reporting requirements for petroleum and natural gas systems
were originally proposed to be part of part 98 (75 FR 16448, April 10,
2009), the final October 2009 rulemaking did not include the petroleum
and natural gas systems source category as one of the 29 source
categories for which reporting requirements were finalized. The EPA re-
proposed subpart W in 2010 (75 FR 18608; April 12, 2010), and a
subsequent final rulemaking was published on November 30, 2010, with
the requirements for the petroleum and natural gas systems source
category at 40 CFR part 98, subpart W (75 FR 74458) (hereafter referred
to as the ``2010 Final Rule''). Following promulgation, the EPA
finalized several technical and clarifying amendments to subpart W (76
FR 22825, April 25, 2011; 76 FR 53057, August 25, 2011; 76 FR 59533,
September 27, 2011; 76 FR 73866, November 29, 2011; 76 FR 80554,
December 23, 2011; 77 FR 48072, August 13, 2012; 77 FR 51477, August
24, 2012; 78 FR 25392, May 1, 2013; 78 FR 71904, November 29, 2013; 79
FR 63750, October 24, 2014; 79 FR 70352, November 25, 2014; 80 FR
64262, October 22, 2015; and 81 FR 86490, November 30, 2016). These
amendments generally added or revised requirements in subpart W,
including revisions that were intended to improve quality, clarity, and
consistency across the calculation, monitoring, and data reporting
requirements, and to finalize confidentiality and reporting
determinations for data elements reported under the subpart.
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\1\ Consolidated Appropriations Act, 2008, Public Law 110-161,
121 Stat. 1844, 2128.
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More recently, the EPA proposed amendments to subpart W on June 21,
2022 (87 FR 36920) (hereafter referred to as the ``2022 Proposed
Rule''), including technical amendments to improve the quality and
consistency of the data collected under the rule and resolve data gaps,
amendments to streamline and improve implementation, and revisions to
provide additional flexibility in the calculation methods and
monitoring requirements for some emission sources. The 2022 Proposed
Rule was developed prior to the enactment of the Inflation Reduction
Act, which was signed into law on August 16, 2022, and its direction in
CAA section 136(h) to revise subpart W. Consequently, in developing the
2023 Subpart W Proposal, the EPA considered the proposed amendments to
subpart W from the 2022 Proposed Rule as well as the concerns and
information submitted by commenters in response to that proposal. In
the 2023 Subpart W Proposal, the EPA proposed to revise the subpart W
provisions, including both (1) updates to the proposed revisions to
subpart W that were in the 2022 Proposed Rule as well as (2) additional
proposed revisions to comply with CAA section 136(h). The preamble to
the 2023 Subpart W Proposal explained that the EPA did not intend to
finalize the revisions to subpart W that were proposed in the 2022
Proposed Rule and that the final amendments to subpart W would include
consideration of public comments on the 2023 Subpart W Proposal.
Additionally, the EPA opened a non-regulatory docket on November 4,
2022, and issued a Request for Information (RFI) seeking public input
to inform program design related to CAA section 136.\2\ As part of this
request, the EPA sought input on revisions that should be considered
related to subpart W. The comment period closed on January 18, 2023.
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\2\ Docket ID No. EPA-HQ-OAR-2022-0875.
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The EPA is finalizing amendments and confidentiality determinations
in this action, with certain changes from
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the 2023 Subpart W Proposal following consideration of comments
submitted and based on the EPA's updated assessment. The revisions
reflect the EPA's efforts to improve calculation, monitoring, and
reporting of greenhouse gas data for petroleum and natural gas systems
facilities and to ensure that reporting is based on empirical data,
accurately reflects total methane emissions and waste emissions from
applicable facilities, and allows owners and operators of applicable
facilities to submit empirical emissions data that appropriately
demonstrate the extent to which a charge is owed under the Waste
Emissions Charge. Responses to major comments submitted on the proposed
amendments from the 2023 Subpart W Proposal considered in the
development of this final rule can be found in section III. of this
preamble. Documentation of all comments received as well as the EPA's
responses can be found in the document Summary of Public Comments and
Responses for 2024 Final Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems under the Greenhouse Gas
Reporting Rule, available in the docket to this rulemaking (Docket ID.
No. EPA-HQ-OAR-2023-0234).
While this final rule complies with and is consistent with
directives in CAA section 136(h), this final rule does not address
implementation of other portions of CAA section 136 (section 60113 of
the Inflation Reduction Act), ``Methane Emissions and Waste Reduction
Incentive Program for Petroleum and Natural Gas Systems.'' The EPA
noted in the preamble to the 2023 Subpart W Proposal that we intend to
issue one or more separate actions to implement other requirements of
CAA section 136, which could include revisions to certain requirements
of subpart W for implementation purposes. Subsequently, the EPA
published the 2024 WEC Proposal to implement CAA section 136(c),
``Waste Emissions Charge,'' or ``WEC,'' on January 26, 2024 (89 FR
5318).\3\
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\3\ CAA section 136(c), ``Waste Emissions Charge,'' directs the
Administrator to impose and collect a charge on methane
(CH4) emissions that exceed statutorily specified waste
emissions thresholds from an owner or operator of an applicable
facility that reports more than 25,000 metric tons carbon dioxide
equivalent pursuant to the Greenhouse Gas Reporting Rule's
requirements for the petroleum and natural gas systems source
category (codified as subpart W in the EPA's Greenhouse Gas
Reporting Rule regulations).
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D. Legal Authority
The EPA is finalizing these rule amendments under its existing CAA
authority provided in CAA section 114 and under its newly established
authority provided in CAA section 136, as applicable. As noted in the
preamble to the proposed rule for this rulemaking and in the preamble
to the 2009 Final Rule (74 FR 56264, October 30, 2009), the EPA has
consistently applied its authority under CAA section 114(a)(1) for over
a decade to require the information proposed to be gathered by this
rule because such data would inform and are relevant to the EPA's
carrying out of a variety of CAA provisions. Thus, when promulgating
amendments to the Greenhouse Gas Reporting Rule (40 CFR part 98), the
EPA has assessed the reasonableness of requiring the information to be
provided and explained how the data are relevant to the EPA's ability
to carry out the provisions of the CAA. See the preambles to the
proposed Greenhouse Gas Reporting Rule (74 FR 16448, April 10, 2009)
and the 2009 Final Rule for further information. Additionally, in
enacting CAA section 136, Congress implicitly recognized the EPA's
appropriate use of CAA authority in promulgating the GHGRP. As noted in
section I.B. of this preamble, the provisions of CAA section 136
reference and are in part based on the Greenhouse Gas Reporting Rule
requirements under subpart W for the petroleum and natural gas systems
source category and require further revisions to subpart W for purposes
of supporting implementation of section 136. Under CAA section 136(h),
Congress directed the Administrator to revise the requirements of
subpart W to ensure that reporting of CH4 emissions under
subpart W (and corresponding waste emissions charges under CAA section
136) is based on empirical data, accurately reflects the total
CH4 emissions (and waste emissions) from applicable
facilities, and allows owners and operators to submit empirical
emissions data, in a manner prescribed by the Administrator, to
demonstrate the extent to which a charge is owed under CAA section 136.
Under CAA section 136, an ``applicable facility'' is a facility within
nine of the ten industry segments subject to subpart W, as currently
defined in 40 CFR 98.230 (excluding natural gas distribution). The
revisions being finalized are consistent with these directives,
ensuring that (1) reporting of methane emissions under subpart W are
based on empirical data, (2) accurately reflect total methane emissions
(and waste emissions) and (3) allow owners and operators to submit
appropriate empirical data. The EPA appropriately applied its authority
in this rulemaking in a manner consistent with CAA section 114 and the
directives under CAA section 136. See section II. of this preamble for
discussion of the rationale for these revisions, which includes that
they can be used to support carrying out a range of future climate
change policies and regulations under the CAA, including but not
limited to information relevant to carrying out CAA section 136,
provisions involving research, evaluating and setting standards,
endangerment determinations, or informing EPA non-regulatory programs
under the CAA, and see also section III. of this preamble and the
document Summary of Public Comments and Responses for 2024 Final
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems under the Greenhouse Gas Reporting Rule, available in the
docket to this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234), for
further detail on the revisions and their supporting rationale.
The Administrator has determined that this action is subject to the
provisions of section 307(d) of the CAA (see also section VII.M. of
this preamble). Section 307(d) contains a set of procedures relating to
the issuance and review of certain CAA rules.
In addition, pursuant to sections 114, 301, and 307 of the CAA, the
EPA is publishing final confidentiality determinations for the new or
substantially revised data elements required by these amendments.
Section 114(c) requires that the EPA make information obtained under
section 114 available to the public, except for information (excluding
emission data) that qualifies for confidential treatment.
E. Relationship to Other Clean Air Act Section 136 Actions
The IRA adds authorities under CAA section 136 to reduce
CH4 emissions from the oil and gas sector. It accomplishes
this in multiple ways. First, it provides incentives for CH4
mitigation and monitoring. Second, it establishes a waste emissions
charge for applicable facilities that exceed statutorily specified
thresholds that vary by industry segment and are determined by the
amount of natural gas or oil sent to sale. Third, CAA section 136(h)
requires the EPA to revise subpart W. The first and second listed
aspects of CAA section 136 are outside the scope of this rulemaking.
CAA section 136 provides $1.55 billion in incentives for
CH4 mitigation and monitoring, including through grants,
rebates, contracts, loans, and other activities. Of these funds, at
least $700 million is allocated to activities at
[[Page 42067]]
marginal conventional wells. There are several potential uses of funds.
Use of funds can include financial and technical assistance to owners
and operators of applicable facilities to prepare and submit GHG
reports under subpart W. Financial assistance can also be provided for
CH4 emissions monitoring authorized under CAA section 103
subsections (a) through (c). Additionally, financial and technical
assistance can be provided to: reduce CH4 and other GHG
emissions from petroleum and natural gas systems, including to mitigate
legacy air pollution from petroleum and natural gas systems; improve
climate resilience of communities and petroleum and natural gas
systems; improve and deploy industrial equipment and processes that
reduce CH4 and other GHG emissions and waste; support
innovation in reducing CH4 and other GHG emissions and waste
from petroleum and natural gas systems; permanently shut in and plug
wells on non-Federal land; and mitigate health effects of
CH4 and other GHG emissions and legacy air pollution from
petroleum and natural gas systems in low-income and disadvantaged
communities, and support environmental restoration.
The EPA has partnered with the Department of Energy (DOE) to
administer financial assistance under the Methane Emission Reduction
Program. In 2023, DOE announced and conditionally awarded $350 million
in funds to fourteen states to measure and reduce methane emissions
from low-producing conventional wells.\4\ In February 2024, the EPA and
DOE announced intent to open a competitive funding opportunity to a
broader range of applicants to reduce and monitor emissions from the
oil and gas industry.\5\
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\4\ U.S. Environmental Protection Agency. (2023, December 15).
Biden-Harris Administration Announces $350 Million to 14 States to
Reduce Methane Emissions from Oil and Gas Sector as Part of
Investing in America Agenda [Press Release]. https://www.epa.gov/newsreleases/biden-harris-administration-announces-350-million-14-states-reduce-methane-emissions. Available in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
\5\ U.S. Environmental Protection Agency. (2024, February 9).
EPA and DOE announce intent to fund projects to reduce methane
emissions from the oil and natural gas sectors as part of President
Biden's Investing in America agenda [Press Release]. https://www.epa.gov/newsreleases/epa-and-doe-announce-intent-fund-projects-reduce-methane-emissions-oil-and-natural-gas. Available in the
docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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The EPA and DOE are moving expeditiously to implement the
incentives for CH4 mitigation and monitoring and anticipate
making announcements regarding next steps; however, as noted, those
steps are outside the scope of this rulemaking. As relevant data become
available from the funded activities, the EPA will consider how they
can be used to improve reporting under subpart W.
CAA section 136(c) provides that the Administrator shall impose and
collect a charge on CH4 emissions that exceed an applicable
waste emissions threshold under CAA section 136(f) from an owner or
operator of an applicable facility that reports more than 25,000
mtCO2e per year pursuant to subpart W. CAA section 136
provides various flexibilities and exemptions relating to the waste
emissions charge. The EPA proposed to add 40 CFR part 99 to implement
the WEC in the 2024 WEC Proposal and has provided an opportunity for
public comment on that proposal; therefore, as noted, implementation of
the WEC is outside the scope of this rulemaking.
As noted earlier, CAA section 136(h) requires revisions to subpart
W. The purpose of this final action is to meet directives set forth in
CAA section 136(h) and to amend certain requirements that apply to the
general provisions, general stationary fuel combustion, and petroleum
and natural gas systems source categories of the Greenhouse Gas
Reporting Rule to improve the calculation, monitoring, and reporting of
greenhouse gas data for petroleum and natural gas systems facilities
consistent with the EPA's authority.
F. Relationship to Clean Air Act Section 111
The EPA had also identified areas where additional revisions to
part 98 would better align subpart W requirements with recently
promulgated requirements in 40 CFR part 60 and part 62, allow
facilities to use a consistent method to demonstrate compliance with
multiple EPA programs (and thereby limit burden), and improve the
emission calculations reported under subpart W. On November 15, 2021
(86 FR 63110), the EPA proposed under CAA section 111(b) standards of
performance for certain new, reconstructed, and modified oil and
natural gas sources (40 CFR part 60, subpart OOOOb) (hereafter referred
to as ``NSPS OOOOb''), as well as emissions guidelines under CAA
section 111(d) for certain existing oil and natural gas sources (40 CFR
part 60, subpart OOOOc) (hereafter referred to as ``EG OOOOc'') (the
sources affected by these two proposed subparts are collectively
referred to in this preamble as ``affected sources''). On December 6,
2022, the EPA issued a supplemental proposal to update, strengthen and
expand the standards proposed on November 15, 2021 (87 FR 74702). On
March 8, 2024, the final NSPS OOOOb and EG OOOOc rule published in the
Federal Register (89 FR 16820). While the standards in NSPS OOOOb will
directly apply to new, reconstructed, and modified sources, the final
EG OOOOc does not impose binding requirements directly on sources;
rather it contains guidelines, including presumptive standards, for
states to follow in developing, submitting, and implementing plans to
establish standards of performance to limit GHGs (in the form of
CH4 limitations) from existing oil and gas sources within
their own states. If a state does not submit a plan to the EPA for
approval in response to the final emission guidelines, or if the EPA
disapproves a state's plan, then the EPA must establish a Federal plan.
In addition, a Federal plan could apply to sources located on Tribal
lands where the tribe does not request approval to develop a tribal
implementation plan similar to a state plan. Once the Administrator
approves a state plan under CAA section 111(d), the plan is codified in
40 CFR part 62 (Approval and Promulgation of State Plans for Designated
Facilities and Pollutants) within the relevant subpart for that state.
40 CFR part 62 also includes all Federal plans promulgated pursuant to
CAA section 111(d). Therefore, rather than referencing the presumptive
standards in EG OOOOc, which do not directly apply to sources, the
final amendments to subpart W reference 40 CFR part 62.
We are finalizing revisions to certain requirements in subpart W
relative to the requirements finalized for NSPS OOOOb and the
presumptive standards in EG OOOOc (which will inform the standards to
be developed and codified at 40 CFR part 62). The final amendments in
this rule will allow facilities to use a consistent method to
demonstrate compliance with multiple EPA programs. These final
standards will limit burden for subpart W facilities with affected
sources that are also required to comply with the NSPS OOOOb or a state
or Federal plan in 40 CFR part 62 implementing EG OOOOc by allowing
them to use data derived from the implementation of the NSPS OOOOb to
calculate emissions for the GHGRP rather than requiring the use of
different monitoring methods.
II. Overview and Rationale for Final Amendments to 40 CFR Part 98,
Subpart W
As discussed in section I. of this preamble, in August 2022,
Congress
[[Page 42068]]
passed, and President Biden signed, the IRA into law. Section 60113 of
the IRA amended the CAA by adding section 136, ``Methane Emissions and
Waste Reduction Incentive Program for Petroleum and Natural Gas
Systems.'' CAA section 136(h) requires that the EPA shall, within two
years of the enactment of that section of the IRA, revise the
requirements of subpart W to ensure the reporting under that subpart
and calculation of charges under CAA section 136(e) and (f) are based
on empirical data, accurately reflect the total CH4
emissions and waste emissions from the applicable facilities, and allow
owners and operators of applicable facilities to submit empirical
emissions data, in a manner prescribed by the Administrator, to
demonstrate the extent to which a charge is owed. CAA section 136(d)
defines the term ``applicable facility'' as a facility within the
following industry segments as defined in subpart W: offshore petroleum
and natural gas production, onshore petroleum and natural gas
production, onshore natural gas processing, onshore gas transmission
compression, underground natural gas storage, liquefied natural gas
storage, liquefied natural gas import and export equipment, onshore
petroleum and natural gas gathering and boosting, and onshore natural
gas transmission pipeline.
Empirical data can be defined as data that are collected by
observation and experiment. There are many forms of empirical data that
can be used to quantify GHG emissions. For purposes of this action, the
EPA interprets empirical data to mean data that are collected by
conducting observations and experiments that could be used to
accurately calculate emissions at a facility, including direct
emissions measurements, monitoring of CH4 emissions (e.g.,
leak surveys) or measurement of associated parameters (e.g., flow rate,
pressure), and published data. The EPA reviewed available empirical
data methods for accuracy and appropriateness for calculating annual
unit or facility-level GHG emissions. The review included both the
evaluation of technologies and methodologies already incorporated in
subpart W for measuring and reporting annual source- and facility-level
GHG emissions and the evaluation of the accuracy of potential
alternative technologies and methodologies, with a focus on
CH4 emissions due to the directive in CAA section 136(h).
The EPA also reviewed technologies and methodologies suggested by
commenters during the public comment period for the 2023 Subpart W
Proposal.
Currently, subpart W specifies emission source types to be reported
for each industry segment and provides methodologies to calculate
emissions from each source type, which are then summed to generate the
total subpart W emissions for the facility. Current calculation methods
can be grouped into five categories: (1) direct emissions measurement;
(2) combination of measurement and engineering calculations; (3)
engineering calculations; (4) leak detection and use of a leaker
emission factor; and (5) population count and population emission
factors. Subpart W emission factors (both population and leaker
emission factors) include both those developed from published empirical
data and those developed from site-specific data collected by the
reporting facility. The EPA developed the current subpart W monitoring
and reporting requirements to use the most appropriate monitoring and
calculation methods, considering both the accuracy of the emissions
calculated by the proposed method and the size of the emission source
based on the methods and data available at the time of the applicable
rule promulgation. Considering the directives set forth in CAA section
136, the EPA re-evaluated the existing methodologies to determine if
they are likely to accurately reflect CH4 and waste
emissions at an individual facility, whether the existing methodologies
used empirical data, and whether the existing methodologies should be
modified or replaced or if additional optional calculation methods were
available and appropriate and should be added to meet CAA section 136
directives. Even in cases where the EPA determined that an existing
method that is not based on direct measurement or emission monitoring
provides a reasonably accurate calculation of emissions for a facility,
we also reviewed whether an appropriate direct emission measurement or
emission monitoring method could be added to subpart W, if one was not
already available, to give owners and operators the opportunity to
submit empirical data. For example, intermittent bleed pneumatic
devices are designed to vent during actuation only, but these devices
are known to often malfunction and operate incorrectly, which causes
them to release gas to the atmosphere when idle, leading to high degree
of variance in emissions from pneumatic devices between facilities (see
the technical support document Greenhouse Gas Reporting Rule: Technical
Support for Revisions and Confidentiality Determinations for Data
Elements Under the Greenhouse Gas Reporting Rule; Final Rule--Petroleum
and Natural Gas Systems, hereafter referred to as the ``final subpart W
TSD,'' available in the docket for this rulemaking, Docket ID. No. EPA-
HQ-OAR-2023-0234, for more information). For this example, the final
amendments add several new optional calculation methods to allow
reporters to account for the variability. The EPA also evaluated
whether there were gaps in the emission source types reporting
CH4 emissions under subpart W and whether there were
methodologies available to calculate those emissions.
The final amendments include:
Revisions to expand reporting to include new emission
sources, in order to accurately reflect total CH4 emissions
reported to the GHGRP.
Revisions to add emissions calculation methodologies to
expand options to allow owners and operators to submit empirical
emissions data and improve the accuracy of reported emission data,
including to expand options to allow owners and operators to submit
empirical emissions data where the EPA determined appropriate methods
were available.
Revisions to refine existing emissions calculation
methodologies to reflect an improved understanding of emissions, to
incorporate additional empirical data or to incorporate more recent
research on GHG emissions to improve the accuracy of reported emission
data.
The EPA has also identified additional areas where revisions to
part 98 will improve the EPA's ability to verify the accuracy of
reported emissions and improve data transparency and alignment with
other EPA programs and regulations. The EPA also identified areas where
additional data or revised data elements may be necessary for future
implementation of the Waste Emissions Charge under CAA section 136. The
final revisions include:
Revisions to report emissions and certain associated data
from emission sources at facilities in the Onshore Petroleum and
Natural Gas Production and Onshore Petroleum and Natural Gas Gathering
and Boosting industry segments at the site level or well level instead
of at the basin level, sub-basin level, or county level.
Addition of data elements related to emissions from
plugged wells.
Addition or clarification of throughput-related data
elements for subpart W industry segments.
Revisions to data elements or recordkeeping where the
current
[[Page 42069]]
requirements are redundant or alternative data are more appropriate for
verification of emission data.
Revisions that provide additional information for
reporters to better or more fully understand their compliance
obligations, revisions that emphasize the EPA's intent for requirements
that reporters appear to have previously misinterpreted to ensure that
accurate data are being collected, and editorial corrections or
harmonizing changes that will improve the public's understanding of the
rule.
Sections II.A. through II.D. of this preamble describe the above
changes in more detail and provide the EPA's rationale for the changes
included in each category. Additional details for the specific
amendments for each subpart are included in section III. of this
preamble.
A. Revisions To Address Potential Gaps in Reporting of Emissions Data
for Specific Sectors
We are finalizing several amendments to include reporting of
additional emissions or emissions sources to address potential gaps in
the total CH4 emissions reported per facility to subpart W.
These final amendments ensure that the reporting under subpart W
accurately reflects the total CH4 emissions and waste
emissions from applicable facilities, as directed by CAA section
136(h). In particular, based on recent analyses such as those conducted
for the annual Inventory of U.S. Greenhouse Gas Emissions and Sinks
(U.S. GHG Inventory), and data newly available from atmospheric
observations, we have become aware of potentially significant sources
of emissions for which there are no current emission estimation methods
or reporting requirements within part 98. For subpart W, we are
finalizing the addition of calculation methodologies and requirements
to report GHG emissions for several additional sources. We are adding a
new emissions source, referred to as ``other large release events,'' to
capture abnormal emission events that are not accurately accounted for
using existing methods in subpart W. This additional source covers
events such as storage wellhead leaks, well blowouts,\6\ and other
large, atypical release events and will apply to all types of
facilities subject to subpart W. Reporters will calculate GHG emissions
using measurement data or engineering estimates of the amount of gas
released and using measurement data, if available, or process knowledge
(best available data) to estimate the composition of the released gas.
We are also finalizing the addition of calculation methodologies and
requirements to report GHG emissions for several other new emission
sources, including nitrogen removal units, produced water tanks, mud
degassing, and crankcase venting. None of these sources are currently
accounted for in subpart W, and the EPA is adding them because they are
likely to have a meaningful impact on reported total facility
CH4 emissions. We are also finalizing revisions to the
existing methodologies and adding new measurement-based methodologies,
consistent with section II.B. of this preamble, for determining
combustion emissions from RICE and GT to account for combustion slip,
which is not currently accounted for under the existing calculation
methodologies for combustion emissions. We are also finalizing
requirements to report existing emission sources for certain subpart W
industry segments under additional industry segments. For example, we
are requiring liquefied natural gas (LNG) import/export facilities to
begin calculating and reporting emissions from acid gas removal unit
(AGR) vents. Additional details of these types of final changes may be
found in section III. of this preamble.
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\6\ We are finalizing as proposed the provision to define a well
blowout in 40 CFR 98.238 as a complete loss of well control for a
long duration of time resulting in an emissions release.
---------------------------------------------------------------------------
B. Revisions To Add New Emissions Calculation Methodologies or Improve
Existing Emissions Calculation Methodologies
We are finalizing several revisions to add new or revise existing
calculation methodologies to improve the accuracy of emissions data
reported to the GHGRP, incorporate additional empirical data, and to
allow owners and operators of applicable facilities to submit empirical
emissions data that appropriately demonstrate the extent to which a
charge is owed in future implementation of CAA section 136, as directed
by CAA section 136(h). Subpart W specifies emission source types to be
reported for each industry segment and provides methodologies to
calculate emissions from each source type, which are then summed to
generate the total subpart W emissions for the facility. Considering
the directives set forth in CAA section 136, the EPA re-evaluated the
existing methodologies for each source to determine if they are likely
to accurately reflect CH4 and waste emissions at an
individual facility, whether the existing methodologies used empirical
data (e.g., direct emissions measurements or monitoring of
CH4 emissions; measurement of associated parameters), and
whether the existing methodologies should be modified or replaced or if
new optional calculation methodologies should be added to meet CAA
section 136 directives. A summary list of the final emissions sources
to be reported with the corresponding monitoring and emissions
calculation methods is available in the final subpart W TSD, available
in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
Many sources in subpart W already have or require calculation
methodologies that use direct emission measurement, including AGR
vents, large reciprocating compressor rod packing vents, large
compressor blowdown vent valve leaks, and large compressor blowdown
vent (unit isolation valve leaks), the latter three when leakage is
detected via screening. In these final amendments, the EPA is
finalizing the addition of new calculation methodologies to allow for
the use of direct measurement, including for the calculation of
emissions from equipment leaks, combustion slip, crankcase venting,
associated gas, compressors, natural gas pneumatic devices, and
equipment leaks from components at transmission company interconnect
metering and regulating stations. The EPA is also finalizing new
calculation methodologies to allow for the development of facility-
specific emission factors for equipment leaks based on data collected
from direct measurement at the facility. The EPA is also finalizing the
option to use advanced technologies to measure data that are inputs to
emissions calculations for flares and completions and workovers with
hydraulic fracturing. These final amendments will provide owners and
operators the opportunity to submit appropriate empirical data in their
subpart W annual reports. We also reviewed whether some optional
calculation methodologies would be appropriate to allow in RY2024, so
that owners and operators would have the opportunity to submit
appropriate empirical data in line with existing subpart W. As
discussed in section IV. of this preamble, we are finalizing the
addition of a number of new optional calculation methodologies that are
relevant to existing subpart W sources effective July 15, 2024.
Similar to the 2016 amendments to align subpart W requirements with
certain requirements in 40 CFR part 60, subpart OOOOa (hereafter
referred to as ``NSPS OOOOa'') (81 FR 86500,
[[Page 42070]]
November 30, 2016), we are also finalizing revisions to certain
requirements in subpart W relative to the requirements finalized for
NSPS OOOOb and the presumptive standards in EG OOOOc (which will inform
the standards to be developed and codified at 40 CFR part 62). As in
the 2016 rule, the final amendments also allow facilities to use a
consistent method to demonstrate compliance with multiple EPA programs.
These final standards will limit burden for subpart W facilities with
affected sources that are also required to comply with the NSPS OOOOb
or a state or Federal plan in 40 CFR part 62 implementing EG OOOOc by
allowing them to use data derived from the implementation of the NSPS
OOOOb to calculate emissions for the GHGRP rather than requiring the
use of different monitoring methods. Consistent with that goal, the
final amendments to subpart W reference the final version of the
method(s) in the NSPS OOOOb and EG OOOOc. These amendments also improve
the emission calculations reported under the GHGRP by requiring the use
of facility-collected measurement or survey data to calculate emissions
where available and appropriate. Specifically, we are finalizing
amendments to the subpart W calculation methodologies for atmospheric
pressure storage tanks, flares, centrifugal and reciprocating
compressors, and equipment leak surveys related to the final NSPS OOOOb
and presumptive standards in EG OOOOc, and we are finalizing new
reporting requirements for ``other large release events'' as defined in
subpart W that reference the NSPS OOOOb and approved state plans or
applicable Federal plan in 40 CFR part 62. These final amendments are
described in sections III.B., N., O., and P. of this preamble; the
effective dates of these final amendments are discussed in section IV.
of this preamble. As reflected in section IV. of this preamble, the
provisions of these final amendments that reference the NSPS OOOOb and
approved state plans or applicable Federal plan in 40 CFR part 62 do
not apply to individual reporters unless and until 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. In
the meantime, reporters have the option to comply with the calculation
methodologies that are required for sources subject to NSPS OOOOb or 40
CFR part 62, or they may comply instead with the applicable provisions
of subpart W that apply to sources not subject to NSPS OOOOb or 40 CFR
part 62. For example, for flare sources, subpart W facilities have the
option to comply with the flare monitoring requirements in NSPS OOOOb
even if the source is not yet subject to or will not be subject to
those provisions. For the ``other large release events'' source
category, emissions from other large release events are required to be
calculated and reported starting in Reporting Year (RY) 2025; the
requirements to calculate and report these emissions are not dependent
on whether a source is subject to NSPS OOOOb or 40 CFR part 62. The
specific changes that we are finalizing, as described in this section,
are described in detail in section III. of this preamble.
We are also finalizing several revisions to modify calculation
equations to incorporate refinements to methodologies based on an
improved understanding of emission sources. In some cases, we have
become aware of discrepancies between assumptions in the current
emission estimation methods and the processes or activities conducted
at specific facilities, where the revisions will reduce reporter
errors. In other cases, we are revising the emissions estimation
methodologies to incorporate recent studies on GHG emissions or
formation that reflect updates to scientific understanding of GHG
emissions sources. The final amendments will improve the quality and
accuracy of the data collected under the GHGRP.
We are also finalizing revisions to several existing calculation
methodologies to incorporate empirical data obtained at the facility.
Emissions can be reliably calculated for sources such as atmospheric
storage tanks and glycol dehydrators using standard engineering first
principle methods such as those available in API 4697 E&P Tanks \7\ and
GRI-GLYCalcTM \8\ when based on actual operating conditions.
Using such software also addresses safety concerns that are associated
with direct emissions measurement from these sources in certain
circumstances. For example, sometimes the temperature of the emissions
stream for glycol dehydrator vent stacks is too high for operators to
safely measure emissions. Currently these methods in subpart W allow
for use of best available data for all inputs to the model. However,
the EPA has noted that in some cases, such as with reporting of
emissions from some dehydrators, the data used to calculate emissions
are not based on actual operating conditions but instead based on
``worst-case scenarios'' or other estimates. In these final amendments,
for large glycol dehydrators and AGRs, we are requiring that certain
input parameters be based on actual measurements at the unit level in
order to ensure that emissions calculations are based on actual
operating conditions and to improve the accuracy of the reported
emissions for these sources.
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\7\ E&P Tanks v3.0 software and the user guide (Publication
4697) formerly available from the American Petroleum Institute (API)
website.
\8\ GRI-GLYCalcTM software available from Gas
Technology Institute website (https://sales.gastechnology.org/)
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In order to improve the accuracy of the data collected under the
GHGRP, we are finalizing revisions to emission factors where improved
measurement data has become available or we have received additional
information from stakeholders. Some of the calculation methodologies
provided in the GHGRP rely on the use of emission factors that are
based on published empirical data. Default emission factors based on
representative empirical data can provide a reasonably accurate
estimate of facility-level emissions. The final rule includes revisions
to emission factors for a number of emission source types where we have
received or identified updated, representative measurement data.
We are finalizing updated emission factors for natural gas
pneumatic devices, equipment leaks from natural gas distribution
sources (including pipeline mains and services, below grade
transmission-distribution transfer stations, and below grade metering-
regulating stations) and equipment at onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and boosting
facilities, and compressors at onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and boosting
facilities in subpart W. The revised emission factors are more
representative of GHG emissions sources and will improve the overall
accuracy of the emission data collected under the GHGRP. Additional
details of these types of final revisions may be found in section III.
of this preamble.
As noted in section II.A. of this preamble, we are adding a new
emissions source, referred to as ``other large release events,'' to
capture abnormal emission events that are not accurately accounted for
using existing methods in subpart W. Under these provisions in this
final rule, the EPA is also finalizing the inclusion of emissions from
other large emissions events and super-emitters in the subpart W
reporting program. This addition will directly address the concerns
identified by a multitude of studies about the
[[Page 42071]]
contribution of super-emitters to total emissions and help to ensure
the completeness and accuracy of emissions reporting data. Advanced
measurement approaches that have demonstrated their ability to detect,
attribute the source at least to site-level, and accurately quantify
emission rates of such events are a central feature of the finalized
changes. Some advanced measurement approaches have a demonstrated
ability to provide data useful for quantifying emissions from very
large, distinct emission events, such as production well blowouts. In
the U.S. GHG Inventory, the EPA has already incorporated emissions
estimates developed from such approaches to calculate emissions from
well blowouts.\9\ In this final rule, we are requiring facilities to
consider notifications of super-emitter emissions event under the
super-emitter provisions of NSPS OOOO/OOOOa/OOOOb at 40 CFR 60.5371,
60.5371a, and 60.5371b or the applicable approved state plan or
applicable Federal plan and calculate the associated emissions when
they exceed the final threshold of 100 kg/hr CH4 if they are not
already appropriately accounted for under another source category in
subpart W. We expect that under the final methodology for other large
release events, data from some advanced measurement approaches,
including data derived from equipment leak and fugitive emissions
monitoring using advanced screening methods conducted under NSPS OOOOb
or the applicable approved state plan or applicable Federal plan in 40
CFR part 62, in combination with other empirical data, could be used by
reporters to calculate the total emissions from these events and/or
estimate duration of such an event.
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\9\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2020: Updates for Anomalous Events including Well Blowout
and Well Release Emissions. April 2022. Available at https://www.epa.gov/system/files/documents/2022-04/2022_ghgi_update_-_blowouts.pdf and in the docket for this rulemaking, Docket ID. No.
EPA-HQ-OAR-2023-0234.
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The EPA received numerous comments requesting that the EPA allow
for the use of advanced technologies to quantify emissions from other
emission sources in subpart W beyond ``other large release events.'' In
response, we reviewed advanced measurement approaches that utilize
information from satellite, aerial, drone, vehicle, and stationary
platforms to detect and/or quantify methane emissions from petroleum
and natural gas systems at different spatial and temporal scales for
their potential use in estimating emissions of specific sources for the
purposes of subpart W reporting. Advanced technologies have been a
focus for research and emission monitoring strategies, and several
technologies have progressed in recent years to provide valuable CH4
emission data. The spatial and temporal resolution of emission
estimates varies widely, however, depending on the technology and
platform.
Two general categories of advanced technologies were evaluated for
their potential use in subpart W: remote sensing (e.g., satellite,
aerial) and continuous monitoring systems, which typically use gas
sensors and/or imaging coupled with proprietary algorithms to detect
emissions and/or provide emission rates. Remote sensing approaches
typically use aerial or satellite-deployed infrared spectroscopy to
survey areas for methane emission plumes. For remote sensing
technologies, the size of the area monitored is typically inversely
related to the detection levels. Satellite remote sensing technologies
are deployed at altitudes of 400 to 800 kilometers and currently have
CH4 detection limits of approximately 50 to 25,000 kilograms per hour
(kg/hr),\10\ and high altitude remote sensing (by airplane) measure at
altitudes of 168 to 12,000 meters (m) with current CH4 detection limits
of approximately 1 to 50 kg/hr.\11\ We find that existing remote
sensing approaches are suitable to supplement the other requirements
for periodic measurement and calculation of annual emissions for large
discrete events, as they are capable of having suitable detection
limits for the identification of the presence of large anomalous
events. However, our assessment at this time is that existing remote
sensing approaches currently are not able to appropriately estimate
annual emissions from other sources under subpart W. Most remote
sensing measurements are taken over limited durations (a few minutes to
a few hours) typically during the daylight hours and limited to times
when specific meteorological conditions exist (e.g., no cloud cover for
satellites; specific atmospheric stability and wind speed ranges for
aerial measurements). These direct measurement data taken at a
particular moment in time may not be representative of the annual CH4
emissions from the facility, given that many emissions are episodic. If
emissions are found during a limited duration sampling, that does not
necessarily mean they are present for the entire year. And if emissions
are not found during a limited duration sampling, that does not
necessarily mean significant emissions are not occurring at other
times. Extrapolating from limited measurements to an entire year
therefore creates risk of either over or under counting actual
emissions.
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\10\ See GHGSat. GHGSat Media Kit. (2021). Available at https://www.ghgsat.com/upload/misc/GHGSAT_MEDIAKIT_2021.pdf; Pandey, S., et
al. ``Satellite observations reveal extreme methane leakage from a
natural gas well blowout.'' Proceedings of the National Academy of
Sciences, Vol. 116, no. 52. Pp. 26376-26381, December 16, 2019,
available at https://doi.org/10.1073/pnas.1908712116; Jacob, D.J.,
et al. ``Quantifying methane emissions from the global scale down to
point sources using satellite observations of atmospheric methane.''
Atmospheric Chemistry and Physics, Vol. 22, Issue 14, pp. 9617-9646,
July 29, 2022, available at https://doi.org/10.5194/acp-22-9617-2022; Anderson, V., et al. ``Technological opportunities for sensing
of the health effects of weather and climate change: a state-of-the-
art-review.'' International Journal of Biometeorology, Vol. 65,
Issue 6, pp. 779-803, January 11, 2021, available at https://doi.org/10.1007/s00484-020-02063-z. The documents are also available
in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-
0234.
\11\ See Conrad, B.M., Tyner, D.R. & Johnson, M.R. ``Robust
probabilities of detection and quantification uncertainty for aerial
methane detection: Examples for three airborne technologies.''
Remote Sensing of Environment, Vol. 288, p. 113499, available at
https://doi.org/10.1016/j.rse.2023.113499. 2023; Duren, R.M., et al.
``California's methane super-emitters.'' Nature, Vol. 575, Issue
7781, pp. 180-184, available at https://doi.org/10.1038/s41586-019-1720-3. 2019; Thorpe, A.K., et al. ``Airborne DOAS retrievals of
methane, carbon dioxide, and water vapor concentrations at high
spatial resolution: application to AVIRIS-NG.'' Atmos. Meas. Tech.,
10, 3833-3850, available at https://doi.org/10.5194/amt-10-3833-2017. 2017; Staebell, C., et al. ``Spectral calibration of the
MethaneAIR instrument.'' Atmospheric Measurement Techniques, Vol.
14, Issue 5, pp. 3737-3753, available at https://doi.org/10.5194/amt-14-3737-2021. 2021. The documents are also available in the
docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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Additionally, while advanced measurement methods based on remote
sensing, including satellite and aerial methods, have proven their
ability to identify and measure large emissions events, their detection
limits may be too high to detect emissions from sources with relatively
low emission rates.\12\ The data provided by some of these technologies
are at large spatial scales, with limited ability to disaggregate to
the facility- or emission source-level and have high minimum detection
limits. So while these technologies can provide very useful information
about emissions during snapshots in time, and thus help to greatly
improve the completeness and accuracy of emission reporting, with the
current state of these technologies they generally cannot by themselves
estimate annual emissions.
[[Page 42072]]
Therefore, this rule finalizes allowing the use of these advanced
measurement methods based on remote sensing to supplement the other
requirements for periodic measurement and calculation of annual
emissions for other large release events, as described in section
III.B. of this preamble.
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\12\ Duren, et al. ``California's methane super-emitters.''
Nature, Vol. 575, Issue 7781, pp. 180-184, 2019. Available at
https://doi.org/10.1038/s41586-019-1720-3 and in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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Continuous monitoring systems, which typically use one or more
stationary sensors and/or imagers located on or near sites to
frequently detect and/or quantify anomalous emissions, can have
significant value for detecting anomalous emissions but are less
suitable for the annual quantification that is required for purposes of
the Greenhouse Gas Reporting Program and satisfying Congress's
directive in the Inflation Reduction Act. Although these systems may
continuously collect methane concentration data, emissions data from
monitored sites are not typically continuous because methane emission
plumes may not reach sensors or visual images may not detect plumes
under certain meteorological and operational conditions. Recent studies
evaluating the performance of several continuous monitors have reported
that these systems can provide valuable data for detecting anomalous
emissions (and generally faster than survey methods) and determining
event duration, but typically have high uncertainty in quantifying
total emissions.\13\ Therefore, we determined that continuous
monitoring systems currently are not suitable for quantifying emissions
for subpart W reporting on their own but may provide data on the
duration of large release events. Further discussion of our review of
advanced technologies is available in the final subpart W TSD,
available in the docket for this rulemaking.
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\13\ See, e.g., Bell, C., et al. ``Performance of Continuous
Emission Monitoring Solutions under a Single-Blind Controlled
Testing Protocol.'' Environ. Sci. Technol. 2023, 57, 14, 5794-5805.
Published March 28, 2023. https://doi.org/10.1021/acs.est.2c09235.
Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2023-0234.
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Based on our review, we are finalizing the use of advanced
measurement data, including both remote sensing technologies and
continuous monitoring systems, to help identify and quantify super-
emitter and other large emissions events. Commenters also requested
that the EPA allow for the adoption of advanced technologies without
having to go through a new rulemaking process, similar to the
technology verification programs developed under the NSPS OOOOb and EG
OOOOc even though many commenters acknowledged that with the current
state of advanced technologies, it is not possible to accurately
quantify annual emissions at the individual source level, particularly
at low emission rates as would be needed to accurately quantify many
subpart W sources. However, for reasons discussed below, this final
rule does not include a general provision to incorporate the use of
advanced measurement approaches at this time except in certain cases,
such as large release events. It is worth noting that the NSPS OOOOb
and EG OOOOc (and the technologies that are verified under that
program), are focused on detecting leaks or identifying anomalous
emissions that exceed certain action levels, which is more
straightforward than accurately quantifying source emission rates over
annual time periods. Furthermore, the EPA is not aware of a
standardized protocol to accurately extrapolate from either continuous
or discrete remote sensing measurement data to an annual, facility-
level emission total. At this point in time, there are still many
outstanding research questions associated with how best to combine
advanced measurement data (sometimes called ``top-down'' methods) with
bottom-up methods in a way that avoids double counting of emissions,
including how frequently measurements would need to be conducted to be
considered reliable or representative of annual emissions for reporting
purposes, and what emissions simulation modeling would be necessary to
accurately estimate annual emissions. As described previously in this
section, the different types of measurement data have a wide range of
detection limits and spatial resolution, which makes converting point
estimates to an annual emission estimate as required by and necessary
for the purposes of the GHGRP subpart W difficult. Therefore, this
final rule does not include a general provision to incorporate the use
of advanced measurement approaches for sources at this time and instead
specifically allows its use in certain appropriate cases, including for
other large release events, due to the limitations described earlier in
this section.
The EPA notes that advanced measurement approaches are rapidly
evolving, and expects that these approaches will continue to improve
over time. Advanced measurement approaches are currently being used to
generate a range of valuable information on emissions sources in the
oil and natural gas sector and have great promise for playing a greater
role in subpart W emissions reporting as experience with using them to
quantify emissions grows. We will continue to closely monitor
developments in advanced monitoring technologies and measurement
approaches and engage with experts and stakeholders on how they can be
used in subpart W reporting.
As these measurement approaches continue to develop, the EPA will,
as appropriate, undertake notice-and-comment rulemaking to determine
under what circumstances these approaches can be used for subpart W
reporting of methane emissions, and how subpart W reporters can use
these approaches to quantify annual emissions based on advanced
technologies and the rapid evolution of such technologies. Given the
wide variety of advanced measurement approaches and the methodological
challenges described above, the EPA believes it is necessary to provide
adequate notice and opportunity for comment on the use of advanced
measurement approaches in order to incorporate such technologies into
subpart W. We believe that such an approach is consistent with the
historic implementation of the Greenhouse Gas Reporting Rule which has
been revised over time to incorporate the latest data, updated
scientific knowledge and additional measurement methods. In advance of
such a rulemaking, the EPA intends to solicit input on the use of
advanced measurement data and methods in subpart W through a request
for information, workshop or white paper. We further intend to evaluate
for potential future subpart W updates whether there are measurement
approaches that could be used to estimate annual emissions for any
source categories under subpart W or for facility-level emissions, what
level of accuracy should be required for such use, and whether the
development of standard protocols for estimating emissions from
advanced measurement (either by the EPA or third-party organizations)
could help inform this determination. We also intend to evaluate
whether there are other appropriate uses of this data for the purposes
of reporting under subpart W of the GHGRP, including for what types of
emission sources and emission events and what specific measurement
approaches use may be appropriate, especially in terms of spatial scale
and minimum detection limits. We will also continue to evaluate how
frequently measurements would need to be conducted to be considered
reliable or representative of annual emissions for reporting purposes.
[[Page 42073]]
C. Revisions to Reporting Requirements To Improve Verification and
Transparency of the Data Collected
The EPA is finalizing several revisions to existing reporting
requirements to collect data that will improve verification of reported
data and improve the transparency of the data collected. Data reported
under the GHGRP undergo comprehensive verification review. This process
identifies errors that result in the over- or under- statement of
emissions that are reported from individual facilities and leads to
their correction. As such, amendments that improve the verification
process are supportive of the directive under CAA section 136(h) to
ensure that reporting under subpart W accurately reflects total methane
emissions. Additionally, such revisions will better enable the EPA to
obtain data that is of sufficient quality and granularity that it can
be used to support a range of future climate change policies and
regulations under the CAA, including but not limited to information
relevant to carrying out CAA section 136, provisions involving
research, evaluating and setting standards, endangerment
determinations, or informing EPA non-regulatory programs under the CAA.
The final revisions include changes to the level of reporting of
aggregated emissions and activity data that will improve the process of
emissions verification and the transparency and granularity of the
data. For example, we are finalizing requirements for Onshore Petroleum
and Natural Gas Production and Onshore Petroleum and Natural Gas
Gathering and Boosting industry segment reporters to report emissions
and associated activity data at the site level or well level instead of
at the basin level, sub-basin level, or county level.
We are also finalizing additions or revisions to reporting
requirements to better characterize the emissions for several emission
sources. For example, we are collecting additional information from
facilities with liquids unloadings to differentiate between manual and
automated unloadings.
Other final revisions to the rule include changes that will better
align reporting with the calculation methods in the rule. For example,
we are finalizing revisions to reporting requirements related to
atmospheric pressure fixed roof storage tanks receiving hydrocarbon
liquids that follow the methodology specified in 40 CFR 98.233(j)(3)
and equation W-15. The current calculation methodology uses population
emission factors and the count of applicable separators, wells, or non-
separator equipment to determine the annual total volumetric GHG
emissions at standard conditions. The associated reporting requirements
in existing 40 CFR 98.236(j)(2)(i)(E) and (F) require reporters to
delineate the counts used in equation W-15. The current reporting
requirements are inadvertently inconsistent with the language used in
the calculation methodology and are seemingly not inclusive of all
equipment to be included. Therefore, we are revising the reporting
requirements to better align the requirement with the calculation
methodology and streamline the requirements for all facilities
reporting atmospheric storage tanks emissions using the methodology in
40 CFR 98.233(j)(3).
In some cases, we are finalizing the removal of duplicative
reporting elements within or across GHGRP subparts to reduce data
inconsistencies and reporting errors. For example, we are eliminating
duplicative reporting between subpart NN (Suppliers of Natural Gas and
Natural Gas Liquids) and subpart W where both subparts require similar
data elements to be reported to the electronic Greenhouse Gas Reporting
Tool (e-GGRT). For fractionators of natural gas liquids (NGLs), both
subpart W (under the Onshore Natural Gas Processing segment) and
subpart NN require reporting of the volume of natural gas received and
the volume of NGLs received. For Local Distribution Companies (LDCs),
both subpart W (under the Natural Gas Distribution segment) and subpart
NN require reporting of the volume of natural gas received, volume
placed into and out of storage each year, and volume transferred to
other LDCs or to a pipeline as well as some other duplicative data. The
final amendments limit the reporting of these data elements to
facilities that do not report under subpart NN, thus removing the
duplicative requirements from subpart W for facilities that report to
both subparts. These data elements are not the throughputs that are
proposed to be used for WEC calculations; see section III.U. of this
preamble and the 2024 WEC Proposal for more information on those
throughputs. This revision will improve the EPA's ability to verify the
reported data across subparts.
D. Technical Amendments, Clarifications, and Corrections
We are finalizing other technical amendments, corrections, and
clarifications that will improve understanding of the rule. These
revisions primarily include revisions of requirements to better reflect
the EPA's intent or editorial changes. Some of these changes result
from consideration of questions raised by reporters through the GHGRP
Help Desk or e-GGRT. In particular, we are finalizing amendments for
several source types that will emphasize the original intent of certain
rule requirements, such as reported data elements that have been
misinterpreted by reporters. In several cases, the misinterpretation of
these provisions may have resulted in reporting that is inconsistent
with the rule requirements. The final clarifications will increase the
likelihood that reporters will submit accurate reports the first time.
For example, the EPA is finalizing revisions to the definition of
variable ``Tt'' in existing equation W-1 (final equation W-1B) in 40
CFR 98.233 and the corresponding reporting requirements in final 40 CFR
98.236(b)(4)(ii)(D)(4), (b)(5)(i)(C)(2), and (b)(6)(ii) to use the term
``in service (i.e., supplied with natural gas)'' rather than
``operational'' or ``operating.'' This revision emphasizes the EPA's
intent that the average number of hours used in equation W-1 (final
equation W-1B) should be the number of hours that the devices of a
particular type are in service (i.e., the devices are receiving a
measurement signal and connected to a natural gas supply that is
capable of actuating a valve or other device as needed). These final
clarifications and corrections will also reduce the burden associated
with reporting, data verification, and EPA review. Additional details
of these types of final changes are discussed in section III. of this
preamble.
We are also finalizing revisions to applicability provisions for
certain industry segments and applicable calculation methods. For
example, we are revising the definition of the Onshore Natural Gas
Processing industry segment to remove the gas throughput threshold so
that the applicable industry segment and calculation methods are
defined from the beginning of the year. The current definition of the
Onshore Natural Gas Processing industry segment includes processing
plants that fractionate gas liquids and processing plants that do not
fractionate gas liquids but have an annual average throughput of 25
million standard cubic feet (MMscf) per day or greater. Processing
plants that do not fractionate gas liquids and have an annual average
throughput of less than 25 MMscf per day may be part of a facility in
the Onshore Petroleum and Natural Gas Gathering and Boosting
[[Page 42074]]
industry segment. Processing plants that do not fractionate gas liquids
and generally operate close to the 25 MMscf per day threshold do not
know until the end of the year whether they will be above or below the
threshold, so they must be prepared to report under whichever industry
segment is ultimately applicable. Therefore, as discussed in greater
detail in section III.A.3. of this preamble, we are revising the
Onshore Natural Gas Processing industry segment definition in 40 CFR
98.230(a)(3) to remove the 25 MMscf per day threshold and more closely
align subpart W with the definitions of natural gas processing in other
rules (e.g., NSPS OOOOa). This revision to the Onshore Natural Gas
Processing industry segment definition will better define whether a
processing plant is classified as an Onshore Natural Gas Processing
facility or as part of an Onshore Petroleum and Natural Gas Gathering
and Boosting facility, and the applicable segment will no longer have
the potential to change from one year to the next simply based on the
facility throughput.
Additional details of these types of final changes may be found in
section III. of this preamble.
Other minor changes being finalized include correction edits to fix
typos, minor clarifications such as adding a missing word, harmonizing
changes to match other final revisions, reordering of paragraphs so
that a larger number of paragraphs need not be renumbered, and others
as reflected in the redline regulatory text in the docket for this
rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
III. Final Amendments to Part 98 and Summary of Comments and Responses
This section summarizes the specific substantive final amendments
for subpart W (as well as subparts A and C), as generally described in
section II. of this preamble. Major changes to the final rule as
compared to the proposed revisions are identified in this section. The
summary of the amendments in each section is followed by a summary of
the major comments on those amendments and the EPA's responses to those
comments. The document Summary of Public Comments and Responses for
2024 Final Revisions and Confidentiality Determinations for Petroleum
and Natural Gas Systems under the Greenhouse Gas Reporting Rule,
available in the docket to this rulemaking (Docket ID. No. EPA-HQ-OAR-
2023-0234), contains the full text of all the comments on the 2023
Subpart W Proposal, including the major comments responded to in this
preamble. All final amendments, including minor corrections and
clarifications, are also reflected in the final redline regulatory text
in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-
0234).
Section III.A of this preamble describes amendments that affect
reporting responsibility or applicability. Sections III.B through III.U
of this preamble describe technical amendments that affect specific
source types or industry segments. Section III.V of this preamble lists
miscellaneous technical corrections and clarifications.
A. General and Applicability Amendments
1. Ownership Transfer
a. Summary of Final Amendments
We are finalizing amendments to specific provisions to subpart A
that will apply in lieu of existing 40 CFR 98.4(h) for changes in the
owner or operator of a facility in the four industry segments in
subpart W (Petroleum and Natural Gas Systems) that have unique
definitions of facility.\14\ The final provisions specify which owner
or operator is responsible for current and future reporting years'
reports following a change in owner or operator for specific industry
segments in subpart W, beginning with RY2025 reports. As described in
more detail in this section, the provisions vary based upon whether the
selling owner or operator will retain any emission sources, the number
of purchasing owner(s) or operator(s), and whether the purchasing
owner(s) or operator(s) already report to the GHGRP in the same
industry segment and basin or state (as applicable). These final
revisions are expected to improve data quality as described in section
II.C of this preamble by ensuring that the EPA receives a more complete
data set, and they are also expected to improve understanding of the
rule, as described in section II.D. of this preamble.
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\14\ Specifically the Onshore Petroleum and Natural Gas
Production, Natural Gas Distribution, Onshore Petroleum and Natural
Gas Gathering and Boosting, and Onshore Natural Gas Transmission
Pipeline industry segments.
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In this final rule, the EPA is not taking final action at this time
on the proposed amendments related to responsibility for revisions to
annual reports for reporting years prior to owner or operator changes
for specific industry segments in subpart W. In consideration of the
relationship between revisions to annual reports for prior years and
proposed implementation requirements in the 2024 WEC Proposal, the EPA
intends to consider those proposed revisions in coordination with the
2024 WEC rulemaking and take action, if finalized, on these
requirements at the same time.
As discussed in the 2023 Subpart W proposal, we expect that
transactions fall into one of four general categories, and we are
finalizing provisions that specify the current and future reporting
years' responsibilities for reporting for each of those general
categories. First, to address transactions where an entire facility is
sold to a single purchaser and the purchasing owner or operator does
not already report to the GHGRP in that industry segment (and basin or
state, as applicable), we are finalizing as proposed that the
facility's certificate of representation must be updated within 90 days
of the transaction to reflect the new owner or operator. We are
finalizing as proposed the requirement that the purchasing owner or
operator will be responsible for submitting the facility's annual
report for the entire reporting year in which the acquisition occurred
(i.e., the owner or operator as of December 31 will be responsible for
the report for that entire reporting year) and each reporting year
thereafter. In addition, because the definitions of facility for each
of these segments encompass all of the emission sources in a particular
geographic area (i.e., basin, state, or nation), the purchasing owner
or operator must include any other applicable emission sources already
owned by that purchasing owner or operator in the same geographic area
as part of the purchased facility beginning with the reporting year in
which the acquisition occurred. We proposed, but are not taking final
action at this time on, a requirement that the purchasing owner or
operator would also become responsible for responding to EPA questions
and making any necessary revisions to annual GHG reports for reporting
years prior to the reporting year in which the acquisition occurred. As
noted above, we intend to consider those proposed revisions in
coordination with the 2024 WEC rulemaking and take action on these
requirements, if finalized, at the same time.
Second, to address transactions where the entire facility is sold
to a single purchaser and the purchasing owner or operator already
reports to the GHGRP in that industry segment (and basin or state, as
applicable), we are finalizing as proposed that the purchasing owner or
operator will merge the acquired facility with their existing facility
for purposes of reporting under the GHGRP. In other words, the acquired
emission sources will become part of the purchaser's existing facility
under the GHGRP and emissions for the combined facility will
[[Page 42075]]
be reported under the e-GGRT identifier for the purchaser's existing
facility. We are finalizing as proposed a requirement that the
purchaser will then follow the provisions of 40 CFR 98.2(i)(6) to
notify the EPA that the purchased facility has merged with their
existing facility and will provide the e-GGRT identifier for the
merged, or reconstituted, facility. Finally, the purchaser will be
responsible for submitting the merged facility's annual report for the
entire reporting year in which the acquisition occurred (i.e., the
owner or operator as of December 31 will be responsible for the report
for that entire reporting year) and each reporting year thereafter. We
proposed, but are not taking final action at this time on, a
requirement that the purchasing owner or operator would also become
responsible for responding to EPA questions and making any necessary
revisions to annual GHG reports for the purchased facility for
reporting years prior to the reporting year in which the acquisition
occurred. Similarly, we are not taking final action at this time on a
requirement that the acquired facility's certificate of representation
be updated within 90 days of the transaction to reflect the new owner
or operator. As noted above, we intend to consider those proposed
revisions in coordination with the 2024 WEC rulemaking and take action
on these requirements, if finalized, at the same time.
Third, to address transactions where the selling owner or operator
retains some of the emission sources and sells the other emission
sources of the seller's facility to one or more purchasing owners or
operators, we are finalizing as proposed that the selling owner or
operator will continue to report under subpart W for the retained
emission sources unless and until that facility meets one of the
criteria in 40 CFR 98.2(i) and complies with those provisions. Each
purchasing owner or operator that does not already report to the GHGRP
in that industry segment (and basin or state, as applicable) will begin
reporting as a new facility for the entire reporting year beginning
with the reporting year in which the acquisition occurred. The new
facility will include the acquired applicable emission sources as well
as any previously owned applicable emission sources. We note that,
under the provisions that are being finalized as proposed, because the
new facility will contain acquired emission sources that were part of a
facility that was subject to the requirements of part 98 and already
reporting to the GHGRP, the purchasing owner or operator will follow
the provisions of 40 CFR 98.2(i) and continue to report unless and
until one of the criteria in 40 CFR 98.2(i) are met, instead of
comparing the facility's emissions to the reporting threshold in 40 CFR
98.231(a) to determine if they should begin reporting. Each purchasing
owner or operator that already reports to the GHGRP in that industry
segment (and basin or state, as applicable) will add the acquired
applicable emission sources to their existing facility for purposes of
reporting under subpart W and will be responsible for submitting the
annual report for their entire facility, including the acquired
emission sources, for the entire reporting year beginning with the
reporting year in which the acquisition occurred.
Fourth, to address transactions where the selling owner or operator
does not retain any of the emission sources and sells all of the
facility's emission sources to more than one purchasing owner or
operator, we are finalizing as proposed that the selling owner or
operator for the existing facility will notify the EPA within 90 days
of the transaction that all of the facility's emission sources were
acquired by multiple purchasers. After consideration of comment, we are
revising from proposal use of the term ``current owner or operator'' to
instead read ``prior owner or operator'' in the final amendments. The
purchasing owners or operators will begin submitting annual reports for
the acquired emission sources for the reporting year in which the
acquisition occurred following the same provisions as in the third
scenario. In other words, each owner or operator will either begin
reporting their acquired applicable emission sources as a new facility
or add the acquired applicable emission sources to their existing
facility.
Finally, for the third and fourth types of transactions, we
proposed but are not taking final action at this time on a set of
provisions to clarify responsibility for annual GHG reports for
reporting years prior to the reporting year in which the acquisition
occurred. As noted above, we intend to consider those proposed
revisions in coordination with the 2024 WEC rulemaking and take action
on these requirements, if finalized, at the same time.
We proposed that as part of the third and fourth types of ownership
change described previously in this section, the selling owner or
operator and each purchasing owner or operator would be required to
select by an agreement binding on the owners and operators (following
the procedures specified in 40 CFR 98.4(b)) a ``historic reporting
representative'' that would be responsible for revisions to annual GHG
reports for previous reporting years within 90 days of the transaction.
The proposed historic reporting representative for each facility would
respond to any EPA questions regarding GHG reports for previous
reporting years and would submit corrected versions of GHG reports for
previous reporting years as needed. As noted above, we are not taking
final action at this time on the proposed provisions for past reporting
years after a transaction, including the proposed historic reporting
representative provisions, and intend to consider those proposed
revisions in coordination with the 2024 WEC rulemaking and take action
on these requirements, if finalized, at the same time.
We are finalizing as proposed amendments to 40 CFR 98.2(i)(3), the
current provision that allows an owner or operator to discontinue
reporting to the GHGRP when all applicable processes and operations
cease to operate. Through correspondence with reporters via e-GGRT, we
are aware that there have been times that an owner or operator divested
a facility and was therefore no longer required to report the emissions
from that facility, but even though the facility changed owners and did
not cease operating, the selling owner or operator chose the provisions
of existing 40 CFR 98.2(i)(3) as the reason they were ceasing to report
because none of the other options fit the situation. The EPA's intent
is that this reason for no longer reporting to the GHGRP should only be
used in cases in which all the applicable sources permanently ceased
operation. Therefore, we are finalizing as proposed amendments to
clarify that 40 CFR 98.2(i)(3) will not apply when there is a change in
the owner or operator for facilities in these four industry segments,
unless the changes result in permanent cessation of all applicable
processes and operations. We are finalizing a new paragraph at 40 CFR
98.2(i)(7) to specify that a selling owner or operator that completes
the fourth transaction type discussed above (i.e., all the emission
sources from the reporting facility are sold to multiple owners or
operators within the same reporting year) may discontinue reporting for
the facility for the reporting years following the year in which the
transactions occurred provided that notification is provided to the
Administrator. Prior to the addition of this new paragraph, there was
not a reason provided in the regulations to discontinue reporting under
40 CFR 98.2(i) that applied to this situation.
[[Page 42076]]
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to ownership transfers.
Comment: Multiple commenters suggested that the EPA amend the
reporting and ownership transfer provisions such that owners and
operators would only be responsible for reporting emissions that
occurred during their period of ownership or operation and that new
owners should not be responsible for methane taxes generated by the
prior owner. Commenters identified the WEC as a reason to reconsider
reporting responsibilities. Under the structure suggested by
commenters, in the case of transfer of a facility during a reporting
year there would be a separate report submitted by each owner or
operator. One commenter asserted that multiple reports from multiple
reporters would be necessary to ensure accurate reporting as required
by CAA section 136(h). The commenter further stated the proposed
requirements for consolidated reporting by one owner would constitute a
deviation from the IRA and increase the possibility of inaccurate
reporting. Commenters further stated that new owners or operators
should not be responsible for revisions to reports prior to their
effective date of acquisition.
Response: The EPA is not taking action in this final rule on the
existing subpart W requirement that the owner or operator of a facility
as of December 31 is responsible for submitting a report including the
entire calendar year's emissions by March 31 of the following calendar
year.
The EPA disagrees with the assertion that multiple reports and
reporters will be necessary to ensure accurate emissions reporting. The
amendments affecting ownership transfers do not impact the existing
requirement that the owner or operator of a facility as of December 31
is responsible for submitting a report by March 31 of the following
calendar year. The commenter did not identify specific issues with this
current structure leading to the inaccurate reporting of emissions
data. Rather than ensure accurate reporting as the commenter claimed,
the EPA believes that preparation and submission of multiple reports by
different entities related to the same emission sources would lead to
duplicative burden and raise the potential for inconsistencies in
reported data. The EPA therefore believes it would be neither practical
nor supportive of the CAA section 136(h) directive to ensure the
accuracy of reported data for the reporting responsibility for a single
facility to be duplicated in multiple reports among multiple owners and
operators. For these same reasons, the EPA disagrees with commenters
that this implementation deviates from the IRA.
With respect to the assertion that the existing reporting structure
makes the new owner or operator responsible for the methane taxes
generated by the prior owner, the EPA notes that the comment concerns
the timing of ownership changes and the impact upon WEC obligations and
that the EPA considers these to be outside the scope of this subpart W
rulemaking and they are addressed in the 2024 WEC Proposal. With
respect to the assertion that retaining this reporting structure would
constitute ``deviating from the IRA,'' the EPA notes that full calendar
year reporting under subpart W was required for the facility as of
December 31 at the time of signature of the IRA. The EPA finds no
indication in the text of CAA section 136 suggesting that revision to
this structure was mandated or intended.
Comment: Multiple commenters opposed the proposed implementation of
a historic reporting representative. Some commenters suggested that a
historic reporting representative was unnecessary as owners and
operators should only be responsible for emissions that occurred during
their time of ownership or operation, although one commenter stated
that the historic reporting representative was preferable to placing
the responsibility for historic reporting on the new owner or operator.
Some commenters stated that there is no certainty that a historic
reporting representative would have access to the data and information
needed to accurately respond to questions regarding prior year reports.
One commenter suggested that in place of a historic reporting
representative, the EPA implement a data freeze after one year from the
original submittal date of a report.
One commenter supported the proposed use of a contractually
determined reporting representative but asserted that some transactions
may be too complicated to fit within the four categories of
transactions that were proposed.
Response: The EPA is not finalizing the proposed requirements
related to designation of a historic reporting representation at this
time. To better facilitate implementation of the WEC under CAA section
136(c) and alignment with the final WEC rule, the EPA intends to
finalize requirements related to the responsibility for historic
reporting as part of a future rulemaking.
The EPA acknowledges that commenters expressed concern regarding
whether the individual responsible for historic reporting would have
access to data and information needed to accurately respond to
questions regarding GHG reporting, including potentially confidential
or sensitive information and correspondence. Similarly, in past
correspondence regarding the GHGRP, facility representatives have
expressed concern that providing an individual access to the data and
information needed for historic reporting would also provide that
individual access to potentially confidential or sensitive information
and correspondence submitted to e-GGRT in future year reporting. The
EPA notes that the EPA is considering updating e-GGRT to implement
these proposed provisions if finalized in a future rulemaking. For
example, one potential update could be that the individual that an
owner or operator selects to be responsible for historic reporting
would be provided access to a facility's reports and correspondence
limited to the reporting years for which that owner or operator was
responsible for reporting for the facility. This potential
implementation would prevent the individual responsible for historic
reporting from accessing potentially confidential or sensitive
information and correspondence for reporting years following an
ownership transaction.
The EPA is not implementing a data freeze for subpart W reporting
as part of this final rulemaking. The EPA recognizes that resubmissions
for historic reporting years have the potential to be complex due to
changes in facility owners or operators, and further, that because
assessment of the WEC is based upon subpart W reporting these revisions
may carry financial obligations under the WEC program (compared to the
GHGRP). In recognition of this potential complexity, in the 2024 WEC
Proposal a deadline of November 1 was proposed for resubmission of WEC
filings that would otherwise be required due to resubmission of a
report under subpart W. While not at issue in this subpart W
rulemaking, we note that as part of the 2024 WEC Proposal, we proposed
that the EPA would retain the right to reevaluate WEC obligations in
WEC filings after November 1 (e.g., as part of an EPA audit of facility
data). Similarly, the proposed November 1 deadline would not apply to
adjustments to WEC obligations resulting from the process to
[[Page 42077]]
resolve unverified data, proposed at 40 CFR 99.8, should that
resolution occur after November 1. The EPA's proposed approaches for
WEC filing requirements and data verification are intended to
incentivize complete and accurate WEC filings under part 99, and thus
corresponding reporting of complete and accurate data under part 98 to
the extent it is relevant for purposes of WEC, by March 31 of each
year. The EPA anticipates that there may be situations requiring
resubmissions of subpart W reports after the proposed November 1
deadline for purposes of the GHGRP, but notes that these situations
would not necessarily require resubmissions or trigger a change in WEC
obligation under the proposed WEC rule. The EPA is not taking final
action on the requested implementation of a data freeze for subpart W
reporting under this final rule and considers the comment insofar as it
relates to WEC timeframes under the proposed 40 CFR part 99 to be
outside the scope of this subpart W rulemaking.
The EPA acknowledges the existence of complex asset transfers
within the oil and gas industry but is not aware of, and the commenter
did not provide an example of, a transfer that would not fit within the
four categories proposed. The four categories have been finalized as
proposed.
Comment: Multiple commenters stated that a new owner or operator
should not be responsible for correcting or resubmitting reporters that
were submitted and certified prior to their acquisition of a facility.
Response: The EPA is not taking final action on the proposed
requirements related to designation of a historic reporting
representation at this time. To better facilitate implementation of the
WEC under CAA section 136(c) and align with the final WEC rule, the EPA
intends to finalize requirements related to the responsibility for
historic reporting as part of a future rulemaking.
Comment: One commenter noted that in the proposed 40 CFR 98.4(n)(1)
and (2) it is not directly stated which party is responsible for filing
the certificate of representation following the transfer of a facility.
The commenter suggested clarifying amendment to specify this is the
responsibility of the new owner or operator. Another commenter stated
it is unclear what is meant by the term certificate of representation.
Response: The EPA is finalizing 40 CFR 98.4(n)(1) and (2) as
proposed. The language referenced by the commenter is consistent with
the existing language at 40 CFR 98.4(h) related to updates to the
certificate of representation following a change in owner or operator
in the general case (i.e., for all facilities other than those
specified in the final introductory paragraph at 40 CFR 98.4) and is
consistent with the EPA's interpretation of that language (that such
updates are the responsibility of the new owner or operator). As
previously noted, the EPA plans to finalize amendments to historic
reporting responsibilities in a future rulemaking. The EPA intends to
consider any associated amendments related to the responsibility for
updates to the certificate of representation at such time. Regarding
the last comment, we note that the contents of a complete certificate
of representation are listed at 40 CFR 98.4(i), which is not being
amended as part of this rulemaking.
Comment: Multiple commenters addressed the impact of the proposed
amendments on reporting and notification requirements for partial
facility sales. One commenter opposed the proposed language at 40 CFR
98.4(n)(3) that would require both the existing and purchasing owner
and operator to report for their respective emission sources until the
criteria in 40 CFR 98.2(i) are met. The commenter requested that the
EPA instead finalize a provision allowing the existing and purchasing
owners and operators to compare their respective facility emissions to
the reporting threshold in 40 CFR 98.231(a).
One commenter expressed general support for the proposed revisions
but stated that the proposed language for reporting requirements under
the scenarios addressed at 40 CFR 98.4(n)(3) and (4) are ambiguous. The
commenter recommended that the EPA clarify that in scenarios of partial
facility sales the criteria of 40 CFR 98.2(i) would apply. The
commenter further recommended that the EPA finalize a requirement
requiring notification when any type of transaction occurs.
Response: The EPA is finalizing as proposed the provisions related
to continued reporting obligations following the sale of a portion of a
facility's emission sources. The EPA believes the language of 40 CFR
98.4(n)(3) is clear regarding continued reporting obligations for both
the existing and the purchasing owner or operator involved in a
transaction. 40 CFR 98.4(n)(3) requires that the existing owner or
operator continue to report for their retained emission sources unless
and until the criteria of 40 CFR 98.2(i) are met. Similarly, 40 CFR
98.4(n)(3)(i) requires that a purchasing owner or operator that does
not already have a reporting facility in the same industry segment
continue to report for the new facility until one of the criteria in 40
CFR 98.2(i) are met. For a purchasing owner or operator that already
has a reporting facility in the same industry segment, 40 CFR
98.4(n)(3)(ii) directs that the acquired emission sources must be
included in their annual report. The EPA disagrees that the reporting
threshold in 40 CFR 98.231(a) should be used in place of the provisions
of 40 CFR 98.2(i) to determine continued reporting obligations. The
commenter that expressed general support for the provisions stated that
40 CFR 98.2(i) contemplates continued reporting for operators whose
facilities no longer meet the original definition of a applicable
facility under subpart A--including after they have sold assets. The
final amendments ensure that the applicable requirements to cease
reporting for facilities involved in the transactions to which 40 CFR
98.4(n)(3) applies are the same as the applicable requirements to cease
reporting for existing facilities.
The EPA did not propose, and is not finalizing, a requirement that
notification is provided when any type of transaction occurs. As
discussed above, the EPA believes this final rule establishes clear
requirements regarding continued reporting for transferred assets.
Further, the disaggregated reporting provisions finalized for the
Onshore Petroleum and Natural Gas Production and Onshore Petroleum and
Natural Gas Gathering and Boosting industry segments are expected to
provide the EPA the ability to track the movement of assets without
requiring specific notification of each asset transfer.
Comment: One commenter stated that the use of the word ``current''
in the proposed language of 40 CFR 98.4(n)(4) was ambiguous in the
context of a transfer of ownership or operation and recommended that
the EPA clarify that the new owner or operator should be required to
notify the EPA of the acquisition of emission sources.
Response: The EPA acknowledges the potential for confusion with the
term ``current owner or operator'' in the proposed 40 CFR 98.4(n)(4)
and has instead finalized the term ``prior owner or operator'' in this
context. The EPA has not adopted the commenter's suggestion that this
requirement should instead be the responsibility of the new owner or
operator. The intent of this notification is to inform the EPA that
reporting will discontinue for the prior facility due to the sale of
all emission sources to multiple purchasers. The EPA does not believe
any single purchaser will necessarily know that all of the assets from
the prior facility had
[[Page 42078]]
been sold or the identity of other purchasers.
2. Definition of ``Owner'' and ``Operator''
Consistent with section II.D. of this preamble, the EPA is
finalizing the proposal to amend 40 CFR 98.1(c) to clarify that the
terms ``owner'' and ``operator'' used in subpart A have the same
meaning as the terms ``gathering and boosting system owner or
operator'' and ``onshore natural gas transmission pipeline owner or
operator'' for the Onshore Petroleum and Natural Gas Gathering and
Boosting and Onshore Natural Gas Transmission Pipeline industry
segments of subpart W, respectively. The EPA received only supportive
comments on this clarification.
3. Onshore Natural Gas Processing Industry Segment Definition
The EPA is finalizing several amendments to 40 CFR 98.230(a)(3) as
described in this section. The EPA received only minor comments on the
proposed requirements related to the definition of ``onshore natural
gas processing'' in 40 CFR 98.230(a)(3). See the document Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems
under the Greenhouse Gas Reporting Rule in Docket ID. No. EPA-HQ-OAR-
2023-0234 for these comments and the EPA's responses.
According to existing 40 CFR 98.230(a)(3), the Onshore Natural Gas
Processing industry segment currently includes all facilities that
fractionate NGLs. The industry segment also includes all facilities
that separate NGLs from natural gas or remove sulfur and carbon dioxide
(CO2) from natural gas, provided the annual average throughput at the
facility is 25 MMscf per day or greater. The industry segment also
currently includes all residue gas compression equipment owned or
operated by natural gas processing facilities that is not located
within the facility boundaries.
The EPA is finalizing as proposed an amendment to revise the
definition of ``onshore natural gas processing'' in 40 CFR 98.230(a)(3)
to specify that it includes forced extraction of natural gas liquids
(NGLs) from field gas, fractionation of mixed NGLs to natural gas
products, or both, similar to the definition of ``natural gas
processing plant'' in NSPS OOOOa. The revised definition for natural
gas processing also does not include the 25 MMscf per day threshold for
facilities that separate NGLs from natural gas using forced extraction
but do not fractionate NGLs. We are also finalizing the revisions to
the term ``forced extraction of natural gas liquids'' in 40 CFR 98.238
as proposed to specify that forced extraction does not include ``a
Joule-Thomson valve, a dewpoint depression valve, or an isolated or
standalone Joule-Thomson skid.'' These amendments will improve the
verification and transparency of the data, particularly across
reporting years, consistent with section II.C. of this preamble, and it
will provide reporters with certainty about the applicable industry
segment for the reporting year, consistent with section II.D. of this
preamble, allowing them to focus their efforts on collecting accurate
monitoring data and emissions information needed for one applicable
industry segment. As explained in the 2023 Subpart W Proposal, while we
expect that the final revisions will result in some processing plants
that have been reporting as part of onshore petroleum and natural gas
gathering and boosting facilities to begin report as onshore natural
gas processing facilities, and some onshore natural gas processing
facilities beginning to report as part of onshore petroleum and natural
gas gathering and boosting facilities, we do not expect that the
overall coverage of the GHGRP will decrease.
4. Applicability of Proposed Subpart B to Subpart W Facilities
The EPA is not taking final action on the proposed addition of 40
CFR 98.232(n), which would have referred to subpart B of part 98
(Energy Consumption) that was proposed in the May 22, 2023, GHGRP
supplemental proposed rule (88 FR 32852). For the reasons explained in
section III.B. of the preamble to the GHGRP amendments that were signed
by the EPA Administrator on April 3, 2024,\15\ the EPA did not take
final action on the proposed addition of subpart B of part 98.
Therefore, we are not taking final action on proposed amendments to
subpart W to clarify the intent for subpart W reporters to also report
under subpart B. See the document Summary of Public Comments and
Responses for 2024 Final Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems under the Greenhouse Gas
Reporting Rule in Docket ID. No. EPA-HQ-OAR-2023-0234 for a complete
listing of all comments and responses related to subpart B.
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\15\A copy of the final preamble and rule is available at
https://www.epa.gov/ghgreporting/rulemaking-notices-ghg-reporting.
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B. Other Large Release Events
1. Summary of Final Amendments
We are finalizing the inclusion of an additional emissions source,
referred to as ``other large release events,'' to capture maintenance
or abnormal emission events that are not fully accounted for using
existing methods in subpart W, consistent with section II.A. of this
preamble. We proposed to include calculation and reporting requirements
for other large release events in the 2022 Proposed Rule and in the
2023 Subpart W Proposal. We are finalizing the definition of other
large release event to include planned releases, such as those
associated with maintenance activities, for which there are not
emission calculation procedures in subpart W as proposed in the 2023
Subpart W Proposal, except that we are specifically excluding blowdowns
for which emissions are calculated according to the provisions in 40
CFR 98.233(i) from the definition of other large release events, for
reasons described later in this section. We are also finalizing the
language in 40 CFR 98.233(y)(1)(ii), with modifications from proposal
for clarity, that instructs the reporter to exclude emissions that
would have been calculated for the source(s) of the other large release
event during the timespan of the other large release event from source-
specific emissions calculated under paragraphs 40 CFR 98.233(a) through
(h), (j) through (s), (w), (x), (dd), or (ee), as applicable, to avoid
double counting.
One primary difference in the requirements we are finalizing for
other large release events and those in the 2023 Subpart W Proposal is
we are limiting the threshold for other large release events to include
only events under this source category with an instantaneous
CH4 emission rate of 100 kg/hr or higher or events with
instantaneous CH4 emission rates of 100 kg/hr greater than
the emissions estimated using other subpart W methods (the latter of
which is applicable for events associated with calculation methods
elsewhere in subpart W), which aligns with the threshold for events
under the Super-Emitter Program in NSPS OOOOb and EG OOOOc, rather than
having both an aggregate 250 mtCO2e threshold and a 100 kg/
hr methane instantaneous threshold with reporting required if either
threshold was exceeded. We are also finalizing an additional clarifying
sentence at 40 CFR 98.233(y)(1) to clearly state that emissions for the
entire
[[Page 42079]]
duration of the event must be reported as an other large release event,
not just those time periods of the event in which emissions exceed the
100 kg/hr instantaneous rate threshold to ensure that the total
emissions for the duration of the event are appropriately accounted for
in subpart W. This clarification to the proposed provision was added to
ensure that the emissions from the entire event are reported; on
further review the EPA wants to ensure the requirement to calculate and
report emissions from the event could not be misinterpreted, given the
use of the 100 kg/hr instantaneous threshold in the final rule, as
applying to only those periods when the emissions rate exceeded the 100
kg/hr emission rate threshold. Under the final provisions, we are also
clarifying that events that meet or exceed the 100 kg/hr emission rate
threshold when simultaneous emissions from multiple release points that
have a common root cause are aggregated must be reported as a single
other large release event. This approach aligns subpart W's other large
release event provisions with the Super-Emitter Program, which uses
remote sensing technologies that typically detect and measure the
cumulative emissions from the site or facility. Even when more
geospatially accurate methods are used, the measurements may still
reflect the cumulative emissions from an aggregate plume created by
several nearby sources within the site or facility.
We are not finalizing the proposed separately applicable 250
mtCO2e per event threshold. After consideration of comments
and further consideration of available scientific literature, we
determined that the single threshold is more straightforward to
implement and more consistent with the emission events we sought to
include than the 250 mtCO2e threshold, which could include
emission events with relatively small emission rates that occur for
prolonged periods of time. Our literature review reveals that tanks,
unlit flares, and reciprocating compressors have been the majority of
emission sources with emissions that may exceed 250 mtCO2e
over the duration of the emissions event but are generally below 100
kg/hr. We already have calculation methods appropriate for these
sources so the vast majority of these lower rate emission events would
continue to be reported under the source-specific methods and would not
be reported as an other large release event, even if the 250
mtCO2e threshold was retained. Thus, removing the 250
mtCO2e threshold should not meaningfully reduce the
emissions that would have to be reported under the other large release
event provisions.
Additionally, we are changing the requirements related to assessing
incremental emission differences from the source-specific methodologies
for blowdowns from what was proposed. Specifically, we are excluding
blowdowns from the list of subpart W sources for which facilities must
assess whether the incremental emissions threshold for an other large
release event has been met or exceeded. Blowdowns can often have high,
but short-lived, release rates that might otherwise be identified as
other large release events; however, we are excluding such events from
the other large release event source because our assessment is that the
calculation methods for blowdown events under 40 CFR 98.233(i) are more
accurate for this emission source, which has highly transient
emissions. Specifically, the calculation methodology for blowdown vent
stacks under 40 CFR 98.233(i) determines the total volume of between
closed isolation valves and uses the pressure of the system at the
start and end of the blowdown to calculate the amount of gas released,
which we consider to be accurate even for large events. During a
blowdown event, the emission rate will be highest at the start of the
event (highest pressure) and consistently decline during the blowdown.
Many remote measurements only determine the emission rate during a
minute or two of observations, so projecting this instantaneous
emission rate to estimate event emissions for blowdowns can be highly
inaccurate. For these reasons, blowdowns will continue to be reported
under blowdown vent stacks and not under other large release events,
even for large emission rate events. We note that accidental ruptures
of transmission pipelines at onshore natural gas transmission pipeline
facilities and gathering pipelines at onshore petroleum and natural gas
gathering and boosting facilities are not considered blowdowns if the
isolation valves are not closed at the time of the incident because the
volume of the gas released is not limited to the volume between the
isolation valves that are subsequently closed to isolate the leak for
repair. Considering the high pressures at which transmission pipelines
operate, we expect these incidents are likely to have emissions
exceeding 100 kg/hr and are most accurately assessed under the other
large release event provisions.
Consistent with the 2023 Subpart W Proposal, for other large
release events, we are finalizing calculation requirements that rely on
measurement data, if available, or a combination of engineering
estimates, process knowledge, and best available data, when measurement
data are not available. The final calculation procedure consists of
estimating the amount of gas released and the composition of the
released gas. The amount of gas released would generally be calculated
based on a measured or estimated emission rate(s) and an event
duration. We are finalizing provisions as proposed that the start time
of the duration must be determined based on monitored process
parameters, when available, such as pressure or temperature, for which
sudden changes in the monitored parameter signals the start of the
event. If the monitored process parameters cannot identify the start of
the event, we are finalizing the requirement that reporters must assume
the release started on the date of the most recent monitoring or
measurement survey, including advanced technology surveys or voluntary
surveys, that confirms the source was not emitting at the rates above
the other large release event reporting threshold or assume a start
date of 91 days prior to the date of identification, whichever start
date is the most recent. We are also finalizing provisions that for the
purpose of estimating the total volume of the release during the event,
monitoring or measurement survey includes any monitoring or measurement
method in 40 CFR 98.234(a) through (d) as well as advanced screening
methods such as monitoring systems mounted on vehicles, drones,
helicopters, airplanes, or satellites capable of identifying
CH4 emissions at 100 kg/hr, with a modification from
proposal to add language specifying the screening method must be
capable of identifying events at this threshold at a 90 percent
probability of detection as demonstrated by controlled release tests.
This revision in the final provision will ensure that appropriate
advanced screening methods are used. We recognize that some release
events may be identified using audio, visual, and olfactory (AVO)
inspections. Therefore, we are finalizing additional provisions that
specify that, when an event is identified using AVO methods, previous
AVO inspections are considered monitoring surveys and can be used to
limit the start date of an event.
One change from proposal in this final rule is to the default
assumptions associated with the start date of an other large release
event. If no monitoring data or measurement survey data are available,
we are finalizing that reporters must assume that the event
[[Page 42080]]
start date occurred 91 days (three months) prior to the event
identification date. We proposed a 182-day default maximum duration and
requested comment on a 91-day default duration. The available data
suggest that the duration of emission events exceeding 100 kg/hr is
highly variable, commonly lasting several hours to several weeks but
occasionally lasting 182 days or longer, as noted by one commenter.\16\
After reviewing the available information, we determined that a 91-day
default more accurately reflects an average duration than the proposed
182-day default. We note that, consistent with the directives in CAA
section 136(h), we provide default durations for other sources in the
GHGRP, such as equipment leaks, where leaks identified are assumed to
leak all year long (when annual surveys are conducted) or since the
previous survey (with the option for reporters to conduct additional
surveys). For other large release events, we similarly include several
provisions that allow reporters to determine the start date based on
their facility's specific data, including consideration of other
monitoring conducted by the facility; however, we maintain that, in the
absence of other facility-specific information, a default value is
needed and that default should be appropriate based on available data
of other large release events at this time so as to result in
reasonably accurate reporting of total emissions for the facility, as
discussed in the preamble of the 2023 Subpart W Proposal and in the
document Summary of Public Comments and Responses for 2024 Final
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems under the Greenhouse Gas Reporting Rule, available in the
docket to this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234). Based
on consideration of the comments received and for reasons discussed in
section III.B.2. of this preamble, we are finalizing the default start
date of the event, when other information is not available to support a
shorter duration, would be 91 days from the time the event was first
identified. We are aware that many events may be shorter than 91 days;
under the final provisions operators may choose to gather and use other
specified information to determine the actual duration, to avoid the
potential need to apply a default start date for such events. As new
data on event duration becomes available, we intend to evaluate if the
default event should be updated in the future through a future
rulemaking process. We are revising from proposal the language
regarding this 91-day default start date to more clearly specify that
it is used to establish the start date of the event. The 91-day default
start date prior to the date of detection does not limit the cumulative
duration of an event in cases where the repair or cessation of the
emissions is delayed after the date of event detection. For example, if
an event is immediately identified but takes 120 days to repair, the
full duration of the event (120 days) must be used. The 91-day default
only applies to the determination of the start date and not the
cumulative duration. We are finalizing, as proposed, that the end time
of the release event must be the date of the confirmed repair or
confirmed cessation of emissions. There may be events that span across
two separate reporting years. In such cases, we are finalizing as
proposed that the volume of gas released specific to each reporting
year would be calculated and reported for that reporting year starting
with RY2025.
---------------------------------------------------------------------------
\16\ Kairos Aerospace comments on the Greenhouse Gas Reporting
Rule: Revisions and Confidentiality Determinations for Petroleum and
Natural Gas Systems. Letter from Ryan Streams, Kairos Aerospace, to
Jennifer Bohman and Mark DeFigueiredo, U.S. EPA, September 29, 2023.
EPA Docket Id No. EPA-HQ-OAR-2023-0234-0240. ``However, Kairos has
also noted instances where emissions that would qualify as ``Other
Large Release Events'' do appear to be highly persistent in nature.
Kairos analyzed our emission detections during 2022 across the
Anadarko, Barnett, DJ, Eagle Ford, Haynesville, Permian, San
Joaquin, San Juan, and Uinta Basins and observed 714 upstream sites
that had emissions that persisted for at least 182 days. This does
not represent a majority of Kairos detections--Kairos observes
thousands of emissions per year, the majority of which persist for
less than 182 days--but it does appear that long duration events can
happen.''
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For explosions or fires where some of the gas may be combusted or
partially combusted, we are finalizing that reporters must estimate the
portion of the total volume of natural gas released that was combusted
in the explosion or fire in order to determine the composition of GHG
released to the atmosphere during the event. For the portion of natural
gas released via combustion in an explosion or fire, we are finalizing
as proposed that a maximum combustion efficiency of 92 percent be
assumed. Because these releases are not through engineered nozzles that
can be designed to promote mixing and combustion efficiency, the
combustion efficiency of these releases can be highly variable and are
expected to be less efficient than a flare designed to destroy methane.
Since facilities must first estimate the fraction of the gas released
via combustion, we expect that the total combustion efficiency,
considering all gas released over the length of the event, will be much
lower than 92 percent.
We are finalizing requirements for facilities to evaluate releases
when there is monitoring or measurement data completed by the EPA or
the facility. We are also finalizing requirements for facilities to
evaluate releases when there is a notification from the EPA Super-
Emitter Program in NSPS OOOO/OOOOa/OOOOb at 40 CFR 60.5371, 60.5371a,
60.5371b or an applicable approved state plan or applicable Federal
plan in 40 CFR part 62. After consideration of comments received, as
discussed in section III.B.2. of this preamble, and in alignment with
the final provisions of the Super-Emitter Program in NSPS OOOO/OOOOa/
OOOOb and EG OOOOc, we are not finalizing the proposed provision that
subpart W reporters must consider other third-party information (i.e.,
information from parties other than the EPA's or facility's sponsored
monitoring events or notifications of large potential super-emitter
events under the Super-Emitter Program in NSPS OOOO/OOOOa/OOOOb and EG
OOOOc received by the facility from the EPA), and are accordingly not
finalizing the use of the term ``credible information.'' Other third-
party notifications are not assured of having the credibility and
defined requirements that notifications from the EPA under the Super-
Emitter Program, or data from monitoring or measurement conducted by
the EPA or the facility, will have and the EPA has concluded that it is
not appropriate to place a potentially large burden on subpart W
reporters to respond to such information. The final provisions of the
Super-Emitter Program in NSPS OOOO/OOOOa/OOOOb have robust assurances
of credibility, reliability and transparency. The entities doing the
super-emitter monitoring under NSPS OOOO/OOOOa/OOOOb must have the
remote-sensing technology they are using (e.g., satellites) certified
by the EPA under the EPA's advanced methane detection technology
program, including rigorous accuracy checks, where the EPA is
certifying that the technology used is capable of providing accurate
and reliable data within the requirements of the Super-Emitter Program.
The entity filing the super-emitter report must also be certified by
the EPA, to demonstrate that the third party has the training and
expertise to interpret the data and identify a super-emitter event and
has appropriate and reliable methods for identifying the owner or
operator of the sites where the super-emitter event occurred. The
third-party reports must be filed with the EPA
[[Page 42081]]
within 15 days of detection, increasing the opportunity for the owners
and operators to get timely notice, and must also meet specified
reporting criteria and be filed under attestation that the information
is true and accurate to the best of the notifier's knowledge. Once the
super-emitter report is received by the EPA, the EPA evaluates the
report for completeness and accuracy before sending a super-emitter
notice to the owner or operator. The super-emitter notices, and the
owner or operator's response, will all be posted to a public website.
All of these requirements and the significant oversight role the EPA
assumes in certifying both the technology and the reporter, as well as
the checks performed once the reports are submitted to the EPA,
demonstrate that the data underlying the EPA's notices are credible and
reliable and thus support the EPA's conclusion that the emissions
included in the super-emitter notices from the EPA must be evaluated
for a facility's subpart W report. We note that our judgment regarding
the revisions to requirements for each type of source within each
subpart W industry segments reflects our determinations specific to
considerations for each source in each industry segment, including
other large release events. More specifically here, the revisions for
other large release events are intended to be and are implementable
even absent revisions to the other sources, and vice versa, as they
each independently ensure that the emissions reported under subpart W
for the given source or industry segment at issue are consistent with
the directives in CAA section 136(h) and improve the subpart W
provisions as described in section II. of this preamble. Furthermore,
the other large release event requirements for facilities to evaluate
releases when there is monitoring or measurement data completed by the
EPA or the facility are intended to be and are implementable even
absent the other large release event requirements for facilities to
evaluate releases when there is a notification from the EPA Super-
Emitter Program in NSPS OOOO/OOOOa/OOOOb at 40 CFR 60.5371, 60.5371a,
or 60.5371b or an applicable approved state plan or applicable Federal
plan in 40 CFR part 62. Accordingly, the EPA finds that these other
large release event requirements are severable from each other, and
that at minimum revisions for each source are severable from revisions
to each of the other sources.
Under the Super-Emitter Program, the EPA may receive third-party
notifications and in turn notify owners and operators of potential
super-emitter events that are related to subpart W facilities,
including subpart W facilities that either do or do not have NSPS OOOO/
OOOOa/OOOOb or EG OOOOc affected facilities. Under subpart W, we are
finalizing that owners and operators are required to report whether
emission events identified in those notifications are included in their
annual emissions report and if so, under which source category. We are
clarifying in the final rule that facilities must include in the
facility's annual emissions report emissions events identified in
super-emitter notices received from the EPA unless the owners and
operators can certify that the facility does not own or operate the
equipment at the location identified in the notification or, in
situations where there are multiple facilities that own and operate
equipment within 50 meters of the location identified in the
notification, the owners and operators can certify that their facility
does not own or operate the emitting equipment at the location
identified in the notification or unless the EPA has determined that
the notification contains a demonstrable error. For consideration of
demonstrable error, the facility must submit a statement of
demonstrable error as specified by 40 CFR 60.5371, 60.5371a, or
60.5371b or an applicable approved state plan or applicable Federal
plan in 40 CFR part 62.\17\ We are finalizing additional requirements
for actions the owners and operators must complete in order to be able
to certify that the facility does not own or operate the emitting
equipment at the location identified in the notification in situations
where there are multiple facility owners and operators of equipment at
the location. Specifically, the facility must complete an investigation
of available data as specified in 40 CFR 60.5371b(d)(2)(i) through (iv)
within 5 days of receiving the notification to identify the emission
source related to the event. If this data investigation does not
identify the emission source, the facility must conduct a complete leak
survey of equipment within 50 meters of the location identified in the
notification using any one of the methods provided in Sec.
98.234(a)(1) through (3) within 15 days of receiving the notification.
If the data investigation and the leak survey both fail to identify the
source of the event, then the facility owner or operator can certify
that they do not own the emitting equipment.
---------------------------------------------------------------------------
\17\Under the Super-Emitter Program, the owner or operator has
15 days to submit a report, which could include a statement of
demonstrable error challenging the notification. Events occurring
during a calendar year are not reported to the GHGRP until the
following March. We also note that facilities have the ability to
revise their annual reports after submission if errors are
identified.
---------------------------------------------------------------------------
Further, we are finalizing as proposed definitions of the terms
``well release'' and ``well blowout'' in 40 CFR 98.238 to assist
reporting facilities with differentiating between these types of
release events that could potentially occur at wells.
Finally, we are finalizing a series of reporting requirements in 40
CFR 98.236(y) related to the type, location, duration, calculations,
and emissions of each ``other large release event'' similar to those
proposed. Specifically, we are finalizing as proposed that reporters
provide the location, a description of the release (from a specified
list that includes an ``other (specify)'' option for releases that are
not otherwise described well with the list provided), a description of
the technology or method used to identify the release, volume of gas
released, volume fractions of CO2 and CH4 in the
gas released, and CO2 and CH4 emissions for each
``other large release event.'' We are also finalizing that reporters
would provide the start date and time of the release, duration of the
release, and the method used to determine the start date and time
(options would include a pressure monitor, a temperature monitor, other
monitored process parameter, most recent monitoring or measurement
survey showing no large release (and specify the type of monitoring or
survey), or the default assumption that the release started 91 days
prior to the event identification date). As previously explained in
this section, the 91 days start date would be the required assumption
if the facility does not have empirical data, such as monitored process
parameter data or leak inspections or advanced technology monitoring or
measurement surveys, to identify the release start date, a reduction
from the 180 days proposed. These provisions are otherwise being
finalized as proposed except for minor revisions to reflect the
revisions and clarifications pertaining to the default assumption start
date. We are also finalizing as proposed that reporters provide a
general description of the event and indicate whether the ``other large
release event'' was also identified as a potential super-emitter event
under the super-emitter event provisions of NSPS OOOO/OOOOa/OOOOb at 40
CFR 60.5371, 60.5371a, or 60.5371b or an applicable approved state plan
or applicable Federal plan in 40 CFR part 62.
We are finalizing that reporters that received super-emitter event
[[Page 42082]]
notifications from the EPA would be required to report certain
information on each release notification with some revisions from
proposal. We are adding language to limit reporting requirements for
super-emitter event notifications to those for which the EPA does not
determine that the notification contains a demonstratable error. For
consideration of demonstrable error by the EPA, facilities must
describe the demonstrable error in their Super-Emitter Program report
according to the provisions of NSPS OOOO/OOOOa/OOOOb at 40 CFR 60.5371,
60.5371a, or 60.5371b or an applicable approved state plan or
applicable Federal plan in 40 CFR part 62. We are finalizing that for
each EPA notification received via the Super-Emitter Program (for which
the EPA does not subsequently determine that the notification contains
a demonstrable error), facilities would report the type of event
resulting in the emissions as one of the following types of events:
normal operations, a planned maintenance event, leaking equipment,
malfunctioning equipment or device, or undetermined cause. Because all
Super-Emitter Program notifications will come from the EPA, we are not
finalizing certain proposed reporting requirements regarding the
notification since the EPA will already have this information (e.g.,
name of notifier, method used, date of measurement, and emission rate
and uncertainty bounds). We are finalizing that facilities must
indicate whether the emissions identified from the event are included
as an other large release event, as another source required to be
reported under subpart W, or not included. The only exception to the
requirement to include emissions identified via the notification in
emissions reported by the facility under subpart W is if the facility
is able to make a determination, and then certify to the EPA that the
facility does not own or operate the equipment at the location
identified in the Super-Emitter Program notification. We are not
finalizing the proposed requirement that the reporter provide a reason
for not including the emissions from the event in their annual
emissions report, as all emission events identified under the Super-
Emitter Program that are the subject of a notice from the EPA to the
owner/operator must be quantified unless the exception applies and the
owner or operator of the facility certifies that the exception applies.
This information would support EPA verification and ensure accuracy of
the emissions reported under other large release events and the
facility's total reported emissions.
We are not finalizing several of the proposed reporting
requirements under subpart W regarding notifications under the Super-
Emitter Program because all of the Super-Emitter Program notifications
will be issued by the EPA and the EPA will already have records of the
information we had proposed to require be submitted under subpart W.
Specifically, we are not finalizing requirements proposed at 40 CFR
98.236(y)(11)(ii) to report the latitude and longitude of the release
as reported in the notification. Also, we are not finalizing
requirements proposed at 40 CFR 98.236(y)(11)(iv) to report whether the
release was received under the super-emitter event provisions of NSPS
OOOO/OOOOa/OOOOb at 40 CFR 60.5371, 60.5371a, or 60.5371b or an
applicable approved state plan or applicable Federal plan in 40 CFR
part 62 or another notifier, and, if the notification was from another
notifier, the reporter would provide the name of the notifier, the
remote sensing method used, the date and time of the measurement, the
measured emission rate, and uncertainty bounds on the emission rate.
These changes from proposal align with the final requirements in the
Super-Emitter Program under NSPS OOOO/OOOOa/OOOOb and EG OOOOc and
ensure we are not finalizing duplicative reporting requirements.
Finally, we are adding a reporting requirement to provide an
indication if you received a super-emitter release notification from
the EPA after December 31 of the reporting year for which
investigations are on-going such that the annual report that has been
submitted may be revised and resubmitted pending the outcome of the
super-emitter investigation. This reporting element is provided in
recognition of the fact that some super-emitter notifications received
in 2026 may impact the 2025 reporting year annual report and there may
not be sufficient time to revise the 2025 annual report prior to the
March 31 deadline. This reporting element allows the reports to be
certified as accurate for submission while noting the potential need
for revision depending on the outcome of the super-emitter release
notification investigation.
2. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to add the other large release events source
category.
Comment: We received numerous comments on the proposed thresholds
for defining a reportable other larger release event. Several
commenters supported both of the thresholds included in the 2023
Subpart W Proposal and some commenters recommended smaller reporting
thresholds, specifically reducing the 100 kg/hr to 14 kg/hr. However, a
majority of the comments received opposed one or both of the
thresholds. Commenters opposing the 250 mtCO2e threshold
generally considered it to be too small, especially considering the
proposed 182-day default start date. One commenter stated ``. . . it
would take approximately 90 days for a 4.7 kg/hr CH4 leak to
exceed the proposed 250 mtCO2e threshold. . . A `large
release event' should be just that, not a small release over a long
period of time.'' Many of these commenters suggested that the EPA adopt
the Pipeline and Hazardous Materials Safety Administration (PHMSA)
threshold for a reportable incident of 3 MMscf (approximately 6 times
higher that the proposed threshold).
Regarding the 100 kg/hr threshold, a few commenters suggested this
emission rate was too high and that a lower threshold should be adopted
but most of the commenters recommended that a time component was needed
with this threshold because in their view high rate, short duration
events would still have small contributions to a facility's annual
emissions. Many of the commenters making this argument specifically
cited blowdowns as sources with high release rates and short durations
and indicated that these types of events should not be considered under
the other large release event provisions.
Several of the commenters indicated that the EPA should use a
combined threshold (exceed 250 mtCO2e AND 100 kg/hr methane)
rather than the two independent thresholds proposed (exceed 250
mtCO2e OR 100 kg/hr methane). These commenters noted that
this would address issues with low rate, long duration events being
considered as other large release events as well as setting a minimum
emission quantity for high release events, so short duration, high rate
releases such as blowdowns would not be considered under the other
large release event provisions. A few of the commenters suggesting a
combined threshold also suggested increasing thresholds levels.
Response: After considering comments received, we are finalizing
the 100 kg/hr threshold as proposed, but we are not finalizing the
proposed 250 mtCO2e threshold. We determined that the single
threshold will be more straightforward for operators to implement,
aligns more directly with
[[Page 42083]]
the EPA's Super-Emitter Program, and is more consistent with the
emission events we sought to include in the other large release events
source than the 250 mtCO2e limit. Furthermore, based on our
literature review of emission sources with emissions below 100 kg/hr,
tanks, unlit flares, and reciprocating compressors were the majority of
these smaller rate emitters. In this final rule, we have calculation
methods appropriate for these sources that accurately estimate
emissions from events with emission rates less than 100 kg/hr and
determined that removing the 250 mtCO2e threshold would not
significantly reduce the emissions that would have to be reported under
the other large release event provisions because these sources would
always be reported under the source-specific reporting requirements, as
amended, rather than under other large release event provisions.
We disagree with commenters requesting a smaller 14 kg/hr methane
emission rate threshold. First, this emission rate is at or below the
level of detection for several remote sensing methods. Second, this
would cause a disconnect between the final other large release event
threshold and the NSPS Super-Emitter Program requirements.
Regarding commenters suggesting that the 100 kg/hr threshold alone
is not appropriate because high rate, short events may have low
cumulative emissions and commenters suggestion that the EPA implement
one combined threshold exceeding both the 100 kg/hr and the 250
mtCO2e limit, we disagree that these high emission rate
events should not be reported when they are from sources not otherwise
subject to reporting under subpart W or from sources for which the
source-specific method significantly understates the emissions. We also
disagree that the 250 mtCO2e threshold should be applied to
limit the number of releases exceeding 100 kg/hr that should be
accounted for within the subpart W other large release event reporting
requirements. CAA section 136(h) directed the EPA to revise subpart W
to accurately reflect total methane (and waste emissions). Combining
the thresholds would cause a disconnect between the Super-Emitter
Program and the GHGRP reporting requirements where some NSPS OOOOb or
EG OOOOc super-emitter events would not be reported under the subpart W
and result in the underreporting of methane emissions to subpart W.
Several of the commenters provided hypothetical calculations of mass
emissions that would occur for events right at the 100 kg/hr rate for 1
to 5 minutes but offer no data to support that such events are
prevalent. We also note that remote detection of high release events
relies on an adequate pathlength concentration being present, which
would not be the case for these hypothetical short duration events.
These methods generally make flux calculations using wind speeds and/or
dispersion models that typically assume a developed plume, but the
plume would not be fully developed for these hypothetical short events.
Even if the emission event can be detected and quantified by the
monitoring technique used, it is highly unlikely that the remote
monitoring measurement would occur precisely at the time of the 1- to
5-minute release. As such, we find the commenter's concern regarding
the need to evaluate numerous very short events is largely unfounded.
Nonetheless, we did evaluate potential release events that may be of
short duration, as described in the following paragraph.
When commenters provided an example of high-rate, short events,
they all pointed to blowdown events. However, blowdowns have their own
calculation method, which we consider to be accurate across the
duration of the event. Specifically, the blowdown methodology
determines the total volume of natural gas between closed isolation
valves and uses the pressure of the system at the start and end of the
blowdown to calculate the amount of gas released. During the blowdown
event, the emission rate will be highest at the start of the event
(highest pressure) and consistently decline during the blowdown. Many
remote measurements only determine the emission rate during a minute or
two of observations. Projecting this instantaneous emission rate to
estimate event emissions for blowdowns can be highly inaccurate.
Therefore, in the final provisions we have removed the proposed cross-
reference to 40 CFR 98.233(i) for blowdowns in the definition of other
large release events so no additional calculations are necessary for
the emissions from blowdown activities. If a facility fails to close an
isolation valve and an intended blowdown event is actually a continuous
venting event, such an event is not a blowdown and would have to be
reported as an other large release event if it exceeds the 100 kg/hr
threshold.
Besides blowdowns, the other likely high rate, short duration
release event is pressure relief device (PRD) openings. Currently, PRDs
are included under equipment leaks to account for periods when there is
a leak past the PRD valve while it is in the closed position, but
pressure relief events (periods when the valve intentionally opens due
to an over-pressuring of the process vessel or equipment) are not
accounted for under most circumstances. For uncontrolled production
storage tanks, the calculation method assumes all dissolved methane in
fluids from the separator are emitted from the tank. For controlled
tanks, we require facilities to assume a zero percent capture/control
efficiency over the time period the thief hatch is open (which commonly
works as a PRD for the storage tank). Because large, direct PRD
releases are not captured elsewhere in subpart W except for storage
tanks, we maintain that these emissions must remain reportable as other
large release events when the applicable threshold is met to accurately
reflect methane emissions from the facility. We note that CAA section
136(h) requires that the EPA revise the requirements of subpart W to
accurately reflect the total methane emissions from applicable
facilities.
We expect that most short duration events will be adequately
captured under source-specific provisions of subpart W, as included in
the final rule. Additionally, with the 100 kg/hr emission rate
threshold and exclusion of blowdowns, we expect that there will be a
limited number of events that qualify under the provisions of other
large release events. However, we maintain that the emissions from
large emission rate events that are currently not required to be
reported or that are not well-characterized under other provisions of
subpart W must be reported as other large release events as directed
under CAA section 136(h).
Comment: Numerous commenters opposed the proposed requirement that
``. . . if you have credible information that demonstrates the release
meets or exceeds one of the thresholds or credible information that the
release may reasonably be anticipated to meet or exceed (or to have met
or exceeded) one of the thresholds in paragraph (y)(1) of this section,
then you must calculate the event emissions and, if the thresholds are
confirmed to be exceeded, report the emissions as an other large
release event.'' Some commenters expressed concern that this
requirement would create a disincentive to voluntary, site-wide
monitoring. The commenters also stated that ``credible information'' is
poorly defined. Additionally, commenters opposed the proposed reporting
requirements that reporters must consider and report on ``third-party
notifications'' because unqualified third-party notifications could
unnecessarily increase the reporting burden while not leading to more
accurate GHG reporting. The
[[Page 42084]]
commenters also challenged the legality of this requirement. According
to the commenters, CAA section 114 authorizes the EPA only to collect
information and it does not authorize the EPA to impose a mandatory
reporting obligation that would be triggered by third-party
observations or assertions. The commenters also state that any third-
party data should be thoroughly vetted by the EPA and should require
assessment of persistence of the observed emissions rather than relying
on a single observation. One commenter expressed concern that without a
robust structure in place, third party notices could be received on
March 30 that require revisions to annual reports due on March 31,
which the commenter considered unreasonable. Other commenters stated
that the EPA must define ``credible evidence,'' allow operators to
account for telemetry malfunctions, and remove requirements for
reporters to respond to third-party notifications.
Response: We agree with commenters that the EPA should have a role
in authorizing third-party measurement systems and collecting and
submitting notifications that trigger a reporting obligation under
subpart W. Under the Super-Emitter Program, third parties must be EPA-
certified entities, who must use EPA-approved remote sensing
technologies and approaches. Under the Super-Emitter Program, the EPA
will play an important oversight role, including notifying owners and
operators after reviewing third-party notifications of events received
under the Super-Emitter Program. It is within our authority for this
subpart W rule to require reporters to assess the information that we
have vetted and sent to them as notifications through the Super-Emitter
Program, as it is data that we will have assessed as robust as part of
that program, is based on empirical data, and is relevant to accurate
calculations of emissions for the facility. Owners and operators
identified through the Super-Emitter Program will also 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. Regarding our authority for the NSPS Super-Emitter Program
itself, that is outside the scope of this rulemaking; please see the
discussion of our authority in the NSPS OOOOb final rule (see 89 FR
16876-16879, March 8, 2024).
In this final rule, we are not finalizing the proposed term
``credible information'' and simply describing in 40 CFR 98.233(y) the
types of information that must be considered. Specifically, we are
requiring that facilities consider both EPA-verified notifications
provided under the Super-Emitter Program in NSPS OOOOb or federal or
state plans consistent with EG OOOOc and any EPA- or facility-funded
monitoring data that identify high emission events. Facility owners and
operators are required to assess whether those emission events meet the
definition of other large release event or are adequately reported
under other provisions of subpart W. Owners or operators are not
required to consider any other third-party monitoring data besides
those received through a notification from the EPA or funded by EPA or
the facility, but may consider other third-party data at their
discretion. This eliminates the concerns noted by the commenters
regarding unvetted and unsolicited third-party notifications.
If a company-sponsored monitoring event (whether voluntary or
regulatorily required) indicates an other large release event and site
operation staff confirm the release, such emissions should be reported,
particularly given the direction under CAA section 136(h). Commenters
raised concerns that this may discourage facilities from conducting
voluntary site-wide monitoring; however, we consider that the structure
of directives Congress gave the EPA under CAA section 136(h), which the
EPA acted consistent with in this final rule, provides an incentive for
routine monitoring. Routine or continuous monitoring allows a facility
to both reduce waste emissions and identify an accurate number and
duration of other large emission events. The EPA recognizes that the
option for reporters to submit additional empirical data for a given
facility may lead to reporters taking additional voluntary actions for
subpart W reporting, including for the purpose of demonstrating the
extent to which a charge under CAA section 136(c) is owed. To the
extent this approach ``incentivizes'' additional actions by the
reporter, the EPA considers this to be inherent in the directives
Congress gave the EPA in CAA section 136(h). The EPA considers this
approach consistent with the directives Congress specified in CAA
section 136(h), as it ensures that reporting is based on empirical data
and accurately reflects total methane emissions while also allowing
reporters to submit appropriate empirical emissions data. We also note
that facilities must still act on EPA-provided notifications (from the
Super-Emitter Program) about large release events.
With respect to concerns about notifications impacting soon to be
submitted or previously submitted annual reports, we first note that
the 15-day maximum timeframe for third-party notifiers to submit
information to the EPA under the Super-Emitter Program will ensure
facilities will be notified of super-emitter events in a timely manner.
For events for which start times can be determined, which we expect to
be most events, notifications received in late March are unlikely to
require revisions of the annual report due at the end of March because
it is likely that the facility is already aware of the event from data
regularly monitored by the facility. Second, with the revised default
start date being 91 days from event identification rather than 182
days, it is much less likely that notifications received at the end of
March 2026, for example, would impact the emission totals for the 2025
reporting year, which ends 89 days before the report due date. However,
we acknowledge that there may be circumstances that notifications are
received near the March 31 due date and there would not be time to
evaluate the notification prior to the reporting deadline. In this
circumstance, facilities should submit their report to the best of
their knowledge. We added a reporting element at 40 CFR
98.236(y)(11)(v) for reporters to provide an indication of whether they
have received a super-emitter release notification after December 31 of
the reporting year for which an investigation is on-going and might
result in the need to revise and resubmit the annual report pending the
outcome of the super-emitter investigation. If upon determining the
start date and duration of the event, the some of the event's emissions
are reportable for the report already submitted, facilities are able to
amend the previously submitted annual report to include the applicable
event emissions and resubmit that annual report. We note that
facilities have 45 days under 40 CFR 98.3(h)(1) to resubmit and correct
their annual report after identifying a substantive error, which would
afford them additional time to evaluate the event.
While persistence is not specifically included in the Super-Emitter
Program notification requirements, many of the remote sensing
technologies use multiple determinations (e.g., multiple transects at
different heights) to meet required accuracy assessments.
18 19 For
[[Page 42085]]
a super-emitter notification that the EPA determines is complete and
does not contain information that the EPA finds to be inaccurate to a
reasonable degree of certainty, we maintain that it is reasonable to
require facilities to report these emissions, even when they may be
short-lived. Because some remote measurements may identify an aggregate
emission rate from the site or facility that exceeds 100 kg/hr but
would not have the spatial resolution to identify the specific source
or sources, reporters will need to investigate and identify the source
of the emissions. We note that in certain situations, such as a process
unit over-pressuring, there may be multiple release points (such as
several different PRDs opening at the same time). For these types of
releases, we find it reasonable to aggregate the emissions from all
release points that have a common root-cause and consider that a single
``event'' because this would more closely tie reported emissions to the
available monitoring data.
---------------------------------------------------------------------------
\18\Karion, A., et al., ``Aircraft-Based Estimate of Total
Methane Emissions from the Barnett Shale Region.'' Environ. Sci.
Technol. 2015, 49, 8124-8131. https://pubs.acs.org/doi/10.1021/acs.est.5b00217. Available in the docket for this rulemaking, Docket
ID. No. EPA-HQ-OAR-2023-0234.
\19\Schwietzke, S., et al., ``Improved Mechanistic Understanding
of Natural Gas Methane Emissions from Spatially Resolved Aircraft
Measurements.'' Environ. Sci. Technol. 2017, 51, 7286-7294. https://pubs.acs.org/doi/10.1021/acs.est.7b01810. Available in the docket
for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------
Comment: Several commenters supported the 182-day default duration.
One commenter noted that they had observed 714 upstream sites that (1)
had emissions that would qualify as an other large release event under
the subpart W proposal, and (2) persisted for at least 182 days. While
the majority of the site-level emission detected by the commenter
persisted for less than 182 days, the commenter noted that long
duration events can occur. On the other hand, numerous commenters
opposed the 182-day default duration. These commenters argued that the
182-day duration would effectively require facilities to do more
frequent monitoring to avoid having to use the 182-day default
duration. Several of these commenters indicated that the 91-day default
duration that the EPA requested comment on was more appropriate. Other
commenters suggested a default duration of 30 or 45 days may be more
appropriate given the typical duration of large release events. Other
commenters recommended that reporters be permitted to use a wide
variety of methods, including audio, visual and olfactory methods,
optical gas imaging (OGI) surveys, flyovers, process parameters, and
Supervisory Control and Data Acquisition (SCADA) systems, to determine
the start and end time of such events. Some commenters suggested
process knowledge and engineering estimates be allowed to determine
event duration.
Response: After reviewing comments, we have decided to finalize the
default start date of an event to be 91 days prior to event
identification rather than the proposed 182 days. While we also
inadvertently referred to this as a default duration in our 2023
Subpart W Proposal, we intended this to be the default start date (in
the absence of any monitored process data, survey or remote sensing
data suggesting a more recent start date). As further indication of our
intent, we note that the paragraph at 40 CFR 98.233(y)(2)(ii) is
specific to determining the start date of the event and a separate
paragraph--40 CFR 98.233(y)(2)(iii)--provides the provision for the end
time. Nonetheless, based on comments received, it appears some
commenters may have interpreted this to be a maximum event duration;
therefore, we are clarifying in the final provisions in 40 CFR
98.233(y)(2)(ii) that, in the absence of monitored process parameter
data indicating the start date, the event must be assumed to start on
the date of the most recent monitoring or measurement survey that
confirms the source was not emitting at or above the rates specified in
40 CFR 98.233(y)(1) or assumed to have started 91 days prior to the
date the event was first identified, whichever start date is most
recent. Therefore, we are limiting how far back in time the default
start date is from the date the event was first identified, but we are
not limiting the maximum duration of the event. For example, the Aliso
Canyon event was identified soon after it started since the natural gas
contained odorant, but the leak took months to repair and had a total
duration of about 112 days. In a case with these facts under the final
provisions, the duration of the event must still be reported as 112
days based on the identified start date and the confirmed repair date
of the leak.
The literature study data we reviewed, as detailed in the subpart W
TSD for the final rule (included in Docket ID. No. EPA-HQ-OAR-2023-
0234), suggest that the duration of emission events exceeding 100 kg/hr
is typically short and that a 91-day default more accurately reflects
the typical range of observed durations expected to be reported under
this source category than the proposed 182-day default. For example,
well blowouts, which is a source of emissions that will be reported
under other large release events, often persist for an extended period
of time. We disagree with commenters that the default duration should
be reduced further, for example to 30 days, because this could in many
cases result in under-reporting, and will also disincentivize
facilities from trying to pinpoint actual start dates for events that
may have started 30 or more days prior to event detection. We also
expect that most short duration events will be adequately captured
under source-specific provisions of subpart W, as included in the final
rule. We also note that, as discussed above, blowdowns, the often-cited
example of high-rate, short events, have been excluded from the final
provisions for assessment as an other large release events and are
required to be reported under the provisions at 40 CFR 98.233(i) for
blowdown vent stacks. We also have strong evidence that longer duration
events do occur, as noted by one commenter. With the clarification that
this default relates only to the start date of the event, we maintain
that emissions from longer duration events will still be accurately
characterized when using this 91-day default event start date because
this default does not limit the total duration of the event in cases
where it may take days to several months or longer to correct the
issue. While we revised from proposal the default start date, we still
expect that this default start date provisions will not be used often
and that most facilities will be able to identify a start time based on
monitored process parameter data or routine monitoring surveys.
We intentionally provided flexibility for using monitored process
parameters for determining the start time of a release in the proposed
rule without trying to limit the types of parameters that could be
monitored to identify the start date of an event. We note that data
from SCADA systems are considered monitored process parameters. If a
facility has a continuous monitoring network, they can also use that
data to identify the start time. If a facility conducts frequent
advanced technology or remote sensing surveys, these can be used to
more directly assign a start date, provided that the advanced screening
method is capable of identifying events with CH4 emission rates of 100
kg/hr at a 90 percent probability of detection as demonstrated by
controlled release tests. We allow process knowledge and engineering
estimates in the review of the process data to identify the event start
date. However, we maintain that monitored parameters must be used to
make these assessments. The comments received could be construed to
suggest the facility should be able to pick a start date in the absence
of monitored process parameters. This is inconsistent with our intent
when allowing process knowledge or engineering estimates for
[[Page 42086]]
other reporting elements. To ensure clarity on the use of process
knowledge or engineering estimates, we are retaining the proposed
language that the start time must be determined based on monitored
process parameters and adding that ``sound engineering principles'' are
to be used to determine the start time based on the monitored process
parameter.
We note that most of the monitoring methods suggested by commenters
to identify the start date were already proposed at 40 CFR
98.233(y)(2)(iv). At proposal, we did not include AVO monitoring in the
list of monitoring inspections provided in 40 CFR 98.233(y)(2)(iv)
because the ability of AVO to identify a large event is highly
dependent on the height, location, and characteristics of the release.
However, we also recognize that on-site AVO inspections may identify
some other large release events. If the event is identified via AVO
methods, then we think that it logically follows that it is reasonable
to allow the use of previous AVO inspections conducted for that
equipment to limit the default assumed start date that would otherwise
apply (if no monitoring process parameter data or other monitoring or
measurement survey is available). Therefore, we are adding an
additional sentence to final 40 CFR 98.233(y)(2)(iv) that states that
AVO inspections are considered monitoring surveys if and only if the
event was identified via an AVO inspection.
Reporters are allowed under the final rule and may prefer to
undertake more frequent surveys and submit empirical emissions data
because such an approach could shorten the estimated duration of the
event. The EPA recognizes that the option for reporters to submit
additional empirical data for a given facility may lead to reporters
taking additional voluntary actions for subpart W reporting, including
for the purpose of demonstrating the extent to which a charge under CAA
section 136(c) is owed. As previously explained in response to comment
earlier in this section, to the extent this approach ``incentivizes''
additional actions by the reporter, the EPA considers this to be
inherent in the directives Congress gave the EPA in CAA section 136(h).
The EPA also notes that, as discussed in Section I.E of this preamble,
Congress also provided other provisions under CAA section 136, outside
the scope of this rulemaking, that were intended to be and may provide
incentives; for example, CAA section 136 provides $1.55 billion in
incentives for various specified purposes related to CH4 mitigation and
monitoring, including through grants, rebates, contracts, loans, and
other activities.
Comment: One commenter supported the proposed reporting
requirements for other large release events and supported provisions
ensuring that reporters can only exclude from reported emissions those
coming from third-party notifiers when the reporter provides valid,
well-documented reasons for doing so. To do this, according to the
commenter, the reporter should be required to submit evidence of a site
survey occurring shortly after the notification proving that the event
did not occur or come from their site, including time-stamped
parametric data from the site showing that normal operating conditions
existed. If there is imagery that clearly shows an event at the
reporter's site with a quantified, time-stamped emission rate, it
should not be rebuttable by the reporter according to this commenter.
Several commenters stated that the EPA's proposed reporting
requirements for other large release events are nearly identical to the
proposed super-emitter response program reporting requirements in NSPS
OOOOb and EG OOOOc. According to these commenters, reporting elements
such as the unique notification identification number under the Super-
Emitter Program, latitude/longitude of release, a description of the
technology or method used to identify the release, and the total number
of super-emitter release notifications received from a third-party for
the facility have no bearing or impact on the reporting of GHG
emissions. According to these commenters, GHGRP reporters should not
have to bear the burden of retransmitting that information through a
separate reporting program as it is already being provided to the EPA
through the NSPS program.
Response: As noted previously in this section, we are limiting from
proposal the responsibilities of facilities to respond to third-party
notifications, but we are finalizing many of the proposed reporting
requirements in 40 CFR 98.236(y)(11) for other large release event
reporting pertaining to Super-Emitter Program (under the final NSPS
OOOOb and EG OOOOc) notifications that come from the EPA. We are
finalizing reporting requirements under subpart W for reporters to
indicate the results of any assessment or investigation triggered by
the notification, including the type of event and whether the
identified emissions are included in the subpart W report for a
specific source type or as an other large release event. We are
clarifying in the final rule that facilities must quantify and include
in the facility's annual emissions report emissions events identified
in Super-Emitter Program notices received from the EPA (and the EPA has
not determined that the notification contains a demonstrable error)
unless the owners and operators can certify that the facility does not
own or operate the equipment at the location identified in the
notification or, in situations where there are multiple facilities that
own and operate equipment at the location identified in the
notification, the owners and operators can certify that their facility
does not own or operate the emitting equipment at the location
identified in the notification if they complete certain actions. We are
finalizing additional requirements at 40 CFR 98.233(y)(6) for the
actions required by the owners and operators in order for to certify
that their facility does not own or operate the emitting equipment in
cases where there are multiple oil and gas facilities within 50 meters
of the location identified in the notification. Specifically, owners
and operators must conduct investigations of available data as
specified in 40 CFR 60.5371b(d)(2)(i) through (iv) to identify the
emissions source related to the event notification within 5 days of
receiving the notification. If these investigations do not identify the
emissions source, owners and operators must conduct a complete leak
survey of their equipment within 50 meters of the location identified
in the notification using any one of methods provided in 40 CFR
98.234(a)(1) through (3) within 15 days of receiving the notification.
If that survey also fails to identify the emissions source, the
facility may certify that they took these required actions and that
they do not own or operate the emitting equipment at the location
identified in the notification. Note that, if the reporter owns and
operates the equipment at the location identified in the notification
and there are no other owners or operators of equipment at the location
identified in the notification, then that reporter must account for the
emissions from that event within their subpart W report. With respect
to reporting requirements, if the emissions are not included in the
subpart W report, we are finalizing a reporting requirement that the
facility must have determined, and then must certify, that the
emissions identified in the notification were not from assets under
common ownership or control of the facility. In this manner, we are
requiring that the emissions from all notifications be accounted for
within the subpart W report unless the facility can demonstrate that it
does not own or
[[Page 42087]]
operate the equipment or, if applicable, the emitting equipment at the
location identified in the notice from the EPA.
As previously noted in this section, we are also finalizing that
only for each EPA notification received via the Super-Emitter Program
for which the EPA has not determined that the notification contains a
demonstratable error, the facility would be required to report
information related to the notification. We note, however, that because
the EPA will have vetted and sent to the notifications through the
Super-Emitter Program, we expect that demonstrable errors will be rare.
Because all Super-Emitter Program notifications will be coming from
the EPA for the subpart W other large release event reporting
requirements, we have reduced the reporting requirements under 40 CFR
98.236(y)(11) to focus on those details that the EPA would not already
have regarding the super-emitter event. Specifically, we are
eliminating from the final rule proposed reporting requirements for
latitude and longitude in the notification [at 40 CFR
98.236(y)(11)(ii)] and information on the notifier and method used to
detect emissions by the notifier [at 40 CFR 98.236(y)(11)(iv)]. We
maintain that the remaining reporting elements are important for
understanding which releases are reported as other large release events
and which are reported under other provisions of subpart W.
C. New and Additional Emission Sources
Sources of emissions that are required to be reported to subpart W
are listed in 40 CFR 98.232 for each industry segment, with the
methodology and reporting requirements for each source provided in 40
CFR 98.233 and 98.236, respectively. The EPA is finalizing as proposed
the addition of several emission sources that are anticipated to have a
meaningful impact on reported emissions, are commonplace in the oil and
gas industry, and/or have existing emission calculation methodologies
and reporting provisions in the current subpart W regulatory text. For
some of these emission sources, discussed in additional detail in
section III.C.1. of this preamble, reporting is currently required for
some, but not all, industry segments in which they exist. Other
emission sources, discussed in additional detail in sections III.C.2
through 5 of this preamble, are not currently required to be reported
for any industry segments in which they exist. The addition of sources
to subpart W is expected to enhance the overall quality of the data
collected under the GHGRP and improve the accuracy of total emissions
reported from facilities, consistent with section II.A. of this
preamble.
The following sections detail the final additions of emission
sources to subpart W.
1. Current Subpart W Emission Sources Proposed for Additional Industry
Segments
a. Summary of Final Amendments
Upon review of the U.S. GHG Inventory and the 2021 API Compendium,
as well as other publications,\20\ the EPA determined that several of
the emission sources included in at least one industry segment in
subpart W are not currently required to be reported by facilities in
all the industry segments in which those sources exist. As such,
consistent with section II.A. of this preamble, we are finalizing as
proposed the addition of requirements to report CO2,
CH4, and nitrous oxide (N2O) emissions (as
applicable for the source type) from the following sources under 40 CFR
98.232 and 98.236(a): \21\
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\20\ For example, American Petroleum Institute (API). Liquefied
Natural Gas (LNG) Operations Consistent Methodology for Estimating
Greenhouse Gas Emissions. Prepared for API by The LEVON Group, LLC.
Version 1.0, May 2015. Available in the docket for this rulemaking,
Docket ID. No. EPA-HQ-OAR-2023-0234.
\21\ It should be noted that the EPA did not identify any
subpart W emission sources missing from the Onshore Petroleum and
Natural Gas Gathering and Boosting industry segment.
---------------------------------------------------------------------------
Onshore petroleum and natural gas production: Blowdown
vent stacks.
Onshore natural gas processing: Natural gas pneumatic
device venting, Hydrocarbon liquids and produced water storage tank
emissions.
Onshore natural gas transmission compression: Dehydrator
vents.
Underground natural gas storage: Dehydrator vents,
Blowdown vent stacks, Condensate storage tanks.
LNG storage: Blowdown vent stacks, Acid gas removal unit
vents.
LNG import and export equipment: Acid gas removal unit
vents.
Natural gas distribution: Natural gas pneumatic device
venting, Blowdown vent stacks.
Onshore natural gas transmission pipeline: Equipment leaks
at transmission company interconnect metering-regulating stations,
Equipment leaks at farm tap and/or direct sale metering-regulating
stations, Transmission pipeline equipment leaks.
We are also finalizing several revisions that would facilitate
implementation of the final provisions that require reporting of these
emission sources from additional industry segments. We are finalizing
revisions as proposed to change the name of the emission source type
``onshore production and onshore petroleum and natural gas gathering
and boosting storage tanks'' to ``hydrocarbon liquids and produced
water storage tanks'' and change ``storage tank vented emissions'' to
``hydrocarbon liquids and produced water storage tank emissions''
throughout subpart W. Additionally, we are finalizing revisions as
proposed to the emission source type name in 40 CFR 98.233(k) and
98.236(k) from ``transmission storage tanks'' to ``condensate storage
tanks.'' \22\
---------------------------------------------------------------------------
\22\ Revisions are also finalized as proposed to 40 CFR
98.232(e)(3) to reference the source as ``condensate storage
tanks.''
---------------------------------------------------------------------------
We are also finalizing revisions to the calculation methodologies
and/or emissions reporting structure for each of these emission source/
industry segment combinations that would be needed in 40 CFR 98.233 and
98.236, respectively. For industry segments for which we are finalizing
provisions to additionally require reporting of emissions from AGR
vents, dehydrator vents, hydrocarbon liquids and produced water storage
tank emissions, and condensate storage tank emissions, we are
finalizing as proposed that reporters would use the same calculation
methods and report the same information as reporters in the industry
segments in which those source types are already reported. The
remainder of this section describes additional amendments to 40 CFR
98.233.
For the addition of natural gas pneumatic device venting as an
emission source for the Onshore Natural Gas Processing industry
segment, we are finalizing as proposed that those facilities would use
the calculation methodologies as described in section III.E. of this
preamble. For any reporters to the Onshore Natural Gas Processing
industry segment that would use Calculation Methodology 3, we are
finalizing as proposed the use of the same emission factors as those
used for the Onshore Natural Gas Transmission Compression and
Underground Natural Gas Storage industry segments. See section III.E.
of this preamble for additional details about the calculation
methodologies for natural gas pneumatic devices.
As noted earlier in this section, we are finalizing the addition of
blowdown vent stack reporting as proposed for the Onshore Petroleum and
Natural Gas Production, Underground Natural Gas Storage, LNG Storage,
and Natural Gas Distribution industry segments. Subpart
[[Page 42088]]
W currently requires reporting of blowdowns either using flow meter
measurements (existing 40 CFR 98.233(i)(3)) or using unique physical
volume calculations by equipment or event types (existing 40 CFR
98.233(i)(2)). To allow reporters in the new industry segments to
calculate emissions by equipment or event types, the EPA is finalizing
as proposed the specification of the appropriate list of equipment or
event types for each new segment. We are finalizing as proposed that
facilities in the Onshore Petroleum and Natural Gas Production,
Underground Natural Gas Storage, and LNG Storage industry segments
following the methodology in 40 CFR 98.233(i)(2) are required to
categorize blowdown vent stack emission events into the seven
categories provided in 40 CFR 98.233(i)(2)(iv)(A), as the types of
blowdown vent stack emission events for these segments are similar to
those for the segments currently required to categorize under this
provision. We are finalizing as proposed that facilities in the Natural
Gas Distribution industry segment are required to categorize blowdowns
into the eight categories listed in proposed 40 CFR
98.233(i)(2)(iv)(B), as the types of blowdowns that occur in the
Natural Gas Distribution industry segment are pipeline blowdowns
similar to those in the Onshore Natural Gas Transmission Pipeline
industry segment. After consideration of public comments, we are also
finalizing two revisions to 40 CFR 98.233(i) to provide additional
provisions for Natural Gas Distribution blowdowns. First, we are
revising 40 CFR 98.233(i) to specify that blowdowns in the Natural Gas
Distribution industry segment with a unique physical volume of less
than 500 cubic feet are not required to be reported, due to the fact
that distribution mains and services operate at much lower pressures
than other pipelines. Second, we are revising 40 CFR 98.233(i)(1) to
require the calculation of the distribution pipeline unique physical
volume in cases where a pipeline does not have isolation valves and
revising the definition of the term ``V'' in equation W-14A and
``Vp'' in equation W-14B to remove the phrase ``between
isolation valves.''
We are finalizing one other amendment as proposed related to the
calculation of emissions from blowdown vent stacks. The EPA previously
determined that for reporters in the Onshore Petroleum and Natural Gas
Gathering and Boosting industry segment using the methodology provided
in existing 40 CFR 98.233(i)(2) and equation W-14A, it is reasonable to
allow engineering estimates based on best available information when
determining temperature and pressure for emergency blowdowns, due to
the geographically dispersed nature of the facilities in this industry
segment. As discussed in section III.J.3. of this preamble, we are
finalizing as proposed to also allow engineering estimates based on
best available information when determining temperature and pressure
for emergency blowdowns for the Onshore Natural Gas Transmission
Pipeline industry segment, as facilities in this industry segment are
also geographically dispersed. Due to the fact that facilities in the
Onshore Petroleum and Natural Gas Production and Natural Gas
Distribution industry segments are similarly geographically dispersed,
we are finalizing as proposed that reporters in those industry segments
using the methodology provided in 40 CFR 98.233(i)(2) and equation W-
14A would also be allowed to use engineering estimates based on best
available information available when determining temperature and
pressure for emergency blowdowns.
For the Onshore Natural Gas Transmission Pipeline industry segment,
as noted earlier in this section, we are finalizing the addition of
reporting of emissions from equipment leaks from transmission
pipelines, transmission company interconnect metering-regulating
stations, and farm tap and/or direct sale stations. The EPA is
finalizing as proposed the addition of these sources to the calculation
methodologies provided in 40 CFR 98.233(r) using population emission
factors, with associated updates to the variable definitions in
equation W-32A to include components in the Onshore Natural Gas
Transmission Pipeline industry segment. We are also finalizing the
addition of default CH4 population emission factors for the
components specified in this paragraph at facilities in the Onshore
Natural Gas Transmission Pipeline industry segment in table W-5 to
subpart W as proposed. The EPA derived these final emission factors
using the 1996 Gas Research Institute (GRI)/EPA study Methane Emissions
from the Natural Gas Industry (hereafter referred to as ``the 1996 GRI/
EPA study''), specifically Volumes 9 and 10.\23\ The precise derivation
of the final emission factors is discussed in more detail in the
subpart W TSD, available in the docket for this rulemaking, Docket ID.
No. EPA-HQ-OAR-2023-0234.
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\23\ Methane Emissions from the Natural Gas Industry, Volume 9:
Underground Pipelines, Final Report (GRI-94/0257.26 and EPA-600/R-
96-080i) and Volume 10: Metering and Pressure Regulating Stations in
Natural Gas Transmission and Distribution, Final Report (GRI-94/
0257.27 and EPA-600/R-96-080j). Gas Research Institute and U.S.
Environmental Protection Agency. June 1996. Available in the docket
for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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After consideration of comments and consistent with CAA section
136(h) and the overall intent of this rulemaking for reporting to be
based on empirical data, we are also providing the option for
facilities to survey equipment components, measure leaks, and report
the resulting emissions for transmission company interconnect metering-
regulating stations and farm tap and/or direct sale stations using the
equipment leak survey method in 40 CFR 98.233(q)(3). For the leak
survey option, we are finalizing that a leak survey for transmission
company interconnect metering-regulating stations and farm tap and/or
direct sale stations will be considered a complete leak survey for the
purposes of subpart W if all the subject equipment leak components at a
station are included. We are finalizing this characterization of a
complete leak survey such that a facility could survey some stations
and utilize the population count method at other stations so long as
every station quantifies equipment leak emissions using one of the
provided methods in 40 CFR 98.233(q) or (r). This approach is
consistent with the approach taken in this final rule for facilities in
the Onshore Petroleum and Natural Gas Production and Onshore Petroleum
and Natural Gas Gathering and Boosting industry segments that elect to
conduct leak surveys in accordance with the provisions of 40 CFR
98.233(q) (see section III.P.3. of this preamble). For the leak survey
method in 40 CFR 98.233(q), we are also finalizing that transmission
pipeline facilities can develop a facility-specific leaker factor in
accordance with 40 CFR 98.233(q)(4) using the leak measurements
obtained in accordance with 40 CFR 98.233(q)(3). This approach is
consistent with the approach for other industry segments subject to 40
CFR 98.233(q) who elect to conduct leak measurements in accordance with
40 CFR 98.233(q)(3). As explained in more detail in section III.P.4. of
this preamble, the facility-specific leaker factor approach requires
facilities to accumulate at least 50 measurements by component type to
calculate the facility-specific leaker factor to ensure a statistically
robust emission factor and accurate accounting of emissions. In
response to comments, we are also finalizing a definition for the term
``transmission company interconnect
[[Page 42089]]
metering-regulating station'' as well as correcting some cross-
referencing errors and making minor technical corrections in the final
provisions.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed addition of existing emission source types for various
industry segments.
Comment: Commenters noted that distribution pipelines operate at
pressures much lower than transmission pipelines, and as a result, the
volume of gas blown down and emissions from a 50 cubic foot section of
distribution pipe would be significantly less than the volume of gas
and emissions from a transmission pipeline blowdown. One commenter
noted that pressures are about a factor of 10 less than transmission
pipelines, so blowdowns of equipment less than 500 cubic feet (rather
than 50 cubic feet) should be exempt from reporting.
Response: To evaluate this comment, the EPA reviewed the memorandum
documenting the development of the 50 cubic foot threshold, Equipment
Threshold for Blowdowns.\24\ The analysis in that memorandum was based
on the volume of emissions from a typical large processing or
transmission compressor operating at a pressure of 750 psig to 800
psig. In contrast, distribution systems operate at lower pressures,
with gas mains typically averaging around 60 psig and small service
lines that deliver gas to individual homes operating as low as 0.25
psig.\25\ Therefore, because the distribution pipeline operating
pressures are about a factor of 10 less than the equipment upon which
the 50 cubic foot threshold was based, we are finalizing a threshold of
500 cubic feet for blowdowns in the Natural Gas Distribution industry
segment.
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\24\ U.S. EPA, Equipment Threshold for Blowdowns, November 2010.
Available as EPA-HQ-OAR-2009-0923-3581 and in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
\25\ American Gas Foundation, Safety Performance and Integrity
of the Natural Gas Distribution Infrastructure, January 2005.
Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2023-0234.
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Comment: One commenter stated that isolation valves are uncommon in
the distribution segment, so it is not possible to derive a unique
physical volume, and without a unique physical volume, equations W-14A
and W-14B are each missing required inputs. The commenter stated that
distribution line dig-in emissions are typically mitigated by pinching
off the pipeline until a full repair can be completed.
Response: The EPA agrees that the requirements in 40 CFR
98.233(i)(1) for calculating unique physical volume do instruct
reporters to calculate the volume between isolation valves. However,
lack of isolation valves does not mean that reporters cannot calculate
the physical volume of the pipeline that was isolated from operation.
For example, the commenter indicated that operators typically pinch off
both ends of the section of pipeline that needs repair. In this case,
the reporter could use the diameter of the pipeline and the distance
between the two points where the pipeline is pinched off to determine
the physical volume of that section of pipeline. Therefore, we have
revised 40 CFR 98.233(i)(1) to specify that for natural gas
distribution pipelines without isolation valves, reporters should
calculate the unique physical volume of the distribution pipeline that
was isolated from operation using engineering estimates based on best
available data. For other industry segments with isolation valves, the
``unique physical volume'' does not change and can be calculated prior
to any blowdowns, so that the reporter knows which unique physical
volumes are 50 cubic feet or greater. While a natural gas distribution
reporter may not have isolation valves to pre-define a permanent unique
physical volume, the reporter can determine, for each pipeline diameter
they operate, what length of pipeline would result in a physical volume
of 500 cubic feet or more. If the distance between the two points where
the pipeline is pinched off for a repair is greater than that length,
the blowdown would be required to be reported.
We are also amending the definitions of the term ``V'' in equation
W-14A and ``Vp'' in equation W-14B to remove the phrase
``between isolation valves'' to account for this alternative pipeline
isolation method for natural gas distribution pipelines. We note that
the equations W-14A and W-14B are intended to calculate emissions for
each unique physical volume, allowing for the summation of multiple
blowdowns from one unique physical volume. Because the pinch-off points
are not likely to be in the same location every time, reporters may
have to calculate emissions from each blowdown separately. In other
words, the term ``N,'' the number of occurrences of blowdowns for each
unique physical volume in the calendar year, will most likely be equal
to 1 for each ``unique physical volume.''
Comment: Commenters requested that direct measurement be provided
as an option for transmission interconnect meter-regulating stations
and farm tap/direct sale stations. Commenters stated that providing a
measurement option would result in improved accuracy of the emissions
estimates for these emission sources and align with the objectives in
the IRA to use empirical data. Commenters also explained that the
current measurement methods could be used with the components on these
stations. Some commenters suggested that companies could survey their
stations using the existing subpart W methods and apply leaker factors
for detected leaks in proposed table W-4 to subpart W, which are
provided for transmission and underground storage stations, since the
component types are similar. The commenter also suggested that
facilities could perform annual surveys of their stations or the EPA
could provide an option to survey stations over a multi-year survey
cycle.
Response: As noted by the commenters, the only option provided in
the 2023 Subpart W Proposal for transmission company interconnect
metering and regulating stations and direct sale or farm tap stations
was the population count method, which requires the count of stations
and the use of a default population count emission factor developed
using data from the 1996 GRI/EPA studies. In this rulemaking, the EPA
seeks to provide calculation methods for equipment leaks from subject
emission sources that are supported by available data or by providing
reporters with a direct measurement option, where appropriate.
Providing these options allows facilities to determine which method may
be most appropriate to accurately estimate emissions while factoring
the burden of the method. Generally, it is understood that direct
measurement would provide the most accurate estimate of emissions, but
could require significant resources to perform surveys depending on the
survey method and the number of emission sources. Similarly, the use of
a default population count emission factor does not provide the same
level of accuracy as direct measurement, but requires lower burden
(e.g., count of stations and annual operating times) to estimate
emissions. The EPA's ability to provide the leaker method and the
population count method for estimating equipment leaks from emission
sources requires the development of default leaker or default
population count emission factors. The development of these emission
factors is dependent
[[Page 42090]]
upon the availability of study data from which they can be derived.
We agree with commenters that equipment leak components at
transmission company interconnect metering and regulating stations or
direct sale or farm tap stations could be surveyed and directly
measured using one of the methods provided in 40 CFR 98.234(a).
Therefore, we are finalizing amendments in 40 CFR 98.232(m), 98.233(q),
and 98.236(q) to provide that transmission pipeline companies may
survey, measure, quantify and report equipment leaks from components
(i.e., valves, connectors, open ended lines, pressure relief valves,
and meters) at transmission company interconnect metering and
regulating stations or direct sale or farm tap stations using the
methods in 40 CFR 98.234(a). We are finalizing that a leak survey for
transmission company interconnect metering-regulating stations and farm
tap and/or direct sale stations will be considered a complete leak
survey for the purposes of subpart W if all the subject equipment leak
components at a station are included. We are not requiring the use of
the leak survey and measurement method in 40 CFR 98.233(q), rather it
will be an option in addition to the population count method.
Separately, we are finalizing as proposed the station level default
population count emission factors in 40 CFR 98.233(r), as discussed in
section III.Q. of this preamble.
However, at this time, the EPA does not have the data necessary to
provide a default leaker emission factor approach for equipment leaks
from stations at transmission pipeline companies (i.e., transmission
company interconnect metering and regulating stations; direct sale or
farm tap) as the commenters have requested. While one commenter
suggests that transmission pipeline companies could utilize the leaker
emission factors in table W-4 to subpart W with the count of leakers at
transmission company interconnect metering and regulating stations and
direct sale or farm tap stations, based on our assessment, we find that
the leaker emission factors in table W-4 may not be representative of
the leaks from these transmission pipeline emission sources. The
emission factors in table W-4 were developed and intended for
components at transmission compressor stations and underground natural
gas storage stations. Therefore, we are not finalizing a leaker
approach for these emission sources that would use a default leaker
emission factor, but we may consider providing this approach in a
future rulemaking if data becomes available that could inform a default
leaker emission factor set.
We also reviewed the 1996 GRI/EPA study upon which the final
default population count factors for transmission company interconnect
metering and regulating stations and direct sale or farm tap stations
are based to determine if a default leaker emission factor could be
derived from the study data. However, the study data are presented as
station-level leaks rates (i.e., scf/station-day). Component level leak
rates were not provided in the study. Component level leak rates are
needed to develop default leaker emission factors analogous to those in
Subpart W for other equipment leak emissions sources.
Comment: Commenters stated that the EPA should provide additional
flexibility in the quantification of emissions from transmission
pipelines, including allowing a leaker emission factor approach and/or
direct measurement of leak emissions.
Response: The EPA evaluated potential empirical methods for
quantifying transmission pipeline leaks and determined that there is
insufficient data available to develop subpart W methods that either
directly quantify emissions or apply leaker emission factors to
detected leaks. Although we are not aware of any published studies that
include transmission pipeline leak data, Yu et al. (2022) \26\ used
quantitative aerial remote sensing surveys to quantify gathering
pipeline leaks with emission rates greater than 10 to 20 kilograms of
CH4 per hour. Quantitative aerial remote sensing
theoretically could be used to quantify transmission pipeline leak
emissions but a direct method based on quantitative remote sensing
would have very high uncertainty due to lack of data on the emission
rate distribution of transmission pipeline leaks. Directly quantifying
emissions would exclude an unknown fraction of total emissions that
were below the survey method's detection limit. Similarly, we evaluated
the available data to determine whether a leaker factor approach could
be developed. As noted above, we are not aware of appropriate data for
developing leaker factors for transmission pipelines. We also note that
the accuracy of leaker emission factors is dependent on the method
detection limit and therefore likely would need to be specific to each
survey approach. The EPA intends to evaluate any data available in the
future on transmission pipeline leak emission rates and determine if an
empirical method can be incorporated in future updates. Another issue
with quantitative remote sensing is that individual measurements of
leak emission rates can have high uncertainty. Repeat measurements
reduce the uncertainty, but it is not currently clear what methodology,
including number of measurements, would be appropriate for accurately
estimating emissions from transmission pipeline leaks. The EPA also
intends to evaluate future pipeline leak data to determine what level
of uncertainty and/or number of measurements is needed to accurately
quantify emissions.
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\26\ Yu, J., et al. ``Methane Emissions from Natural Gas
Gathering Pipelines in the Permian Basin.'' Environ. Sci. Technol.
Lett. 2022, 9, 969-974. Available in the docket for this rulemaking,
Docket ID. No. EPA-HQ-OAR-2023-0234.
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Comment: Commenters requested clarification of the proposed terms:
Interconnect, Farm Tap and Direct Sale. The commenters requested that
the EPA either provide definitions and examples of these terms in the
regulatory text or in a FAQ document.
Response: The term ``Farm Tap'' is already defined in 40 CFR
98.238. The definition provided is, ``Farm Taps are pressure regulation
stations that deliver gas directly from transmission pipelines to
generally rural customers. In some cases, a nearby LDC may handle the
billing of the gas to the customer(s).'' We note in the rule that table
W-5 to subpart W groups ``Direct Sale or Farm Tap Station'' indicating
that we expect the terms to be interchangeable or sufficiently carrying
the same meaning, that is a station where there is a direct connect
(i.e., sale) from the transmission pipeline to the customer.
In reviewing Volume 10 of the 1996 GRI/EPA study upon which the
final default population count emission factors are based, we find that
the emission factor included in table W-5 for ``Transmission Company
Interconnect M&R Station'' is based on data collected from stations,
which are ``interconnects with other transmission companies to allow
for flexibility of supply. The stations can flow in either direction.''
The 1996 GRI/EPA study specifically excludes transmission stations
where gas is delivered to distribution companies as these are covered
in the distribution segment, just as they are in subpart W where
natural gas distribution companies report equipment leak emissions from
transmission-distribution transfer stations. The ``Transmission Company
Interconnect M&R Station'' is intended to be stations that are
transmission-to-transmission interconnect points. Furthermore, these
stations are characterized in the 1996 GRI/EPA study as performing
metering and
[[Page 42091]]
pressure regulating with an inlet pressure above 100 psig. In order to
provide clarity to the meaning of the term ``Transmission Company
Interconnect M&R Station'', we are finalizing the following definition
in 40 CFR 98.238: Transmission Company Interconnect M&R Station means a
metering and pressure regulating station with an inlet pressure above
100 psig located at a point of transmission pipeline to transmission
pipeline interconnect.
Comment: Commenters pointed out that there was a mismatch between
equation W-32A and the emission factors provided in table W-5 to
subpart W. Commenters stated that the emission factors provided in
table W-5 are default methane population emission factors. Commenters
stated that the variable ``GHGi'' for transmission pipeline sources
provided in 40 CFR 98.233(r) was proposed as equaling 0.975 for
CH4 and 0.011 for CO2. Commenters requested that
the EPA revise the equation or the factors for consistency and clarity.
Response: We agree with commenters that there was an inadvertent
error in adding onshore natural gas transmission pipeline to the list
of sources in the variable ``GHGi'' of equation W-32A in 40 CFR
98.233(r). We are finalizing a correction that will move the addition
of ``onshore natural gas transmission pipeline'' to be grouped with a
methane concentration of 1 and a carbon dioxide concentration value of
0.011 in the variable ``GHGi'' of equation W-32A in 40 CFR 98.233(r),
consistent with the application of the default methane emission
factors, which we are finalizing as proposed.
2. Nitrogen Removal Units
The EPA is finalizing as proposed revisions to 40 CFR 98.232,
98.233(d), and 98.236(d) to add calculation and reporting requirements
for CH4 emissions from nitrogen removal units used in the
Onshore Petroleum and Natural Gas Production, Onshore Natural Gas
Processing, Onshore Petroleum Natural Gas Gathering and Boosting, LNG
Storage, and LNG Import and Export Equipment industry segments.
Nitrogen removal units remove nitrogen from the raw natural gas stream
to meet pipeline requirements and for compressing natural gas into
LNG.27 28 The nitrogen removal unit typically follows in
series after other process units that remove acid gas (e.g.,
CO2, hydrogen sulfide), water, and heavy hydrocarbons. The
EPA received only minor comments regarding the addition of nitrogen
removal units. See the document Summary of Public Comments and
Responses for 2024 Final Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems under the Greenhouse Gas
Reporting Rule in Docket ID. No. EPA-HQ-OAR-2023-0234 for these
comments and the EPA's responses.
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\27\ Kuo, J.C., K.H. Wang, C. Chen. Pros and cons of different
Nitrogen Removal Unit (NRU) technology. 7 (2012) 52-59. Journal of
Natural Gas Science and Engineering. July 2012. Available in the
docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
\28\ Park, J., D. Cho. Decision methodology for nitrogen removal
process in the LNG plant using analytic hierarchy process. Journal
of Industrial and Engineering Chemistry. 37 (2016) 75-83. 2016.
Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2023-0234.
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The EPA is finalizing as proposed the definition of ``nitrogen
removal unit'' in 40 CFR 98.238 as a process unit that separates
nitrogen from natural gas using various separation processes (e.g.,
cryogenic units, membrane units). The EPA is finalizing a definition of
``nitrogen removal unit vent emissions'' as the nitrogen gas separated
from the natural gas and released with CH4 and other gases
to the atmosphere. The proposed definition of this term also included
nitrogen gas released to a flare or other combustion unit, similar to
the definition of ``acid gas removal unit vent emissions.'' However, as
described later in this section, gas from a nitrogen removal unit
routed to a flare or routed to combustion will be reported separately
as flared emissions or combustion emissions, respectively, so the final
definition of ``nitrogen removal unit vent emissions'' includes only
the vent gas released to the atmosphere. The EPA is finalizing as
proposed the amendments to 40 CFR 98.232(c)(17), 98.232(d)(5),
98.232(g)(10), 98.232(h)(9), and 98.232(j)(3) to add nitrogen removal
unit vents to the list of source types for which the industry segments
previously specified will be required to report emissions and is
finalizing as proposed the corresponding additions at 40 CFR 98.236(a)
to add nitrogen removal units to the list of equipment and activities
that will be reported for each of these industry segments.
The EPA is finalizing CH4 emission calculation
methodologies for nitrogen removal units that are nearly identical to
the final calculation methodologies in 40 CFR 98.233(d) for AGRs. These
methods include use of vent meters, engineering calculations based upon
flow rate and composition of gas streams, or calculation using
simulation software. The final amendments to the AGR calculation
methodologies are largely the same as proposed, with some additional
clarifications regarding applicability of the calculation methods and
provisions to address vents routed to vapor recovery systems. The only
difference between the final calculation methodologies for
CH4 emissions from AGRs and nitrogen removal units is that
any nitrogen removal unit with a vent meter installed must use
Calculation Method 2; the new provision allowing use of Calculation
Method 4 for AGRs with a vent meter does not apply to nitrogen removal
units. Comments on and a more detailed discussion regarding the
amendments to the AGR calculation methodologies, which are relevant to
nitrogen removal units calculation methodologies as well, are addressed
in section III.F.1. of this preamble. Further, the EPA is finalizing as
proposed the addition of relevant reporting elements for CH4
emissions from nitrogen removal units to 40 CFR 98.236(d) for each of
the allowable calculation methodologies.
The EPA is finalizing as proposed the requirements that emissions
from nitrogen removal unit vents routed to a flare (CO2,
CH4, and N2O) will be reported under 40 CFR
98.236(n) separately from vented nitrogen removal unit emissions
(CH4). We note that, as explained in section III.N. of this
preamble, the EPA is finalizing requirements for determining the flow
and composition of the gas routed to a flare that differ from those
proposed in 40 CFR 98.233(n) that also affect AGRs and nitrogen removal
units. Under the final rule, the flared nitrogen removal unit emissions
are included with ``other'' flared source types for purposes of the
disaggregation provisions in 40 CFR 98.233(n)(10) and 40 CFR
98.236(n)(19), as proposed. See section III.N. of this preamble for
more information on the flaring calculation and reporting provisions,
including changes from the proposed requirements that affect AGRs and
nitrogen removal units.
3. Produced Water Tanks
a. Summary of Final Amendments
As discussed in the 2023 Subpart W proposal, in the 2022 U.S. GHG
Inventory emissions estimate for 2020, the EPA estimated approximately
140,300 metric tons of CH4 emissions from produced water
tanks associated with natural gas wells and 88,600 metric tons of
CH4 emissions from produced water tanks associated with oil
wells. Therefore, consistent with section II.A. of this preamble, the
EPA is finalizing as proposed amendments to 40 CFR 98.233(j) to require
reporters with
[[Page 42092]]
atmospheric pressure storage tanks receiving produced water to
calculate CH4 emissions using any of the three calculation
methodologies specified in 40 CFR 98.233(j)(1) through (3). Industry
segments required to report emissions from produced water tanks would
include Onshore Petroleum and Natural Gas Production, Onshore Petroleum
and Natural Gas Gathering and Boosting, and Onshore Natural Gas
Processing. The EPA is finalizing the definition of ``produced water''
as proposed, which is the water (brine) brought up from the
hydrocarbon-bearing strata during the extraction of oil and gas, and
can include formation water, injection water, and any chemicals added
downhole or during the oil/water separation process.
For facilities with produced water storage tanks electing to model
their CH4 emissions consistent with 40 CFR 98.233(j)(1), the
EPA is finalizing revisions as proposed to allow facilities to select
any software option that meets the requirements currently stated in 40
CFR 98.233(j)(1) (i.e., to select a modeling software that uses the
Peng-Robinson equation of state, models flashing emissions from
produced water, and speciates CH4 emissions that result when
the produced water from the separator or non-separator equipment enters
an atmospheric pressure storage tank). We are finalizing revisions to
40 CFR 98.233(j)(1) as proposed to state that API's E&P Tanks should
only be used for modeling atmospheric storage tanks receiving
hydrocarbon liquids.
For stuck dump valve emissions associated with produced water
tanks, we proposed that calculation of these emissions would not be
required when using Calculation Method 3. Additionally, no correction
factor was proposed for use in equation W-16 to calculate stuck dump
valve emissions associated with produced water tanks in Calculation
Methods 2 and 3. Therefore, and after consideration of comments
received, the EPA is revising from proposal the introductory paragraph
in 40 CFR 98.233(j) to, at this time, only require calculation and
reporting of emissions from hydrocarbon liquid stuck dump valves per 40
CFR 98.233(j)(5).
As described in section III.K.5. of this preamble, the EPA is
finalizing that reporters would collect measurements of the simulation
input parameters listed under 40 CFR 98.233(j)(1) for produced water
tanks, with changes from proposal described in section III.K.5. of this
preamble. In addition, after consideration of comments received and the
technical challenges with measuring entrained oil in produced water,
the EPA is finalizing updates from proposal that facilities may elect
to use a representative hydrocarbon liquid composition and assume oil
entrainment of 1 percent or greater rather than collecting a produced
water sample.
The EPA is finalizing as proposed the addition of CH4
emission factors to 40 CFR 98.233(j)(3) that were developed as part of
the 1996 GRI/EPA study, which is consistent with the factors used by
the U.S. GHG Inventory. The final emission factors were sourced from
the 2021 API Compendium (table 6-26), which provides emission factors
from the 1996 GRI/EPA study converted from units of million pounds per
year to units of metric tons per thousand barrels (based upon the
assumption of 497 million barrels of produced water annual production).
Average emission factors are provided for pressures of 50, 250, and
1,000 pounds per square inch. The EPA expects that these factors, which
were developed using process simulation at different pressures, are
sufficiently representative of produced water tank emissions.
Furthermore, the EPA is not aware of any other emission factors for
produced water tank emissions, nor are we aware of studies or data that
would allow us to develop different emission factors.
We are also finalizing reporting requirements for produced water
tanks as proposed. We are finalizing revisions to 40 CFR 98.236(j)(1)
as proposed to refer to both hydrocarbon liquid and produced water
atmospheric storage tanks. Additionally, we are finalizing the addition
of 40 CFR 98.236(j)(2) as proposed to require reporting of total annual
produced water volumes for each pressure range, estimates of the
fraction of produced water throughput that is controlled by flares and/
or vapor recovery, counts of controlled and uncontrolled produced water
tanks, and annual CH4 emissions vented directly to
atmosphere from produced water tanks.
The EPA is also finalizing as proposed the revision of the emission
source type name in 40 CFR 98.233(j) and 40 CFR 98.236(j) from
``onshore production and onshore petroleum and natural gas gathering
and boosting storage tanks'' to ``hydrocarbon liquids and produced
water storage tanks'' to reflect the proposed addition of produced
water tanks. Consistently, the EPA is also finalizing as proposed
revisions to the source type provided in 40 CFR 98.232(c)(10) and 40
CFR 98.232(j)(6) to ``Hydrocarbon liquid and produced water storage
tank emissions,'' which reflect the addition of produced water tanks.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to add produced water tanks as an emission
source for the Onshore Petroleum and Natural Gas Production, Onshore
Natural Gas Processing, and Onshore Petroleum and Natural Gas Gathering
and Boosting industry segments.
Comment: One commenter proposed limiting the required emission
calculations for produced water tanks to emissions associated with
stuck dump valves. Another commenter additionally noted that the EPA
provides a stuck dump valve emission factor for produced water tanks if
Calculation Method 1 or 2 is used, but no factor is provided for tanks
using Calculation Method 3.
Response: The EPA does not agree that produced water tank emissions
should be limited to only those emissions associated with stuck dump
valves. In the 2022 U.S. GHG Inventory emissions estimate for 2020, the
EPA estimated approximately 140,300 mt CH4 emissions from
produced water tanks associated with natural gas wells and 88,600 mt
CH4 emissions from produced water tanks associated with oil
wells. These emissions would not be fully represented in subpart W by
only requiring reporting of emissions from produced water tanks with
stuck dump valves; in other words, this approach would not result in
accurate reporting of total emissions.
As proposed, calculation of emissions from stuck dump valves per 40
CFR 98.233(j)(5) would not be required for produced water tanks using
Calculation Method 3. Additionally, the EPA has reviewed the inputs to
equation W-16 and notes that the correction factor, CFdv, is
provided for only separators in crude oil and condensate production for
Calculation Methods 1 and 2. Finally, the EPA is not aware of published
methodologies for estimating stuck dump valve emissions associated
specifically with produced water tanks. Therefore, after consideration
of comments received, the EPA is revising from proposal the
introductory paragraph in 40 CFR 98.233(j) to not require at this time
calculation of emissions from stuck dump valves for produced water
tanks using any of the three calculation methodologies and only require
calculation and reporting of emissions from hydrocarbon liquid stuck
dump valves per 40 CFR 98.233(j)(5).
Comment: Several commenters noted burden associated with collection
of
[[Page 42093]]
pressurized liquid samples and other measurements from produced water
storage tanks. Additionally, one commenter recommended allowing
operators to assume that produced water tanks contain 1 percent of the
oil content. They noted that this would allow for consistency with
Texas Commission on Environmental Quality (TCEQ) Emissions
Representation for Produced Water guidance,\29\ which describes that
oil or condensate floats on top of the water phase and contributes to
the partial pressure within the tank.
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\29\ Emission Representations for Produced Water. Texas
Commission on Environmental Quality. Available at: https://www.tceq.texas.gov/assets/public/permitting/air/NewSourceReview/oilgas/produced-water.pdf and in the docket for this rulemaking,
Docket ID. No. EPA-HQ-OAR-2023-0234.
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Response: The EPA is finalizing a revision from the proposal for a
reduced frequency schedule for composition and Reid vapor pressure
sampling and analysis from each well, separator, or non-separator
equipment. Reporters must sample and analyze hydrocarbon liquids or
produced water composition and Reid vapor pressure at least once every
5 years. Additional details are provided in section III.K.5. of this
preamble.
Additionally, for produced water tanks, the EPA recognizes that
industry standard is to assume one percent oil entrainment for produced
water.30 31 The premise behind the one percent assumption is
that entrainment from upstream separation introduces hydrocarbon
liquids into the produced water tank. This entrained material forms a
layer of hydrocarbons that float on top of the water in the tank and is
expected to increase total emissions, and the EPA recognizes that it is
technically challenging to accurately measure the entrained oil content
in the water fed to the tank. Thus, facilities often use the produced
water flowrate and the composition of the associated hydrocarbon
streams when performing the flash emission calculations. Flash
emissions from produced water tanks are then determined by multiplying
the flash emission calculation results by one percent.
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\30\ Id.
\31\ Are Produced Water Emission Factors Accurate? Bryan
Research & Engineering, Inc. Available in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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The EPA agrees with requests from commenters that one percent
entrainment is an acceptable assumption to represent flashing emissions
from produced water tanks given the difficulty with accurately
quantifying oil entrainment in produced water. We are therefore adding
language in 40 CFR 98.233(j)(1)(vii) and 40 CFR 98.233(j)(2)(i) of the
final rule that for produced water composition, reporters may elect to
use a representative hydrocarbon liquid composition and assume oil
entrainment of 1 percent or greater rather than collecting a produced
water sample every 5 years.
4. Mud Degassing
a. Summary of Final Amendments
The EPA is adding a new emission source type to subpart W for
emissions from drilling mud degassing. The term ``drilling mud,'' also
referred to as ``drilling fluid,'' refers to a class of viscous fluids
used during the drilling of oil and gas wells. As drilling mud
circulates through the wellbore, natural gas and heavier hydrocarbons
can become entrained in the mud. Mud degassing refers to the practice
of extracting the entrained gas from drilling mud once it is outside
the wellbore. The new provisions add calculation and reporting
requirements for CH4 emissions from mud degassing associated
with well drilling for onshore petroleum and natural gas production
facilities in 40 CFR 98.232(c), 98.233(dd), and 98.236(dd). In
addition, several new definitions for terms related to mud degassing
are being added to 40 CFR 98.238. The EPA is only requiring the
reporting of CH4 emissions from this source because
CH4 is the primary GHG emitted from this source, while
emissions of CO2 are expected to be very small.
The EPA is finalizing the revision to 40 CFR 98.232(c) as proposed,
and the revisions to 98.233(dd) and 98.236(dd) with changes to those
proposed, including the addition of a third calculation method that
must be used in certain circumstances and corresponding reporting
requirements, so that reporters have three calculation methods that
apply as specified in those provisions to calculate emissions from mud
degassing in new 40 CFR 98.233(dd).
More specifically, the final provision includes two important
changes from proposal for the requirement to use Calculation Method 1
when the reporter has taken mudlogging measurements. First, the final
rule adds the further qualification that Calculation Method 1 is
required when measurements are taken once the first hydrocarbon bearing
zone has been penetrated until drilling mud ceases to be circulated in
the wellbore, because natural gas is unlikely to become entrained in
drilling fluids until the first hydrocarbon zone is penetrated. Second,
the final rule adds that Calculation Method 1 is required when gas-trap
derived gas concentration from mudlogging measurements is reported in
parts per million (ppm) or is reported in units from which ppm can be
derived.
Additionally, the final Calculation Method 1 includes several
additional changes from proposal. We have replaced the term ``at the
same approximate depth'' with ``within the equivalent stratigraphic
interval'' to use more widely recognized geologic terminology and to
recognize that formation properties are more directly related to
stratigraphy than to depth below surface. We are also adding this term
to 40 CFR 98.238, Definitions, and defining the term as ``the depth of
the same stratum of rock in the Earth's subsurface.'' Other changes to
Calculation Method 1 include clarifications in the definitions of
``Tr'' in equations W-41 and W-42, and ``Tp'' in
equation W-43 to specify that total time that drilling mud is
circulated in the well begins with initial penetration of the first
hydrocarbon-bearing zone rather than when the well is spudded at the
surface, and until drilling mud ceases to be circulated in the
wellbore. We are also amending the term Xn in equation W-41
to be the ``average'' gas concentration. The use of the average gas
concentration should ensure consistency with the use of the average mud
rate in equation W-41 and result in emissions calculations that are
representative of average conditions throughout the drilling cycle.
Consistent with the proposal, the final Calculation Method 1
requires the reporter to calculate CH4 emissions and a
CH4 emissions rate from mud degassing for a representative
well and then to apply that rate to other wells in the sub-basin and
within the equivalent stratigraphic interval. To qualify as a
representative well, we are finalizing that the well is required to be
drilled in the same sub-basin and within the equivalent stratigraphic
interval from the surface (instead of at the same approximate total
depth, as proposed) as the wells for which it is representative.
Under the final provisions, as proposed, the operator is required
to identify and calculate natural gas emissions for a representative
well at least once every 2 years for each sub-basin and equivalent
stratigraphic interval within the facility to ensure that the emissions
from representative wells are representative of the operating and
drilling practices within each applicable sub-basin in the facility. In
the first year of reporting, however, the operator may use measurements
from the prior
[[Page 42094]]
reporting year if measurements from the current reporting year are not
available.
Under the final provisions, if mudlogging measurements were not
taken or were taken but did not produce gas concentration in ppm or in
units from which ppm can be derived, reporters must use Calculation
Method 2 to determine emissions from mud degassing using equation W-44,
which incorporates the nationwide emission factors provided by the
CenSARA study.\32\ Specifically, emissions are calculated using an
emission factor of 0.2605 mt CH4 per drilling day per well
for water-based mud and a factor of 0.0586 mt CH4 per
drilling day per well for oil-based and synthetic drilling muds. After
consideration of comments, the EPA is finalizing Calculation Method 2
with two notable changes from the proposal. The final equation W-44 now
includes an adjustment to local conditions by taking the ratio of the
local CH4 mole fraction, which will consist of the average
mole fraction of CH4 in produced gas for the sub-basin
reported under 40 CFR 98.236(aa)(1)(ii)(I), (XCH4), to the
nationwide mole fraction of 83.35 used to derive the emission factors.
This adjustment for local conditions will more accurately reflect
facility-specific emissions compared to relying solely on nationwide
emission factors as originally proposed. The second change affects the
number of drilling days, DDp, in equation W-44. Entrainment
of gas in drilling mud and resulting emissions are unlikely if mud is
not circulating, which can occur for many reasons during the drilling
of a well; for example, if drilling ceases due to a well workover,
implementation of health and safety protocols, equipment failure, or
for other reasons. Therefore, in the final rule, the number of drilling
days used in equation W-44 is the actual number of days drilling mud is
circulated in the wellbore.
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\32\ 2011 Oil and Gas Emission Inventory Enhancement Project for
CenSARA States. Produced by ENVIRON International Corporation for
Central States Air Resources Agencies. November 2011. Available at
https://www.deq.ok.gov/wp-content/uploads/air-division/EI_OG_Final_Report_CenSara_122712.pdf and in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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In addition to the two calculation methods that were proposed, we
are finalizing Calculation Method 3, which must be used when mudlogging
measurements are taken during some, but not all, of the time the well
bore has penetrated the first hydrocarbon bearing zone and until
drilling mud ceases to be circulated in the wellbore. Under Calculation
Method 3, Calculation Method 1 must be used to calculate emissions for
the cumulative amount of time mudlogging measurements were taken and
Calculation Method 2 must be used for the cumulative amount of time
mudlogging measurements were not taken. The emissions derived from each
are added together for Calculation Method 3.
In addition to the calculation requirements, the EPA is finalizing
corresponding reporting requirements for emissions by well in 40 CFR
98.236(dd) as proposed, except that reporters using Calculation Method
1 must report the target hydrocarbon-bearing stratigraphic formation to
which the well is drilled in addition to the total vertical depth of
the well to allow for adequate verification of reported mud degassing
emissions. We have added a definition for target hydrocarbon-bearing
stratigraphic formation in 40 CFR 98.238 to mean the stratigraphic
interval intended to be the primary hydrocarbon producing formation.
The final reporting requirements for mud degassing also include
reporting requirements for reporters using Calculation Method 3, which
require the reporter to indicate if this method was used and to report
the required Calculation Method 1 data elements for the time periods
when Calculation Method 1 was used and the required Calculation Method
2 data elements when Calculation Method 2 was used.
The other change from the proposed reporting requirements affects
several data elements in Calculation Method 1, based on the EPA's
review and consideration of public comments. The EPA proposed that all
of the Calculation Method 1 data elements identified as inputs to
emission equations should be directly reported without a 2-year delay.
In the final rule, there are several Calculation Method 1 inputs to
emission equations for which reporting may be delayed by 2 years.
Specifically, the Average concentration of natural gas in the drilling
mud (Xn), the Measured mole fraction of CH4 the
natural gas (GHGCH4), and the Total time that drilling mud
is circulated in the well (Tr in equations W-41 and W-42 and
Tp in equation W-43) are eligible for the 2-year delay for
any well that is a wildcat and/or delineation well. The 2-year delay is
also available for the Average mud rate (MRr) and the
Calculated CH4 emissions rate (ERsCH4,r) when one
or more wells to which the calculated CH4 emissions rate for
the representative well (ERs,CH4,r in equation W-42) is
applied is a wildcat and/or delineation well. In addition, reporting of
the Total time that drilling mud is circulated in the well (Tr in
equations W-41 and W-42) may be delayed for 2 years for the
representative well if one or more wells to which the calculated
CH4 emissions rate for the representative well
(ERs,CH4,r in equation W-42) is applied is a wildcat and/or
delineation well. Wildcat and delineation wells are considered
exploratory wells in the oil and gas industry, and data from these
wells are generally considered sensitive information by the industry.
State oil and gas commissions commonly hold such data from public
release for two years. Therefore, the EPA has determined that these
inputs to emission equations should be directly reported but are
subject to a 2-year delay for exploratory wells to acknowledge the
sensitive nature of the data and to ensure that the data cannot be back
calculated prior to the end of the 2-year delay. However, we emphasize
that this information would be considered to be emission data under CAA
section 114 that is not eligible for confidential treatment upon
submission to the agency, and thus will be made available to the public
upon submission. Furthermore, emissions from any well with well
degassing must still be reported annually and we further note that we
have other information that will allow verification of reported
emissions. Moreover, the EPA intends to be diligent in reviewing and
reconciling delayed data with reported emissions data, and we also
stress that, although the delayed data may not be reported in the
initial reporting year, reporters must maintain records supporting
their emission calculations and these records are subject to review by
the EPA. Finally, the EPA intends to further evaluate whether this
information will be required and, if so, may require reporting without
delay in a future rulemaking.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to add mud degassing as an emission source for
onshore petroleum and natural gas production facilities.
Comment: Some commenters supported the addition of mud degassing as
a source, while other commenters questioned the inclusion of mud
degassing as an emissions source of CH4 and CO2,
stating that the EPA has not taken due account of the difficulties and
costs associated with measuring methane emissions from drilling mud
degassing. In addition, one commenter suggested that the EPA has not
considered the ability of reporters to
[[Page 42095]]
accurately capture such emissions as required by the IRA. The
commenters recommended that the EPA not finalize mud degassing in
subpart W.
Response: At this time, we agree with the commenters that
CO2 emissions are unlikely to be significant from this
source, and the EPA did not propose and is not finalizing requirements
to calculate and report CO2 emissions from drilling mud
degassing in this final rule. Under the final provisions, only
CH4 emissions will be reported for drilling mud degassing
from the onshore production segment as the EPA considers mud degassing
to be a potentially significant source of CH4 emissions from
the onshore production segment. Several notable guidelines on oil and
gas emission sources include mud degassing emissions as a source of GHG
emissions and provide calculation methods for estimating mud degassing
emissions from the onshore production segment, including API, the
Central States Air Resources Agencies (CenSARA), and the New York State
Energy Research and Development Authority (NYSERDA). The EPA further
notes that CenSARA and NYSERDA guidelines use the same emission
factors, which are based on a paper published by the EPA in 1977
entitled ``Atmospheric Emissions from Offshore Oil and Gas Development
and Production.'' This paper estimated two total hydrocarbon (THC)
emission factors (EFs), for water-based mud and oil-based mud
degassing. Thus, we believe that it should be included as an emissions
source in reporting for the onshore production segment to best ensure
accurate reporting of total methane emissions from the facilities. We
are, therefore, finalizing that onshore production reporters are
required to report CH4 emissions from drilling mud
degassing.
Regarding the commenter's assertion that the EPA has not considered
the ability of reporters to accurately capture such emissions, we note
that when proposing and finalizing the rule, the EPA considered the
potential challenges associated with taking measurements from mud
degassing. We understand that field and operational conditions may
impact a reporter's ability to take measurements at the well site or
there may be instances when mud logging is not used. Consistent with
the proposal, the final rule does not require measurement of
CH4 emissions from mud degassing, but only that measured
data be used to calculate emissions using Calculation Method 1 if
measurements are taken. When measurement data are not available, the
proposed and final rule provide additional flexibility by allowing
reporters to use the engineering equations in Calculation Method 2 with
default emission factors for oil-based, water-based and synthetic
drilling muds. In addition, as discussed in the response to comments
later in this section, the EPA is providing additional flexibility by
finalizing a new Calculation Method 3, which requires use of
Calculation Method 1 when mudlogging measurements are taken at
intermittent time periods during mud circulation while requiring use of
Calculation Method 2 for those time intervals when mudlogging
measurements are not taken.
Comment: The EPA received several comments requesting clarification
of the term ``same approximate total depth'' as it was used in the
proposed rule for Calculation Method 1 and how to determine same
approximate depth.
Response: The EPA agrees with the commenters that the term ``same
approximate total depth'' as used in the proposed rule could be further
clarified. We are finalizing the rule with the term ``equivalent
stratigraphic interval'' instead of the proposed term ``same
approximate total depth'' to provide more certainty to the meaning of
the term. ``Equivalent stratigraphic interval'' is a term and concept
that should be familiar to professionals in the oil and gas industry
and others with a basic understanding of geology. It refers to the
depth to a specific layer of rock in the Earth's subsurface. Since the
depth of a specific strata can vary due to ground elevation, layer dip,
or subsurface discontinuities, it is often useful to refer to the
equivalent stratigraphic interval as opposed to true vertical depth,
sub-sea depth or more general terms including approximate depth. More
importantly, it clearly reflects the intent of the regulations in using
this term, which is to measure and apply the emissions rate from a
representative well to all others in the same producing formation. We
also note that stratigraphic depth can be correlated with geophysical
data such as seismic data. Additionally, the term ``equivalent
stratigraphic interval'' is defined in the final rule as ``the depth of
the same stratum of rock in the Earth's subsurface.'' In the final
provisions, we have replaced ``same approximate total depth'' with
``equivalent stratigraphic interval'' where the term appeared in 40 CFR
98.233(dd) and 98.236(dd) of the proposed rule. In addition, we added
the definition of equivalent stratigraphic interval to 40 CFR 98.238,
Definitions. Complimentary to this change, in 40 CFR 98.236(dd)(1) of
the final rule we are requiring reporters to report the target
hydrocarbon-bearing stratigraphic formation for each well, including
the representative well, when Calculation Method 1 is used. We have
also added a definition for this term in 40 CFR 98.238 to mean the
stratigraphic interval intended to be the primary hydrocarbon producing
formation. This reporting requirement will allow for adequate
verification of mud degassing emissions.
Comment: Commenters stated that the EPA has proposed that operators
must use mudlogging measurements taken during the reporting year, and
therefore calculate emissions using Methodology 1. The commenters
disagreed with this requirement, claiming that it is possible a
mudlogging measurement is taken at the very early stages of a drilling
operation, and that measurement may not ultimately be reflective of the
entire duration of the drilling operation. The commenters recommended
allowing reporters to use Calculation Method 2 for all active drilling
and proposed a third option in the event that some mudlogging data is
available. Commenters stated that the third option would allow
operators to use a combination of the two methodologies when a varying
level of directly measured data is available. Commenters stated that,
in this third option, mudlogging measurements would be used based on
Method 1 for the period in which the data are available, and Method 2
would be used for the remaining period of drilling activity where
mudlogging data are not available.
Response: The EPA did not propose that operators must use
mudlogging equipment, only that if mudlogging equipment is used then
reporters must use Calculation Method 1 and this approach is adopted in
the final rule. In response to a comment that is addressed later in the
preamble, we are providing additional clarity in the final rule with
respect to applicability of Calculation Method 1. The final rule adds
that Calculation Method 1 is required when reporters have taken
mudlogging measurements, including mud pumping rate and gas trap-
derived gas concentration that is reported in parts per million (ppm)
or is reported in units from which ppm can be derived. Consistent with
the proposal, the final rule requires the reporter to use emission
factors if mudlogging measurements are not taken.
The EPA also disagrees with the commenter that mudlogging
measurements are not representative of the drilling cycle because they
may only be taken at the early stages of drilling. Proposed equation W-
41 used the average mud rate for the representative
[[Page 42096]]
well, r, in gallons per minute, rather than a single point measurement
to determine methane emissions from mud degassing. In considering this
comment, however, the EPA determined that the definition of the term
Xn in equation W-41 should be the ``average'' gas
concentration in the drilling mud as measured by the gas trap, in parts
per million (adding ``average'' to the proposed term in the final
equation). The final provisions to use the average gas concentration
should ensure consistency with the use of the average mud rate
(MRr), resulting in emissions calculations that are based on
average measurements that allow for fluctuations in concentrations and
flows inherent in field operations.
The EPA disagrees with the commenter's suggestion that all
reporters be allowed to use Calculation Method 2 regardless of whether
mudlogging was performed for at least one well. Consistent with CAA
section 136(h), the overall intent of this rulemaking is for reporting
to be based on empirical data and have greater accuracy of total
emissions data from facilities. Therefore, the final provisions include
a modification from proposal to require that reporters use Calculation
Method 1 if they take mudlogging measurements for the entire time
period from the penetration of the first hydrocarbon bearing zone until
drilling mud ceases to be circulated in the wellbore. This requirement
applies only if the mudlogging measurements provide a gas concentration
in ppm or in units from which ppm can be derived. If a reporter does
not use mudlogging, then reporters must use the emission factors in
Calculation Method 2. After considering this comment, the EPA is
finalizing a third method that requires operators to use a combination
of the two methodologies when a varying level of directly measured data
is available. For example, where mudlogging was only used at certain
intervals during drilling an individual well, the third method would
apply and the reporter would use Calculation Method 1 during those
intervals while applying Calculation Method 2 to the other drilling
periods. The EPA is finalizing this hybrid method as a new Calculation
Method 3 in 40 CFR 98.233(dd)(3), that requires use of Calculation
Method 1 when mudlogging measurements are available and use of
Calculation Method 2 for the remaining period of drilling activity
where mudlogging data is not available.
Comment: Commenters requested that the EPA clarify that the total
time that drilling mud is circulated in the representative well in
Calculation Method 1 should be calculated based on circulating time in
the hydrocarbon bearing zones only (i.e., excluding surface holes
drilled by a spudder rig when no hydrocarbons are present).
Response: The EPA agrees that the final definition of Tr
and Tp in Calculation Method 1, ``Total time that drilling
mud is circulated in the representative well in minutes,'' should be
amended from proposal to reflect that time of mud circulation in
equations W-41, W-42, and W-43 does not begin until the first
hydrocarbon-bearing zone is penetrated by the well bore. This change is
consistent with the first day of drilling days, DDp, in
Calculation Method 2, which is the first day that the borehole
penetrated the first hydrocarbon-bearing zone. The final rule reflects
these changes from proposal to Calculation Method 1.
The EPA disagrees with the suggestion to clarify that ``total time
that drilling mud is circulated in the representative well'' should be
calculated based on circulating time in the hydrocarbon bearing zones
only. Hydrocarbons can still become entrained in drilling mud even
after the well bore moves out of the hydrocarbon-bearing zone. The use
of an average mud rate and average natural gas concentration combined
with the change from proposal just described, to only consider the
start of mud circulation to be the time when the first hydrocarbon zone
is penetrated, should appropriately address the commenter's concerns.
Comment: Commenters stated that a further complication of the
proposed method for quantifying methane emissions from drilling mud
degassing is that the concentration of natural gas (or methane) in
drilling mud is not currently specifically measured and is difficult to
obtain. Further, commenters stated it is not measured by mud loggers in
units of ppm, as the measurement instrument used is in units that are
not representative of methane concentration.
Response: The EPA acknowledges that some mudlogging equipment may
use units that are not convertible to ppm. Therefore, we have further
qualified the use of Calculation Method 1 to be required if you have
taken mudlogging measurements from the penetration of the first
hydrocarbon bearing zone until drilling mud ceases to be circulated in
the wellbore, including mud pumping rate and gas trap-derived gas
concentration that is reported in parts per million (ppm) or is
reported in units from which ppm can be derived. We further note that
reporters must use Calculation Methodology 2 emission factors if they
do not take mud logging measurements as described above. The EPA
disagrees that the concentration of natural gas in drilling mud is not
specifically measured and is difficult to obtain. Mudlogging equipment
capable of measuring gas concentration and in ppm is available. Even
when other available mudlogging equipment does not produce data in
these units, the mudlogging equipment may use specific units based on
their sensors and calibration that are convertible to percent or ppm.
Therefore, the final rule retains the requirement to use these
measurements when available under Calculation Method 1 or Calculation
Method 3.
Comment: Commenters expressed concern that the proposed emission
factors in Calculation Method 2 are dated and based on offshore wells.
Commenters suggested that the EPA instead adopt emission factors for
drilling mud degassing in the American Petroleum Institute's (API)
Compendium.\33\ Commenters also expressed concern that the proposed
rule did not allow for adjustments to emission factors in Calculation
Method 2 based on local conditions. Commenters noted that mud weight is
critical in controlling formation pressure and the flow of hydrocarbons
into the well bore during the drilling process and the various methods
do not account for this. A commenter also suggested that the emission
factors should be derived as a function of well dimensions to better
represent mud degassing emissions. The commenter stated that,
otherwise, proposed Calculation Methodology 2 should be revised based
on drilling time in the hydrocarbon hole section, and not overall event
days. The commenter stated that there can be multiple days in a
hydrocarbon hole section where the pumps are not circulating.
---------------------------------------------------------------------------
\33\ Compendium of Greenhouse Gas Emissions Methodologies For
The Natural Gas And Oil Industry. Produced by URS Corporation for
American Petroleum Institute. November 2021. Available at https://www.api.org/-/media/files/policy/esg/ghg/2021-api-ghg-compendium-110921.pdf. Available in the docket for this rulemaking, Docket ID.
No. EPA-HQ-OAR-2023-0234.
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Finally, a commenter noted that the EPA proposes to define the
number of drilling days differently than the CenSARA study. The
commenter stated that rather than considering the first drilling day to
be the day the well is spudded, the EPA proposed that the total number
of drilling days is the sum of all days from the first day that the
borehole penetrates the first
[[Page 42097]]
hydrocarbon-bearing zone through the completion of all drilling
activity.
Response: In proposing emission factors for drilling mud degassing,
the EPA considered the sources available with published emission
factors. As the commenter notes, API does include emission factors in
Section 6.2.1 of its Compendium of Greenhouse Gas Emission
Methodologies for the Natural Gas Industry. The API emission factors
are lower than those included in the CenSARA guidelines; however, the
factors are based on API member comments on a letter from API submitted
to the EPA in 2020 with respect to mud degassing emission factors being
considered for the U.S. Inventory of Greenhouse Gas Emissions. See
Section 6.2.1 of the API Compendium. The commenter has not submitted
documentation to support the recommended emission factors other than
reference to the API Compendium based on API member comments. This does
not allow the EPA to further investigate the derivation of the API
emission factors. In contrast, the basis for emission factors used in
the CenSARA and NYSERDA guidelines is a 1977 study by the EPA's Office
of Air Quality Planning and Standards, which derived emission factor
based on engineering equations. The methodology is public and has been
subject to review. We acknowledge that the factors are based on
offshore operations; however, we believe they present a reasonable
approximation of onshore emissions. We note that the final rule
provides reporters with the option to take site-specific measurements
and use measured data if they do not believe the emission factors,
adjusted for local conditions, accurately represent emissions from mud
degassing from their wells. Therefore, our assessment of the available
information is that the proposed emission factors (from the published
CenSARA study) are appropriate and we are including them in the final
provisions.
For Calculation Method 2, the EPA generally agrees with the
commenter that adjustment for local conditions may more accurately
reflect emissions at the facility than reliance solely on nationwide
emission factors. The CenSARA guidelines allow for local adjustment of
CH4 emissions by applying the ratio of the measured
CH4 mole fraction to the mole fraction used to develop the
emission factor, 83.85,\34\ although the guidelines do not specify how
the measurement is derived. The EPA believes allowing for adjustment to
local conditions is a reasonable approach when using an emission factor
and is finalizing the rule with such an adjustment from proposal to
Calculation Method 2. Specifically, we are adding two data inputs to
equation W-44. The first is XCH4, which is the
CH4 mole fraction in the sub-basin. The CH4 mole
fraction used in equation W-44 will be the mole fraction for the sub-
basin as reported for the onshore production facility in 40 CFR
98.236(aa)(ii) because, for a reporter using Calculation Method 2, the
reporter has not taken mudlogging measurements including gas
concentration. The second data input is the nationwide CH4
mole fraction of 83.85. Reporters using Calculation Method 2 will
multiply the number of drilling days by the appropriate emission factor
as defined in equation W-44. That value will then be multiplied by the
ratio of XCH4 to 83.35 to derive emissions from mud
degassing.
---------------------------------------------------------------------------
\34\ See page 86 of 2011 Oil and Gas Emission Inventory
Enhancement Project for CenSARA States. Produced by ENVIRON
International Corporation for Central States Air Resources Agencies.
November 2011. Available at https://www.deq.ok.gov/wp-content/uploads/air-division/EI_OG_Final_Report_CenSara_122712.pdf and in
the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------
The EPA disagrees with the commenters that mud weight should be
considered in the emission factors in Calculation Method 2 and in
Calculation Method 1. Calculation Method 1 effectively takes mud weight
into account because it uses direct measurement. For example, if mud
weight is high, or overbalanced, the amount of gas entering the mud
stream is reduced and the average gas concentration will decrease. If
mud weight is low, or underbalanced, the gas concentration in the
drilling mud will increase. For Calculation Methodology 2, none of the
available methodologies identify the mud weight used to determine the
emission factors; therefore, it is not possible to modify the emission
factors by applying a specific mud weight to the emission factor.
Separate emission factors for water-based, oil-based and synthetic
drilling muds should address the commenters' concern.
The EPA does not agree with the commenter's suggestion for
Calculation Method 2 to consider well dimensions to better represent
mud degassing emissions. Well dimensions alone do not determine the
quantity of emissions that may result from mud degassing. Use of
separate emission factors for water-based, oil-based and synthetic muds
and allowing use of site-specific CH4 mole fractions provide
flexibility to develop more site-specific emissions for mud degassing
using Calculation Method 2. However, the EPA does agree with the
commenter that the definition of drilling days, DDp, in
equation W-44 should be revised to reflect the actual number of days
drilling mud is circulated in the wellbore. This change is consistent
with how the EPA defines the last drilling day, which is the day
drilling mud ceases to be circulated in the wellbore. Entrainment of
gas in drilling mud and resulting emissions are unlikely if mud is not
circulating. There are many reasons why an operator may stop mud
pumping on a well site including mechanical reasons, well workovers,
health and safety issues, and other reasons.
With respect to the number of drilling days in Calculation Method 2
and the comment that the EPA had changed the start of drilling days
from CenSARA definition (which is the date the well is spudded), the
EPA proposal intended to add clarity to Calculation Method 2 by
proposing the first drilling day as the day that the borehole
penetrated the first hydrocarbon-bearing zone and the last drilling day
is the day drilling mud ceases to be circulated in the wellbore. The
objective of the proposal was to more accurately calculate emissions
using Calculation Method 2 by limiting the number of days multiplied by
the emission factor to the days when mud is actually circulating in
hydrocarbon-bearing zones when the potential for gas entrainment
exists. If spudding is the standard for determination of the first day,
this may add days to the emissions calculation when CH4 is
not actually entrained in the mud. Likewise, including days when the
drill bore is retreating and mud is no longer circulating would include
additional days in Calculation Method 2 when there is no potential for
CH4 to become entrained in the mud. Together these
assumptions would overestimate emissions. Therefore, we are finalizing
the definition of ``total number of drilling days'' as proposed except
for the change that drilling days are further defined as the days when
drilling mud is circulated in the wellbore.
Comment: Several commenters indicated that wells subject to
reporting under this source are often wildcat or delineation wells,
and, as such, should be subject to confidentiality or a delay in
reporting.
Response: After further review, we agree with the commenters that
many wells where drilling mud is used are exploratory wildcat or
delineation wells. After consideration of this comment, we are
finalizing the reporting requirements for Calculation Method 1 to
provide a 2-year delay in
[[Page 42098]]
reporting certain data elements for all wells reported using
Calculation Method 1 if the well is a wildcat or delineation well.
Specifically, the Average concentration of natural gas in the drilling
mud (Xn in equation W-41), in parts per million, the
Measured mole fraction for CH4 in natural gas entrained in
the drilling mud (GHGCH4 in equation W-41), and the Total
time that drilling mud is circulated in the well (Tr in
equations W-41 and W-42 and Tp in equation W-43) are eligible for the
2-year delay for any well that is a wildcat and/or delineation well. In
addition, the following data elements are eligible for the 2-year delay
when one or more wells to which the calculated CH4 emissions
rate for the representative well (ERs,CH4,r in equation W-
42) is applied is a wildcat and/or delineation well: the Average mud
rate (MRr) and the Calculated CH4 emissions rate
(ERsCH4,r). Reporting of the Total time that drilling mud is
circulated in the well (Tr in equations W-41 and W-42) for the
representative well may also be delayed for 2 years if one or more
wells to which the calculated CH4 emissions rate for the
representative well (ERs,CH4,r in equation W-42) is applied
is a wildcat and/or delineation well. Wildcat and delineation wells are
considered exploratory wells in the oil and gas industry, and data on
these wells are generally considered sensitive information by the
industry. State oil and gas commissions commonly hold such data from
public release for two years. Therefore, the EPA has determined that
these inputs to emission equations should be directly reported but are
subject to a 2-year delay for exploratory wells to acknowledge the
sensitive nature of the data and to ensure that the data cannot be back
calculated prior to the end of the 2-year delay. However, we emphasize
that this information would be considered to be emission data under CAA
section 114 that is not eligible for confidential treatment upon
submission to the agency, and thus will be made available to the public
upon submission. Furthermore, emissions from any well with well
degassing must still be reported annually and we further note that we
have other information that will allow verification of reported
emissions. Moreover, the EPA intends to be diligent in reviewing and
reconciling delayed data with reported emissions data, and we also
stress that, although the delayed data may not be reported in the
initial reporting year, reporters must maintain records supporting
their emission calculations and these records are subject to review by
the EPA. Finally, the EPA intends to further evaluate whether this
information will be required and, if so, may require reporting without
delay in a future rulemaking.
Comment: Several commenters did not support the proposed
requirement in 40 CFR 98.236(dd) to report certain data elements when
using Calculation Method 1 to calculate emissions from mud degassing.
Specifically, the commenters disagreed with reporting total vertical
depth of the well and the circulation time of the drilling mud within
the wellbore stating that the EPA did not address why the information
would be requested. They further noted that in the case of total
vertical depth, the reported data would not provide representative
information for horizontal wells and would not improve the reported
data quality.
Response: The EPA disagrees with the commenter that total vertical
depth and mud circulation time should not be reported for Calculation
Method 1 in 40 CFR 98.236(dd). Although formations dip and well to well
correlations are sometimes subject to discontinuities, total vertical
depth combined with identification of the stratigraphic formation
provides a reasonable assurance that wells are drilled into the same
hydrocarbon producing formations. Consistent with the change in
Calculation Method 1 to apply the emissions rate from the
representative well to other wells in the same sub-basin drilling in
the same stratigraphic interval versus the same approximate depth, the
EPA has added a reporting requirement to 40 CFR 98.236(dd) in the final
rule to require reporters using Calculation Method 1 to also report the
target hydrocarbon-bearing stratigraphic formation to which the well is
drilled in addition to the total vertical depth. In response to the
commenters' concerns about the requirement to report the total time
that drilling mud is circulated in the well, this data element is
necessary for the EPA to verify the reported CH4 emissions
using Calculation Method 1. Based on consideration of public comment
and further research, however, we are finalizing that total time
drilling mud is circulated in the well and other data elements in
Calculation Method 1 are eligible for a 2-year delay for wildcat and
delineation wells. See the response to the comment above for additional
information.
5. Crankcase Venting
a. Summary of Final Amendments
The EPA is finalizing with revisions from proposal, as discussed
further in this section, the addition of crankcase venting as a new
emission source to be reported under 40 CFR 98.236(ee) by facilities in
the Onshore Petroleum and Natural Gas Production, Onshore Natural Gas
Processing, Onshore Natural Gas Transmission Compression, Underground
Natural Gas Storage, LNG Storage, LNG Import and Export Equipment,
Natural Gas Distribution, and Onshore Petroleum and Natural Gas
Gathering and Boosting industry segments. The EPA is finalizing with
revisions from proposal, as discussed further in this section,
methodologies for calculating emissions from crankcase venting under 40
CFR 98.233(ee). We are also finalizing as proposed revisions to 40 CFR
98.232 to include crankcase venting reporting requirements for the
appropriate industry segments.
The EPA is finalizing with revisions from proposal the definition
of crankcase venting under 40 CFR 98.238, with a clarification that an
ingestive system may include, but is not limited to, closed crankcase
ventilation systems and closed breather systems. We also are specifying
in the revised definition that crankcase venting does not include vents
where emissions are routed to another closed vent system, since these
emissions are not released to the atmosphere. Further, following
consideration of comments received, we are stating in the introductory
paragraph of 40 CFR 98.233(ee) that crankcase venting emissions must
only be calculated and reported for RICE with a rated heat capacity
greater than 1 million British thermal units per hour (MMBtu/hr) (or
the equivalent of 130 horsepower), which is consistent with the RICE
combustion emissions reporting threshold under 40 CFR 98.236(z). We are
also making revisions from proposal, after consideration of comments,
to 40 CFR 98.233(ee) and 40 CFR 98.236(ee) to remove gas turbines from
the final source types subject to crankcase venting emissions
reporting.
Regarding revisions from proposal to the final methodologies for
calculating emissions from crankcase venting under 40 CFR 98.233(ee),
following consideration of comments received and consistent with
section II.B. of this preamble, we are adding a direct measurement
option for crankcase venting emissions as Calculation Method 1.
Specifically, we are splitting the proposed 40 CFR 98.233(ee) into two
paragraphs, with 40 CFR 98.233(ee)(1) for the added direct measurement
option (final Calculation Method 1) and 40 CFR 98.233(ee)(2) for the
final emission factor method (final Calculation Method 2, which we
proposed under 40 CFR 98.233(ee),
[[Page 42099]]
equation W-45) with modifications from proposal.
For the final Calculation Method 1 in 40 CFR 98.233(ee)(1), we are
allowing the use of screening methods in 40 CFR 98.234(a) to determine
whether quantitative emissions measurements are needed, similar to the
rod packing methodologies for reciprocating compressors under 40 CFR
98.233(p). If emissions are detected using the screening methods, which
for purposes of this calculation method are considered detected
whenever a leak is detected according to the screening method used,
direct measurement must be used to determine CH4 emissions
using the following technologies for conducting direct measurement of
crankcase vent emissions: high volume samplers, meters (such as
rotameters, turbine meters, hot wire anemometers, and others), or
calibrated bags, in accordance with the methods in 40 CFR 98.234(b)
through (d). If no emissions are detected during screening, then the
reporter may assume that the volumetric emissions from the crankcase
vent are zero. If a reporter elects to conduct screening and direct
measurement of crankcase vents, all operating engines at the time of
screening must then be screened at the facility, well-pad site, or
gathering and boosting site at least once annually. Under the final
Calculation Method 1, the reporter must then use equation W-45 under 40
CFR 98.233(ee)(1)(iv) to calculate the annual volumetric CH4
emissions calculation for each RICE that was measured during the
reporting year. We are also adding clarification to the final rule for
reporters with crankcase vents tied into a manifolded group under 40
CFR 98.233(ee)(1)(iii). Under the final provisions for Calculation
Method 1, if the manifolded group contains only crankcase vent sources,
reporters must divide the measured volumetric flow equally between all
operating RICE. Additionally, under the final provisions for this
methodology, if the manifolded group contains crankcase vent sources
and compressor vent sources, we assume that emissions are being
characterized under 40 CFR 98.233(o) or (p) and should be reported
under 40 CFR 98.236 (o) or (p), as applicable. We are also adding under
40 CFR 98.236(ee)(2) several reporting requirements for crankcase vent
emissions calculated through direct measurement under 40 CFR
98.233(ee)(1), as well as a reporting requirement under 40 CFR
98.236(ee)(1)(v) for the count of reciprocating internal combustion
engines with crankcase vents that were in a manifolded group containing
a compressor vent source with emissions reported under 40 CFR 98.236(o)
or (p).
We are also adding language in the final rule to instruct reporters
who use Calculation Method 1 for calculating volumetric CH4
emissions to use the procedures in 40 CFR 98.233(v) to calculate mass
CH4 emissions. This is standard language in all paragraphs
of 40 CFR 98.233 for emission sources that require volumetric emission
calculations. We are adding this language for consistency with the mass
reporting requirements being finalized in 40 CFR 98.236(ee)(2)(ii).
For the final Calculation Method 2 in 40 CFR 98.233(ee)(2),
including final equation W-46, this method provides a component-level
average emission factor approach for estimating emissions for crankcase
ventilation based on the number of RICE in the facility. The final
provision have been modified from proposal to specify that this
emission calculation should be performed for each RICE with a crankcase
vent that is either not operating at the time of the direct emissions
measurement conducted under 40 CFR 98.233(ee)(1), or at a facility,
well-pad site, or gathering and boosting site where the reporter elects
not to conduct direct emissions measurement on any engines.
Correspondingly, this method is being modified from proposal to be
performed per RICE. For example, where a reporter is using Calculation
Method 2 for RICE with crankcase vents that are manifolded with other
vents or equipment, equation W-46 should be performed for each RICE
with a crankcase vent that is part of the manifold. As equation W-46
will be performed for each RICE, we are changing from proposal the
requirement to report average estimated time that the RICE with
crankcase venting were operational in the calendar year to instead
require total time that each applicable RICE was operational during the
calendar year. We are also changing from proposal the requirement to
report the number of crankcase vents at the well-pad site, gathering
and boosting site, or facility, to instead require reporting of the
number of RICE with crankcase vents that operated at some point in the
calendar year.
After consideration of comments received, the emission factor
provided as part of final equation W-46 is being changed from units of
standard cubic feet whole gas per hour per source to units of kilograms
CH4 per hour per source. We are also revising equation W-46
from proposal to include the unit conversion from kilograms
CH4 to metric tons CH4 for consistency with the
emissions reporting requirements of subpart W.
We are also adding language in the introductory paragraph of 40 CFR
98.233(ee) for the final rule that for reporters with crankcase vents
routed to flares, the CO2, CH4 and N2O
emissions that result from combustion of the crankcase vent stream are
reported as flare stack emissions under 40 CFR 98.236(n). The EPA is
specifying that crankcase vents routed to a flare would follow the
calculation requirements in 40 CFR 98.233(n) and would report flared
crankcase emissions (CO2, CH4, and
N2O) separately from vented crankcase emissions
(CH4). We are finalizing requirements that flared emissions
from crankcase vents are not required to be calculated and reported
separately from other flared emissions. Instead, emission streams from
crankcase vents that are routed to flares are required to be included
in the calculation of total emissions from the flare according to the
procedures in 40 CFR 98.233(n) and reported as part of the total flare
stack emissions according to the procedures in 40 CFR 98.236(n), in the
same manner as emission streams from other source types that are routed
to the flare. See section III.N. of this preamble for more information
on the final flaring calculation and reporting provisions.
We are also finalizing requirements in 40 CFR 98.236(ee)(1) to
report the total number of RICE with crankcase vents at the site
(regardless of vent disposition), the number of these RICE that
operated and were vented to the atmosphere for at least a portion of
the year, and the number of these RICEs that operated and were routed
to a flare for at least a portion of the year. We added a sentence at
40 CFR 98.233(ee) to further clarify these reporting requirements apply
even when emissions from the crankcase vents are required to be
reported under other sources (flares).
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to add crankcase venting as an emission source
for Onshore Petroleum and Natural Gas Production, Onshore Natural Gas
Processing, Onshore Natural Gas Transmission Compression, Underground
Natural Gas Storage, LNG Storage, LNG Import and Export Equipment,
Natural Gas Distribution, and Onshore Petroleum and Natural Gas
Gathering and Boosting facilities.
Comment: Many commenters noted that natural gas turbines do not
have crankcase vents, or an equivalent
[[Page 42100]]
emission source, and thus should be excluded from the crankcase venting
emission source.
Response: The EPA agrees with the commenters that there was an
inadvertent error in including natural gas turbines in the crankcase
venting emission source category. We are finalizing a correction that
will remove references to natural gas turbines from 40 CFR 98.233(ee)
and 40 CFR 98.236(ee).
Comment: Several commenters requested the addition of a direct
measurement option for crankcase vent methane emissions. The commenters
stated that the IRA directs the EPA to include improved subpart W
emission estimates by using empirical data, which they asserted is not
addressed in the proposed crankcase venting. Commenters provided
several different suggestions on how to incorporate direct measurement
into the crankcase venting emission source.
Response: We agree with the commenters that a direct measurement
option for the crankcase venting emission source could be appropriate
and consistent with the directives of CAA section 136 if an appropriate
direct measurement option could be identified. The EPA has considered
all measurement options suggested by commenters, which included
mimicking the measurement requirements of reciprocating and centrifugal
compressors, allowing for site-specific emission factors, and/or
allowing for emissions screening. At this time, we have determined
that, consistent with the provisions for reciprocating compressor rod
packing, a multi-step method for a direct measurement option is
appropriate. Reporters may elect to complete emissions screening and
then, if emissions from the crankcase vent are detected during
screening, a measurement must be taken. If the reporter elects not to
complete emissions screening, then all crankcase vents must be directly
measured from engines operating at the time of the measurement event.
Direct measurements must be taken at least annually on operating
engines. We have also determined that at this time the most appropriate
direct measurement methodologies for the crankcase venting emission
source are provided in 40 CFR 98.234(b) through (d), which allow the
use of an appropriate meter, calibrated bag, or high volume sampler.
Regarding screening methods, we have determined that at this time any
of the methods provided in 40 CFR 98.234(a) are appropriate for
screening except for the acoustic leak detection method in 40 CFR
98.234(a)(5). The acoustic leak detection method is applicable only for
through-valve leakage so it is not applicable to the crankcase vent. We
have included this optional first step screening as an appropriate
approach to reduce burden on those reporters with a significant
quantity of crankcase vents while maintaining accuracy in total
emissions. The EPA is not at this time allowing the option for
reporters to develop site-specific emission factors because this
methodology would require the specification of a minimum number of
measurements that must be taken to be representative and new
restrictions around these measurements, which should be proposed to
allow comments.
Comment: Some commenters requested additional clarification on the
definition of crankcase venting. Specifically, commenters requested
that the EPA update the definition to clarify the term ``ingestive
system,'' as it is more commonly referred to as a closed crankcase
ventilation system or a closed breather system. Further, one commenter
noted that as the EPA excludes crankcase vents that are returned to the
combustion process from the crankcase venting definition, the EPA
should consistently exclude crankcase vents that are routed to another
closed vent system, as this would provide operators more flexibility.
Response: The EPA agrees with the commenters and has clarified the
definition of crankcase venting in 40 CFR 98.238 of the final rule that
an ingestive system may include, but is not limited to, closed
crankcase ventilation systems and closed breather systems.
Additionally, the EPA agrees that routing crankcase vent emissions to
any closed vent system should allow the RICE to be excluded from
reporting crankcase vent emissions and has therefore clarified this
exemption in the crankcase venting definition.
Comment: Some commenters requested the ability to account for
emission controls on crankcase vents. Commenters recommend adding this
flexibility, which they state also has the added impact of
incentivizing controls where feasible.
Response: The EPA agrees that reporters should be able to account
for emission controls on crankcase vents. In the final rule, the EPA
has added to the introductory paragraph of 40 CFR 98.233(ee) that
flared emissions from crankcase vents should be calculated and reported
according to 40 CFR 98.233(n) and 40 CFR 98.236(n), respectively. As
stated above, the EPA has also excluded crankcase vents that route
emissions to another closed vent system, such as a vapor recovery
system, from the definition of crankcase venting. Also as noted above,
the EPA has added a measurement option that will allow reporters to
account for other emission controls on crankcase vents.
Comment: Several commenters noted that the parameter
GHGCH4 in proposed equation W-45 incorrectly requires
reporters to assume that the methane content of the crankcase vent
stream is equivalent the methane content of the gas stream entering the
RICE. They state that the crankcase vent stream can be diluted and may
have a much lower methane content than the methane content of gas
stream entering the RICE or the default value referenced. Commenters
requested the ability to either measure the methane content of the
crankcase gas vent, apply a scaling factor to the CH4
content of the inlet gas, or use best available data to determine the
GHGCH4 parameter.
Response: We agree that the use of the methane content in the gas
stream entering the RICE would produce a conservative estimate of
methane emissions from the crankcase vent. The emission factor upon
which the proposed whole gas emission factor was based was in terms of
THC but it is much more direct to convert this THC emission factor to
methane. Thus, we are changing the emission factor proposed for
Calculation Method 2, which was in terms of standard cubic feet of
whole gas per hour, to use terms of kilograms CH4 per hour.
To do this, we reviewed the source of the proposed crankcase emission
factor, the 2021 API Compendium.\35\ API's emission factor, 2.28
standard cubic feet per hour per source, was developed from results
from Phase II of a comprehensive measurement program conducted to
determine cost-effective directed inspection and maintenance (DI&M)
control opportunities for reducing natural gas losses due to fugitive
equipment leaks and avoidable process inefficiencies. Phase II of the
program was conducted at five gas processing plants, seven gathering
compressor stations, and twelve well sites during 2004 and 2005.\36\
This study, ``EPA
[[Page 42101]]
Phase II Aggregate Site Report: Cost-Effective Directed Inspection and
Maintenance Control Opportunities at Five Gas Processing Plants and
Upstream Gathering Compressor Stations and Well Sites, Technical
Report,'' prepared by National Gas Machinery Laboratory, Clearstone
Engineering, Ltd., and Innovative Environmental Solutions, Inc.
(hereafter referred to as the ``Clearstone Phase II Study''), provided
the crankcase emission factor as 0.12 kilograms of THC per hour per
source, which API then converted to a whole gas factor.
---------------------------------------------------------------------------
\35\ Compendium of Greenhouse Gas Emissions Methodologies For
The Natural Gas And Oil Industry. Produced by URS Corporation for
American Petroleum Institute. November 2021. Available at https://www.api.org/-/media/files/policy/esg/ghg/2021-api-ghg-compendium-110921.pdf and in the docket for this rulemaking, Docket ID. No.
EPA-HQ-OAR-2023-0234.
\36\ Cost-Effective Directed Inspection and Maintenance Control
Opportunities at Five Gas Processing Plants and Upstream Gathering
Compressor Stations and Well Sites. EPA Phase II Aggregate Site
Report prepared for U.S. EPA Natural Gas STAR Program by Natural Gas
Machinery Laboratory, Clearstone Engineering Ltd., and Innovative
Environmental Solutions, Inc. March 2006. Available at https://www.epa.gov/sites/default/files/2016-08/documents/clearstone_ii_03_2006.pdf and in the docket for this rulemaking,
Docket ID. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------
In order to provide an emission factor in terms of kilograms of
CH4 per hour per source for use in the equation W-46, the
EPA started with the Clearstone Phase II study's THC emission factor.
We expect the THC in the crankcase vent originates from either direct
natural gas leaks into the crankcase or uncombusted hydrocarbons in
exhaust gas that leaks into the crankcase. In either event, we expect
the ratio of methane to THC in the crankcase vent to be represented by
the average ratio of methane to THC in the natural gas used as fuel for
the engine. We used the average methane-to-total organic compounds
(TOC) weight ratios for production of 0.695 and transmission of 0.908
used in estimating emission impacts for the NSPS OOOOb rule (see Docket
ID. No. EPA-HQ-OAR-2021-0317-1578, attachments 4 through 6, tab
``Composition and Factors''). Using these factors, the EPA converted
the Clearstone Phase II study THC emission factor from units of
kilograms THC per hour per source to units of kilograms CH4
per hour per source.\37\ The emission factors provided in equation W-46
of the final rule are 0.083 kg CH4/hr/engine for onshore
petroleum and natural gas production and onshore petroleum and natural
gas gathering and boosting facilities and 0.11 kg CH4/hr/
engine for all other applicable industry segments. We are also revising
equation W-46 to include the unit conversion from kilograms
CH4 to mt CH4 for consistency with the emissions
reporting requirements of subpart W.
---------------------------------------------------------------------------
\37\ 0.694769294934942 kg CH4/kg TOC for production
facilities; 0.907710347197016 kg CH4/kg TOC for
transmission facilities. It was assumed that TOC = THC for the
purposes of this conversion and that all THC in the crankcase gas is
from uncombusted fuel gas.
---------------------------------------------------------------------------
Comment: One commenter was concerned that engine size was not
considered in calculating emissions or developing the emission factor
used in proposed equation W-45. The commenter states that gas storage
compressors and compressor station engines on which the proposed
emission factor is based are of a much larger scale than production
facility engines and are therefore expected to have a much higher vent
rate. The commenter requested a de-minimis exemption for very small
engines, or the allowance of direct measurement of crankcase vents.
Response: The EPA is finalizing the option for direct measurement
of crankcase gas vent emissions, as previously discussed. In an effort
to be consistent with the provisions of 40 CFR 98.233(z), the EPA is
changing the language in the introductory paragraph of 40 CFR
98.233(ee) to state that only RICE with a rated heat capacity greater
than 1 MMBtu/hr (or the equivalent of 130 horsepower) must calculate
emissions from crankcase venting. We may consider evaluating the
removal of this exclusion in future rulemakings.
Comment: Several commenters opposed the emission factor
methodology, which was proposed on a per vent approach. Commenters
requested that the emission factor be per RICE, rather than per
crankcase vent, to avoid confusion. One commenter also noted that the
proposed emission factor of 2.28 scfh per vent is not consistent with
crankcase emissions per engine based on the study, ``Characterization
of Crankcase Ventilation Gas on Stationary Natural Gas Engines,'' by
Colorado State University (March 2023). One commenter further stated
that the reporting requirements under 40 CFR 98.236(ee) should be on a
per-site basis.
Additionally, some commenters requested clarification on the term
``vent'' in proposed equation W-45. Commenters noted that vents can be
manifolded together. Commenters stated that, for example, when
installed within a structure, crankcase vents from multiple engines are
typically routed to a central manifold and exhausts to the exterior of
the structure through a single ``vent.'' The commenters stated that the
proposed rule could be interpreted as allowing the 2.28 scfh per vent
emission factor to apply to the manifolded vent rather than each
individual engine's vent.
Response: The EPA has reviewed the source of the proposed emission
factor, the Clearstone Phase II Study, and confirmed that the emission
factor provided in the study is in units of kilograms THC per hour per
crankcase vent, but additional detail on the measurement locations and
vent configurations is not provided in the study. However, the EPA
agrees with the commenters that the methodology would be more clear if
the factor was presented on a per RICE basis, especially for crankcase
vents that are manifolded together. Based on a technical drawing
included in the Clearstone Phase II Study, the EPA assumes that the
Clearstone Phase II Study emission factor was likely representative of
crankcase vent emissions from the whole engine. Therefore, we have
revised the emission factor methodology and equation W-46 to be per
RICE in the final rule. Further, we have provided a calculation
methodology for reporters who elect to directly measure emissions from
a manifolded vent; under the final provisions for this methodology, if
the manifolded group contains only crankcase vent sources, reporters
must divide the measured volumetric flow equally between all operating
RICE. Additionally, under the final provisions for this methodology, if
the manifolded group contains crankcase vent sources and compressor
vent sources, the measurement made when the compressor is in operating
mode must be included in the emissions being characterized under 40 CFR
98.233(o) or (p) and must be reported under 40 CFR 98.236 (o) or (p),
as applicable. Therefore, we are not requiring facilities that manifold
their crankcase vent with compressor vent sources to separately
characterize their crankcase vent emissions, because that would double-
count these emissions. This approach is consistent with the goal of CAA
section 136(h) to develop accurate facility-wide methane emissions.
Further, the EPA has reviewed the study, ``Characterization of
Crankcase Ventilation Gas on Stationary Natural Gas Engines,'' by
Colorado State University (March 2023) (hereafter referred to as the
``2023 CSU Study'') and determined that the data is not appropriate for
use in the final rule. We have determined that the 2023 CSU study is
too limited to establish national average CH4 concentration
values. The study team studied one four-stroke lean-burn engine in the
field and lab-tested two additional engines (one four-stroke rich-burn
and one two-stroke lean-burn). The field-tested engine was at tested at
85 percent load, while the lab-tested engines were measured at several
different loads. The study sampled and characterized the crankcase gas
on the natural gas engines with the end goal of installing a closed
crankcase recirculation/filtration system. The field testing on the
four-stroke lean-burn engine found that CH4 accounts for 3.6
[[Page 42102]]
percent of the crankcase gas. The lab testing on the four-stroke rich-
burn engine found higher levels of CH4 in the crankcase gas
at 5.5 percent by volume, and the two-stroke lean-burn engine had very
low levels of CH4 in the crankcase gas (0.3 percent by
volume). However, the study did not determine a CH4 emission
rate. Additionally, the 2023 CSU study only tested CH4
concentrations in the crankcase gas for three engines, two of which
were in controlled conditions of a laboratory setting. The EPA has
determined that the results of this study are not representative of the
industry as a whole due to the low sample size.
In response to the commenter's request to report data for crankcase
venting on a per-site basis, the EPA notes that the data reported under
40 CFR 98.236(ee)(2) of the final rule would be aggregated at the
facility, well-pad site, or gathering and boosting site level. Given
the detailed reporting requirements for facilities electing to use
Calculation Method 1, direct measurement data collected under 40 CFR
98.236(ee)(1) of the final rule is required to be reported for each
test performed on an operating RICE. However, to alleviate burden, the
EPA has revised requirements under 40 CFR 98.236(ee)(2) in the final
rule that would remove averaging of data at the site level. In the
final rule, we have revised the requirement under 40 CFR
98.236(ee)(2)(iii) from reporting of average operating hours to
reporting of total operating hours of RICE with crankcase vents.
D. Reporting for the Onshore Petroleum and Natural Gas Production and
Onshore Petroleum and Natural Gas Gathering and Boosting Industry
Segments
1. Summary of Final Amendments
As explained in the 2023 Subpart W proposal, the current sub-basin
or basin-level aggregation of data reported within the Onshore
Petroleum and Natural Gas Production and Onshore Petroleum and Natural
Gas Gathering and Boosting segments can present challenges in the
process of emissions verification, with corresponding potential impacts
on data quality. The EPA proposed several amendments to reporting
requirements within the Onshore Petroleum and Natural Gas Production
and Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments. Consistent with section II.C. of this preamble, the EPA is
finalizing these amendments as proposed, with the exception that
certain instances of the term ``well-pad'' have been updated to ``well-
pad site'' in the final amendments. We are finalizing an additional
clarifying amendment at 40 CFR 98.236(aa)(10)(v) related to which
gathering and boosting sites must be reported and adding a new
definition for the term ``well-pad site'' at 40 CFR 98.238. These
clarifying amendments are discussed later in this section. As a first
step, the EPA is finalizing as proposed the reporting requirements to
be more explicitly consistent with the reporting form structure for the
well identification (ID) numbers at the facility as discussed in detail
in the 2023 Subpart W Proposal. The EPA is finalizing as proposed
revisions to 40 CFR 98.236(aa)(1)(ii) and additional well-specific
reporting requirements in 40 CFR 98.236(aa)(1)(iii). Additionally, the
EPA is no longer requiring the sub-basin ID to be reported for each
well. Instead, reporters will report the sub-basin ID by well-pad and
then report the well-pad ID on which the well is located. The well-pad
ID is a new data element and is described in the following paragraph.
The EPA is also finalizing as proposed the revisions to the
requirements to provide a list of well IDs for the five emission source
types directly related to wells to instead specify that reporters must
report emissions and activity data for each of those emission source
types by well within the source-specific reporting requirements, as
described later in this section.
Second, the EPA is adding as proposed the following data elements:
well-pad ID (for Onshore Petroleum and Natural Gas Production segment)
and gathering and boosting site ID (for Onshore Petroleum and Natural
Gas Gathering and Boosting). These data elements are hereafter
collectively referred to as ``site-level IDs.'' The EPA is adding to 40
CFR 98.236(aa)(1)(iv) (for Onshore Petroleum and Natural Gas
Production) and 40 CFR 98.236(aa)(10)(v) (for Onshore Petroleum and
Natural Gas Gathering and Boosting) requirements for reporting of
information related to each well-pad ID and gathering and boosting site
ID, respectively. The reporting elements for each well-pad ID include a
unique name or ID for each well-pad, the sub-basin ID, and the location
(i.e., representative latitude and longitude coordinates).
To clarify requirements related to the final well-pad ID data
element, the EPA is finalizing a definition for the newly defined term
well-pad site. The term is defined to mean all equipment on or
associated with a single well-pad. Specifically, the well-pad site
includes all equipment on a single well-pad plus all equipment
associated with that single well-pad. This definition was added to
clarify and align the term ``well-pad site'' with the existing
definition of a facility with respect to the Onshore Petroleum and
Natural Gas Production industry segment, which is not being updated as
part of this rulemaking. The EPA understands that certain equipment at
facilities within the Onshore Petroleum and Natural Gas Production
segment may not be present directly on a well-pad, such as an off-well-
pad tank battery that is associated with a single well-pad. The final
definition clarifies that such equipment would be considered part of
the well-pad site for emission calculation and reporting purposes.
Further discussion of this definition as it applies to specific
emission sources can be found in sections III.E.1. (with respect to
pneumatic devices) and III.P. (with respect to equipment leaks) of this
preamble. Related to this new definition, where the 2023 Subpart W
Proposal used the term ``well-pad'' to describe the level of
aggregation for reporting, we are finalizing the associated provisions
to instead use the term ``well-pad site.''
For the Onshore Petroleum and Natural Gas Gathering and Boosting
industry segments, the EPA is finalizing requirements as proposed at 40
CFR 98.236(aa)(10)(v) to require reporters to provide a unique name or
ID, the site type, and the location for each gathering and boosting
site. After consideration of public comment, the EPA is finalizing 40
CFR 98.236(aa)(10)(v) with clarifying language that reporting is only
required for gathering and boosting sites for which there were
emissions in the calendar year. This is consistent with the intent of
the 2023 Subpart W proposed language, as requiring reporting for sites
without emissions would not benefit the process of emissions
verification or improve data quality and data transparency. For the
``site type'' for each gathering and boosting site, reporters will
select between ``gathering compressor station,'' ``centralized oil
production site,'' ``gathering pipeline site,'' or ``other fence-line
site.'' The EPA is finalizing a definition of ``gathering compressor
station'' in 40 CFR 98.238 to be used for the purposes of this
reporting requirement and to differentiate gathering compressor
stations from other types of compressor stations in subpart W (e.g.,
transmission compressor stations). The Onshore Petroleum and Natural
Gas Gathering and Boosting industry segment also includes centralized
oil production sites
[[Page 42103]]
that collect oil from multiple well-pads but that do not have
compressors (i.e., are not ``compressor stations''). The EPA is
finalizing a definition of a ``centralized oil production site'' in 40
CFR 98.238 to be used for the purposes of this reporting requirement.
For gathering pipelines, the EPA is finalizing a definition of
``gathering pipeline site'' to specify that it is all the gathering
pipelines at the facility within a single state. In previous
rulemakings, the EPA has received information from stakeholders noting
that there are facility configurations that would not clearly fit
within the proposed definition for ``gathering compressor station'' or
``centralized oil production site,'' including, but not limited to,
booster stations, dehydration facilities, and treating facilities.\38\
The EPA is finalizing as proposed the ``other fence-line site'' site
type to cover these types of sites. For gathering pipelines, the EPA is
including within the definition of ``gathering and boosting site'' that
a gathering pipeline site is all the gathering pipelines at the
facility within a single state. For the ``location'' reported for each
gathering and boosting site, the EPA is requiring that reporters will
provide the representative latitude and longitude coordinates where the
site type is a gathering compressor station, centralized oil production
site or other fence-line facility, and the state where the site type is
a gathering pipeline.
---------------------------------------------------------------------------
\38\ Letter from Angie Burckhalter, The Petroleum Alliance of
Oklahoma, to Administrator Michael S. Regan, U.S. EPA, Re: Docket
ID. No. EPA-HQ-OAR-2019-0424; Revisions and Confidentiality
Determinations for Data Elements Under the Greenhouse Gas Reporting
Rule. October 6, 2022. Available in the docket for this rulemaking,
Docket ID. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------
For the emission source types in the Onshore Petroleum and Natural
Gas Production industry segment directly related to wells that
currently report by sub-basin (i.e., well venting for liquids
unloading, completions and workovers with hydraulic fracturing,
completions and workovers without hydraulic fracturing, and associated
gas venting or flaring) or by calculation method and use of a flare
(i.e., well testing), we are finalizing amendments to require reporting
of emissions and activity data for each individual well instead of in
the prior aggregations (e.g., by sub-basin). Where the prior emission
source-level provisions of 40 CFR 98.236 for the Onshore Petroleum and
Natural Gas Production industry segment and the Onshore Petroleum and
Natural Gas Gathering and Boosting industry segment required reporting
at either the facility or the sub-basin level (other than the emission
source types directly related to wells), the final amendments no longer
require reporting at the sub-basin level and instead require reporters
to provide emissions and activity data by well-pad ID or gathering and
boosting site ID for each facility. For emission source types that
report at the unit level (e.g., AGRs, dehydrators, and flares), there
is no change to the reporting level but reporters are required to
identify the well-pad ID or gathering and boosting site ID. This
requirement replaces reporting of the county or sub-basin ID, if
applicable.
Due to the change of the level of aggregation of activity data to
the well level or well-pad site level within the Onshore Petroleum and
Natural Gas Production and Onshore Petroleum industry segment, the EPA
is also finalizing changes to the data elements for which reporters
with wildcat wells and/or delineation wells may delay reporting for 2
years. Wildcat and delineation wells are considered exploratory wells
in the oil and gas industry, and data from these wells are generally
considered sensitive information by the industry. State oil and gas
commissions commonly hold such data from public release for two years.
Based on consideration of public comments, we are finalizing provisions
allowing reporters to delay reporting of the following inputs to
emission equations for wildcat wells and/or delineation wells for 2
years to acknowledge the sensitive nature of the data and to ensure
that the data cannot be back calculated prior to the end of the 2-year
delay.\39\
---------------------------------------------------------------------------
\39\ See section III.C.4. of this preamble for a description of
the provisions for delayed reporting of inputs to emission equations
for mud degassing wildcat wells and/or delineation wells.
---------------------------------------------------------------------------
For completions and workovers with hydraulic fracturing, if the
well is a wildcat well or delineation well:
40 CFR 98.236(g)(5)(i)--Cumulative gas flowback time, in
hours, for all completions or workovers at the well from when gas is
first detected until sufficient quantities are present to enable
separation, and the cumulative flowback time, in hours, after
sufficient quantities of gas are present to enable separation.
40 CFR 98.236(g)(5)(ii)--If the well is a measured well
for the sub-basin and well-type combination, the flowback rate, in
standard cubic feet per hour.
40 CFR 98.236(g)(5)(iii)(A)--If you used equation W-12C,
gas to oil ratio for the well in standard cubic feet of gas per barrel
of oil.
40 CFR 98.236(g)(5)(iii)(B)--If you used equation W-12C,
volume of oil produced during the first 30 days of production after
completions of each the newly drilled well or well workover using
hydraulic fracturing.
For completions and workovers without hydraulic fracturing, if the
well is a wildcat well or delineation well:
40 CFR 98.236(h)(1)(iii)--For a well with one or more gas
well completions without hydraulic fracturing and without flaring,
total number of hours that gas vented directly to the atmosphere during
venting for all completions in the sub-basin category without hydraulic
fracturing.
40 CFR 98.236(h)(1)(iv)--For a well with one or more gas
well completions without hydraulic fracturing and without flaring,
average daily gas production rate for all completions without hydraulic
fracturing in the sub-basin without flaring.
40 CFR 98.236(h)(2)(iii)--For a well with one or more gas
well completions without hydraulic fracturing and with flaring, total
number of hours that gas routed to a flare during venting for all
completions without hydraulic fracturing.
40 CFR 98.236(h)(2)(iv)--For a well with one or more gas
well completions without hydraulic fracturing and with flaring, average
daily gas production rate for all completions without hydraulic
fracturing with flaring.
For well testing, if the well is a wildcat well or delineation
well:
40 CFR 98.236(l)(1)(iv)--For an oil well not routed to a
flare, average gas to oil ratio for the tested well.
40 CFR 98.236(l)(1)(iv)--For an oil well not routed to a
flare, average gas to oil ratio for the tested well.
40 CFR 98.236(l)(1)(v)--For an oil well not routed to a
flare, average flow rate for the tested well.
40 CFR 98.236(l)(2)(iv)--For an oil well routed to a
flare, average gas to oil ratio for the tested well.
40 CFR 98.236(l)(2)(v)--For an oil well routed to a flare,
average flow rate for the tested well.
40 CFR 98.236(l)(3)(iii)--For a gas well not routed to a
flare, number of well testing days for the tested well in the calendar
year.
40 CFR 98.236(l)(3)(iv)--For a gas well not routed to a
flare, average annual production rate for the tested well.
40 CFR 98.236(l)(4)(iii)--For a gas well routed to a
flare, number of well testing days for the tested well in the calendar
year.
40 CFR 98.236(l)(4)(iv)--For a gas well routed to a flare,
average annual production rate for the tested well.
For associated gas venting and flaring, if the well is a wildcat
well or delineation well:
[[Page 42104]]
40 CFR 98.236(m)(5)--Volume of oil produced by the well in
the calendar year only during the time periods in which associated gas
was vented or flared.
40 CFR 98.236(m)(6)--Total volume of associated gas sent
to sales or used on site and not sent to a vent or flare in the
calendar year only during time periods in which associated gas was
vented or flared.
Reporters are not allowed to delay reporting of any of the
emissions from these sources, nor are they allowed to delay reporting
of any other data elements in 40 CFR 98.236. Providing a 2-year delay
in reporting for these specific inputs protects sensitive information
during the time in which it is considered to be sensitive information
by the industry. After 2 years have passed, reporters will be required
to report these inputs to emission equations. We emphasize that this
information would be considered to be emission data under CAA section
114 that is not eligible for confidential treatment upon submission to
the agency, and thus will be made available to the public upon
submission. Furthermore, emissions from any well with well degassing
must still be reported annually and we further note that we have other
information that will allow verification of reported emissions.
Moreover, the EPA intends to be diligent in reviewing and reconciling
delayed data with reported emissions data, and we also stress that,
although the delayed data may not be reported in the initial reporting
year, reporters must maintain records supporting their emission
calculations and these records are subject to review by the EPA.
Finally, the EPA intends to further evaluate whether this information
will be required and, if so, may require reporting without delay in a
future rulemaking.
2. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to disaggregate reporting requirements within
the Onshore Petroleum and Natural Gas Production and Onshore Petroleum
and Natural Gas Gathering and Boosting industry segments.
Comment: The EPA received several comments asserting that the EPA
has not presented a clear rationale rooted in the EPA's statutory
authority for the proposed requirement to disaggregate current
reporting levels in the Onshore Production and Onshore Gathering and
Boosting industry segments.
Response: With the exception of a clarifying amendment to 40 CFR
98.236(aa)(10)(v) discussed elsewhere in this section, the EPA is
finalizing the amendments affecting the aggregation of data reported
within the Onshore Petroleum and Natural Gas Production and Onshore
Petroleum and Natural Gas Gathering and Boosting industry segments as
proposed.
As stated in section III.D. of the preamble to the 2023 Subpart W
Proposal, the aggregation of data currently collected for these
industry segments ``can present challenges in the process of emissions
verification, with corresponding potential impacts on data quality, and
it also limits data transparency.'' Prior to the amendments finalized
in this rulemaking, emissions and activity data for certain emission
sources in the Onshore Petroleum and Natural Gas Production and Onshore
Petroleum and Natural Gas Gathering and Boosting industry segments were
reported at the basin or county/sub-basin level. Sources that
previously reported at the facility (basin) level include natural gas
pneumatic devices, blowdown vent stacks, and equipment leaks. Emission
sources that reported at the sub-basin or county level included liquids
unloading, completions and workovers with hydraulic fracturing, and
storage tanks. This level of aggregation can cover a wide geographic
area and include numerous well-pads or gathering and boosting sites. As
a result, certain methods of emissions verification are not possible or
limited in utility for these sources. For example, a verification
review looking at data reported year-over-year for an individual
gathering and boosting site may be able to identify data entry errors
(e.g., a decimal point entered at the wrong order of magnitude) that
would be masked at higher levels of aggregation. Identification of
similar types of errors for sources not aggregated at this level
regularly occurs during the EPA verification process and has resulted
in significant changes (both increases and decreases) to reported
emissions.
The directive under CAA section 136(h) to ensure that reporting
under subpart W accurately reflects total methane emissions is
inexorably linked to verification of reported data. Absent a robust
system of emissions verification, the EPA cannot ensure the accuracy of
reported data. As such, the proposed amendments to improve the quality
and verification of subpart W data are supportive of the directive of
CAA section 136(h). Further, as discussed in section II.C. of the
preamble to the 2023 Subpart W Proposal, beyond carrying out the
requirements of CAA section 136, the data collected under subpart W is
used to support a range of policies and initiatives under the CAA
including but not limited to ``provisions involving research,
evaluating and setting standards, endangerment determinations, or
informing EPA non-regulatory programs.'' The final amendments affecting
the aggregation of data reported within the Onshore Petroleum and
Natural Gas Production reporting requirements are expected to further
the EPA's understanding of the industry for future purposes of carrying
out provisions under the CAA.
One commenter asserted that changes in the aggregation of reported
data would not impact the total emissions reported under subpart W. The
EPA notes that the intent of the amendments to the aggregation of data
for these industry segments is not to increase or decrease overall
emissions reported, but to support the verification of reported data
and provide a higher degree of data quality and transparency to ensure
accuracy of total emissions reported, and that such verification may
identify errors that would have resulted in either over- or under-
statement of emissions. Further, the EPA anticipates that preparation
of more granular reports may provide reporters the opportunity to
identify errors that would have resulted in over- (or under-) statement
of emissions. We also expect that for facilities subject to the waste
emission charge under CAA section 136, that facilities will want to
review their data at a more granular level, to ensure that any charges
are accurate.
In addition to improving the quality and transparency of data
collected under subpart W, the amendments affecting the aggregation of
data reported within the Onshore Petroleum and Natural Gas Production
will support the EPA's implementation of the WEC under CAA section 136.
For example, CAA section 136(f)(7) requires that, ``[c]harges shall not
be imposed with respect to the emissions rate from any well that has
been permanently shut-in and plugged in the previous year in accordance
with all applicable closure requirements, as determined by the
Administrator.'' Prior to the amendments finalized in this rulemaking,
emissions from liquids unloading, workovers with hydraulic fracturing,
and workovers without hydraulic fracturing were reported by sub-basin
and emissions from leaks associated with the wellhead were reported at
the facility (basin) level. This level of aggregation is not compatible
with being able to determine
[[Page 42105]]
the ``emissions rate from any well'' as required by CAA section
136(f)(7). Following these amendments, data for leaks associated with a
wellhead will be reported at the well-pad site level while liquids
unloading and workovers will be reported by well ID, which can be
associated directly with a well that has been permanently shut-in and
plugged.
Additionally, the EPA notes that existing subpart W requirements
specify calculation of emissions at the well level for certain sources,
including Well Venting for Liquids Unloading, Completions and Workovers
with Hydraulic Fracturing, Completions and Workovers without Hydraulic
Fracturing, Well Testing and Associated Gas. The EPA is not changing
the level at which these calculations are required to be performed,
just the level at which they are reported. It is also noted that
certain other sources including flare stacks, AGRs, and enhanced oil
recovery (EOR) pumps are already reported at the unit level. The EPA
does not anticipate significant burden related to the change in
aggregation of reported data for these sources.
Comment: One commenter stated that the proposed reporting
requirement for ``each gathering and boosting site located in the
facility'' at 40 CFR 98.236(aa)(10)(v) was unclear as to whether
reporters are required to report information for sites that are
shutdown, bypassed, or otherwise have no potential for emissions.
Response: The intent of the referenced reporting requirement is to
collect information only for gathering and boosting sites that were
operational during the calendar year. For further clarification, 40 CFR
98.236(aa)(10)(v) has been amended to specify that reporting is only
required for sites for which there were emissions in the calendar year.
Comment: One commenter noted that where reporting would be required
by well or by well-pad, the EPA did not propose to change the language
for wildcat and delineation wells that specified that reporters may
delay reporting certain data elements for 2 years ``if the only wells
in the sub-basin are wildcat and delineation wells.'' The commenter
questioned why the EPA did not provide a delay in reporting for single
wildcat and delineation wells, for emission sources that must be
reported by well, or provide a delay in reporting if the only wells on
the well-pad are wildcat and delineation wells, for emission sources
that must be reported by well-pad. Finally, the commenter asked whether
the use of ``and/or'' in any provisions referring to a single well is a
typo or if a single well can be both a wildcat and delineation well.
Response: For the existing emission sources that will be required
to report emissions and activity data by well or by well-pad site, the
EPA reviewed the provisions for specific inputs to emissions equations
for which we currently provide or proposed to provide the ability for
reporters to choose to delay reporting for wildcat and delineation
wells for 2 years to protect sensitive information. As documented in
the September 23, 2015 memorandum ``Review for Potential Disclosure
Concerns for Inputs to Emission Equations Affected by the ``2015
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems,'' the EPA determined that certain inputs to emission
equations would not be likely to reveal any sensitive information,
except for two specific types of exploratory wells, delineation wells
and wildcat wells. Information specific to exploratory wells is
generally considered sensitive information by the industry, so the EPA
determined that these inputs to an emission equation should be directly
reported but that reporters may delay reporting of sensitive
information. The proposal, consistent with the prior reporting
requirements as described in that memorandum, acknowledged the
sensitive nature of certain data for exploratory wells.
The following paragraphs describe our review for specific source
types for which we determined that changes from proposal for the 2-year
delay provisions were appropriate. For all source types, we emphasize
that all other data, including natural gas emissions, emissions of
CH4 and CO2, and activity data for which a 2-year delay is
not explicitly provided, must be reported in the applicable reporting
year. The EPA will be very diligent in reviewing current year and
delayed data to verify that emissions originally reported are accurate.
In addition, for each of these source types, we note that wildcat and
delineation wells are slightly different types of wells, and a single
well would not be considered both a wildcat well and a delineation
well. Therefore, for source types for which emissions and activity data
must be reported by well in the final rule, the provisions for delay of
reporting refer to ``a wildcat or delineation well.'' Provisions that
allow a delay in reporting only all the wells at the well-pad site,
sub-basin, or facility are wildcat wells, delineation wells, or some of
each refer to ``wildcat wells and/or delineation wells.''
Completions and workovers with hydraulic fracturing. The proposal
provided a 2-year delay for the reporting of certain data elements for
wildcat and/or delineation wells, but only when all wells with
completions and workovers with hydraulic fracturing in the same sub-
basin and well-type combination were wildcat and/or delineation wells.
The specific data elements included the cumulative amount of time
flowback during the initial and separation flowback stages,
Tp,s and Tp,i respectively, and the average gas
flowback rate at the beginning of the separation stage
(FRs,p) when using equation W-10A, as well as the for the
gas to oil ratio (GOR), GORp, and the volume of oil produced during the
first 30 days of production (Vp) when using equation W-12C
to calculate a 30-day gas production rate for oil wells when using
equation W-10A. However, under the final rule, emissions and associated
data elements will be reported at the well level; therefore,
publication of the data elements specified above even when not all
wells in the sub-basin are wildcat or delineation wells may reveal
sensitive information. Therefore, we are finalizing the reporting
requirements for completions and workovers with hydraulic fracturing to
continue providing the option for the 2-year delay in reporting these
data elements but we are no longer requiring that all wells in the sub-
basin be wildcat and/or delineation wells for reporters to be able to
use the 2-year delay.
Completions and workovers without hydraulic fracturing. The
proposal provided a 2-year delay for the reporting of certain data
elements for wildcat and/or delineation wells, but only when all wells
with completions and workovers without hydraulic fracturing in the same
sub-basin and well-type combination were wildcat and/or delineation
wells. The specific data elements included the average daily gas
production required by 40 CFR 98.236(h)(1)(iv) and (h)(2)(iv). However,
under the final rule, emissions will be reported at the well level;
therefore, publication of this information even when not all wells in
the sub-basin are wildcat or delineation wells may reveal sensitive
information. Therefore, we are finalizing the reporting requirements
for completions and workovers without hydraulic fracturing to continue
providing the option for the 2-year delay in reporting these data
elements, but we are no longer requiring that all wells in the sub-
basin be wildcat and/or delineation wells for reporters to be able to
use the 2-year delay. In addition, we are
[[Page 42106]]
allowing reporters the option of a 2-year delay in reporting the total
number of hours that gas is vented or flared, 40 CFR 98.236(h)(1)(iii)
or (h)(2)(iii). Equation W-13B computes the quantity of natural gas
emissions by multiplying the average daily gas production rate by the
number of hours gas is vented or routed to a flare. Under the proposed
rule, reporters would have been required to report without a delay the
natural gas emissions and the total hours that gas is vented or routed
to a flare, but this would have allowed back-calculation of the
production rate at the well level.
Well testing. The proposal provided a 2-year delay for the
reporting of certain data elements for wildcat and/or delineation
wells, but only when all wells tested in the same sub-basin were
wildcat and/or delineation wells. The specific data elements included
the average flow rate in equation W-17A for oil wells and the average
annual production rate for gas wells in equation W-17B. However, under
the final rule, emissions and associated data elements will be reported
at the well level and publication of the data elements discussed above
even when not all wells in the sub-basin are wildcat or delineation
wells may reveal sensitive information. Therefore, we are finalizing
the reporting requirements for well testing to continue providing the
option for the 2-year delay in reporting these data elements, but we
are no longer requiring that all wells in the sub-basin be wildcat and/
or delineation wells for reporters to be able to use the 2-year delay.
In addition, for oil wells, we are allowing reporters the option of a
2-year delay in reporting the average GOR for the well in equation W-
17A in the final rule, and for gas wells, we are allowing reporters the
option of a 2-year delay in reporting the number of well testing days
in equation W-17B in the final rule. Reporters use equation W-17A to
calculate natural gas emissions from oil wells by multiplying the GOR
by the flow rate in barrels of oil per day by the number of days wells
are tested. The proposal only provided a 2-year delay for the flow
rate. Reporting of all other data elements would allow back calculation
of the flow rate; therefore, the EPA is finalizing the rule today to
provide the 2-year reporting delay for average GOR. Equation W-17B
computes the quantity of natural gas emissions by multiplying the
average annual gas production rate by the number of days. Under the
proposed rule, reporters would have been required to report without a
delay the natural gas emissions and the total number of days, which
would have allowed back-calculation of the production rate.
Associated natural gas. The proposal provided a 2-year delay for
the reporting of certain data elements for wildcat and/or delineation
wells, but only when all wells with associated natural gas in the same
sub-basin were wildcat and/or delineation wells. The specific data
elements included the volume of oil produced and the volume of
associated gas sent to sales in 40 CFR 98.236(m)(5) and(6) when using
equation W-18. However, under the final rule, associated gas emissions
and related data will be reported at the well level and publication of
certain data related to associated gas venting and flaring even when
not all wells in the sub-basin are wildcat or delineation wells may
reveal sensitive information. Therefore, we are finalizing the
reporting requirements for associated gas to continue providing the
option for the 2-year delay for volume of oil produced and volume of
gas sent to sales but we are no longer requiring that all associated
gas wells in the sub-basin be wildcat and/or delineation wells for
reporters to be able to use the 2-year delay.
Comment: Multiple commenters disagreed with the proposed definition
of a ``centralized oil production site'' and its proposed designation
as a site type for facilities in the Onshore Petroleum and Natural Gas
Gathering and Boosting industry segment. Commenters requested that the
term ``centralized oil production site'' be revised to ``centralized
production facility,'' the associated definition be revised to match
the definition of the term in the NSPS OOOOb and EG OOOOc regulations,
and that the site type be designated as part of the Onshore Petroleum
and Natural Gas Production industry segment. Commenters asserted that
the proposed definition and placement within the Onshore Petroleum and
Natural Gas Gathering and Boosting industry segment were inconsistent
with CAA section 136.
Response: The EPA is finalizing the definition of ``centralized oil
production site'' as proposed. The EPA notes that the EPA did not
reopen, and no change was proposed nor is being finalized in this
rulemaking to, the industry segment definitions for ``Onshore petroleum
and natural gas production'' and ``Onshore petroleum and natural gas
gathering and boosting'' at 40 CFR 98.230(a)(2) and (9), respectively,
nor the definitions of facilities with respect to this industry segment
in 40 CFR 98.238. The EPA is finalizing one minor revision to the
industry segment definition for ``Onshore petroleum and natural gas
gathering and boosting'' in this rulemaking, at 40 CFR 98.230(a)(9), to
clarify the EPA's original intent that the petroleum and/or natural gas
is transported to a downstream endpoint, as is already clear from the
definition of ``gathering and boosting system'' in 40 CFR 98.238 (see
section III.U.3. of this preamble for additional information). However,
this revision does not substantively change the industry segment
definition. The EPA did not reopen, and no change was proposed nor is
being finalized in this rulemaking to, the definition of facility with
respect to this industry segment in 40 CFR 98.238. The new reporting
element of a site type (including the newly defined centralized oil
production site) for facilities in the Onshore Petroleum and Natural
Gas Gathering and Boosting industry segment does not change the
applicable industry segment for reporting facilities, either before or
after this rulemaking comes into effect. In other words, existing sites
that meet the new ``centralized oil production site'' definition are
currently considered to be part of the Onshore Petroleum and Natural
Gas Gathering and Boosting industry segment and will continue to be
considered part of this segment with this final rule. The distinction
between an Onshore Petroleum and Natural Gas Production facility and an
Onshore Petroleum and Natural Gas Gathering and Boosting facility under
the existing and finalized subpart W is primarily based on whether the
equipment is located on a single well-pad or associated with a single
well-pad (onshore production equipment) or located off a single well-
pad and associated with two or more single well-pads (gathering and
boosting equipment). Centralized oil production sites are distinct from
the separately defined well-pad sites and receive hydrocarbon liquids
from two or more single well-pads. Therefore, these sites do not meet
the criteria for inclusion in an Onshore Petroleum and Natural Gas
Production facility as defined in subpart W.
Although implementation of CAA section 136(c) (``Waste Emissions
Charge'') is outside the scope of this rulemaking, the EPA notes that
CAA section 136(d) defines the term ``applicable facility'' as a
facility within specified industry segments as defined in subpart W.
Thus, this approach is consistent with the existing facility
definitions in subpart W referenced in CAA section 136 when the
statutory provision was enacted. As previously
[[Page 42107]]
noted, the EPA did not propose and is not finalizing changes to the
definition of the ``Onshore petroleum and natural gas gathering and
boosting'' industry segment (beyond the minor clarification noted in
the previous paragraph) or the definition of a facility with respect to
this segment, and as such the request to change this definition is
outside the scope of this rulemaking.
E. Natural Gas Pneumatic Device Venting and Natural Gas Driven
Pneumatic Pump Venting
Subpart W currently requires calculation of GHG emissions from
natural gas pneumatic device venting (existing 40 CFR 98.233(a)) and
natural gas driven pneumatic pump venting (existing 40 CFR 98.233(c))
using default population emission factors multiplied by the number of
devices and the average time those devices are ``in-service'' (i.e.,
supplied with natural gas). In our 2022 Proposed Rule, we proposed to
update the population emission factors for pneumatic devices based on
recent study data. In the 2023 Subpart W Proposal, we proposed adding
calculation methods based on measurements and leak screening for all
pneumatic device types while retaining the option to use population
emission factors for continuous bleed pneumatic devices only. For
intermittent bleed pneumatic devices, the 2023 Subpart W Proposal
removed the option to use default population emission factors allowing
only measurement and leak screening methods to be used. In this final
rule, after consideration of the comments received, we are finalizing
measurement options similar to those included in the 2023 Subpart W
Proposal, updating from proposal to allow facilities the option to use
population emission factors for all pneumatic device types (including
intermittent bleed devices), and updating the default population
emission factors for all pneumatic device types (including intermittent
bleed devices) as proposed in the 2022 Proposed Rule and consistent
with request for comments on this approach included in the 2023 Subpart
W Proposal. Therefore, in the final rule, up to four calculation
methods are provided as described in this section.
As proposed, we are expanding the number of industry segments that
have to report natural gas pneumatic device venting to include Onshore
Natural Gas Processing and Natural Gas Distribution industry segments.
However, we are not finalizing the first portion of the first sentence
that was proposed at 40 CFR 98.233(a) listing all of the industry
segments that must calculate pneumatic device venting emissions.
Listing these industry segments in 40 CFR 98.233(a) is duplicative of
the information in 40 CFR 98.232 and inconsistent with how the
calculation methods for other emission sources are stated. Similarly,
we are deleting the listing of industry segments in the definition of
GHGi term in equation W-1B. We are also adding a sentence to 40 CFR
98.233(a) to clarify that references to natural gas pneumatic devices
for Calculation Method 1 also apply to combinations of natural gas
pneumatic devices and natural gas driven pneumatic pumps that are
served by a common natural gas supply line, consistent with the
corresponding provisions in 40 CFR 98.233(c). We are making a number of
other revisions and clarifications to specific proposed requirements
for natural gas pneumatic device venting and natural gas pneumatic pump
venting and these are described in the applicable subsections of this
section.
1. Direct Measurement Methods for Natural Gas Pneumatic Devices and
Natural Gas Pneumatic Pumps
a. Summary of Final Amendments
Consistent with section II.B. of this preamble, we are finalizing
Calculation Method 1 based on direct measurement of natural gas
supplied to pneumatic devices in 40 CFR 98.233(a)(1) and supplied to
pneumatic pumps in 40 CFR 98.233(c)(1), as proposed, with minor
clarifications. If a continuous flow monitoring device is installed on
the natural gas supply line dedicated to one or a combination of
pneumatic devices, or the natural gas supply line dedicated to one or
more pneumatic pumps, that are vented directly to the atmosphere, then
the measured flow must be used to calculate the emissions from the
pneumatic devices or pneumatic pumps, as applicable, downstream of that
flow monitor. We are adding the word ``continuous'' to indicate that
the flow meter is to be used on an ongoing basis, not temporarily.
Temporary flow measurements are included under the provisions for
Calculation Method 2. We are also finalizing that this calculation
method is required when the flow is continuously measured in a supply
line that serves both pneumatic devices and natural gas driven
pneumatic pumps that are all vented directly to the atmosphere. We are
clarifying in the final rule for both pneumatic devices and pneumatic
pumps that this requirement applies if the flow monitor is capable of
meeting the requirements of existing 98.234(b). In other words, if the
flow is continuously measured but the meter is not capable of meeting
these requirements, Calculation Method 1 is not required. When using
Calculation Method 1, the flow monitor must meet the requirements
specified in existing 40 CFR 98.234(b). We are also finalizing as
proposed reporting requirements for each measurement location to report
the type of flow monitor, the number of each type of pneumatic device
being monitored at that location, and an indication of whether any
natural gas driven pneumatic pumps are also monitored at that location,
and the CH4 and CO2 emissions calculated for that
monitoring location in 40 CFR 98.236(b)(3). We are also finalizing
comparable reporting requirements for natural gas driven pneumatic
pumps in 40 CFR 98.236(c)(3), as proposed.
For natural gas pneumatic devices that install a flow meter
dedicated to measuring the flow of natural gas supplied to one or a
combination of pneumatic devices that are vented directly to the
atmosphere for only a portion of the year, in the final provision we
are updating to clarify the proposed requirement to ``escalate'' the
measured flow based on time in service by rephrasing this requirement,
consistent with our intent. In the final rule, reporters using
continuous flow meters for a portion of the year must calculate the
total volumetric (or mass) flow for the year based on the measured
volumetric flow times the total hours in the calendar year the devices
were in service (i.e., supplied with natural gas) divided by the number
of hours the devices were in service (i.e., supplied with natural gas)
and the volumetric (or mass) flow was being measured. For natural gas
pneumatic pumps, we are updating proposed 40 CFR 98.233(c)(1)(i)(A) to
use language in the final rule that is consistent with the updates
discussed above for ``escalating'' measured flow for pneumatic devices.
As a result, we are also removing proposed equation W-2A from 40 CFR
98.233(c)(1)(i)(A), which is no longer necessary for pneumatic pumps,
and renumbering equation W-2B to W-2A and equation W-2C to W-2B.
For natural gas pneumatic devices that do not have or do not elect
to install a flow meter dedicated to measuring the flow of natural gas
supplied to one or a combination of pneumatic devices that are vented
directly to the atmosphere, we are finalizing requirements for
Calculation Method 2 in 40 CFR 98.233(a)(2) to allow reporters to
measure the natural gas emissions from each pneumatic device vented
directly to the atmosphere at the well-pad site, gathering and boosting
site, or facility,
[[Page 42108]]
as applicable, using one of the measurement methods in existing 40 CFR
98.234(b) through (d). For natural gas driven pneumatic pumps that do
not have or do not elect to install a flow meter dedicated to measuring
the flow of natural gas supplied to one or a combination of pneumatic
pumps vented directly to the atmosphere, we are finalizing requirements
that the reporter either measure the natural gas emissions from each
such pneumatic pump at the facility as specified in 40 CFR 98.233(c)(2)
or calculate emissions from each such pneumatic pump at the facility
using the default emission factor as specified in 40 CFR 98.233(c)(3).
The measurement method is referred to as Calculation Method 2 for pumps
and is similar to Calculation Method 2 for pneumatic devices.
For reasons discussed in section III.E.3. of this preamble, we are
including a fourth calculation method for pneumatic devices allowing
the use of default population emission factors and this revision led to
us further assessing and updating from proposal Calculation Method 2 in
the final rule. We determined that facilities with pneumatic device
measurement data for some but not all sites, particularly in industry
segments subject to the WEC in section 136(c) through (h) of the CAA,
should be able to use those measurements for their subpart W reports.
Therefore, in the final rule we are modifying Calculation Method 2 to
allow facilities in the Onshore Petroleum and Natural Gas Production
and in the Onshore Petroleum and Natural Gas Gathering and Boosting
industry segments to elect to use Calculation Method 2 for pneumatic
devices for some well-pad sites or gathering and boosting sites and to
elect to use other methods for other sites. However, we are specifying
that, with the exception of emissions from devices for which natural
gas supply is measured according to Calculation Method 1, emissions
from all devices within an individual well-pad site or gathering and
boosting site must be calculated using the same method (i.e.,
Calculation Method 2 or Calculation Method 3 or Calculation Method 4,
if applicable) for a given calendar year in order to prevent selective
measurements of certain devices within a site that are expected to have
lower emissions. This approach is consistent with our approach for
equipment leaks where we have allowed and continue to allow site-by-
site equipment leak surveys to constitute a complete leak detection
survey for facilities in the Onshore Petroleum and Natural Gas
Production and in the Onshore Petroleum and Natural Gas Gathering and
Boosting industry segments. This approach also encourages the use of
Calculation Method 2 for selected well-pads and gathering and boosting
sites at facilities that may have otherwise opted to use Calculation
Method 4 rather than having to commit to measuring all devices across
the large, basin-wide facilities within these industry segments. While
we generally use the phrase ``well-pads'' to refer to sites in the
Onshore Petroleum and Natural Gas Production industry segment that
would be considered a complete survey, we know there are cases when
some pneumatic devices might not be on a well-pad but are still
``associated with a single well-pad'' (as defined in 40 CFR 98.238). To
ensure that the requirements to measure or monitor all pneumatic
devices (or equipment leaks) at the site-level for facilities in the
Onshore Petroleum and Natural Gas Production industry segment include
such devices, we are finalizing the term ``well-pad site'' in 40 CFR
98.238 and defining the well-pad site to mean all equipment on or
associated with a single well-pad, as discussed in section III.D. of
this preamble. Thus, the site-level pneumatic device provisions for the
Onshore Petroleum and Natural Gas Production industry segment include
natural gas pneumatic devices present on a single well-pad and natural
gas pneumatic devices that are not on that single well-pad but that are
associated with that single well-pad. We are also clarifying that the
reporting requirements for sources that are not reported at the
equipment level must be reported at the well-pad site level.
For facilities in the Onshore Natural Gas Processing, Onshore
Natural Gas Transmission Compression, Underground Natural Gas Storage,
and Natural Gas Distribution industry segments, the election to use
Calculation Method 2 is made at the facility level. In other words, if
Calculation Method 2 is elected, all pneumatic devices at the facility
(except those for which natural gas supply is measured according to
Calculation Method 1) must be measured annually or over a multi-year
cycle. We elected to retain this facility-level requirement because
facilities in the Onshore Natural Gas Processing, Onshore Natural Gas
Transmission Compression, Underground Natural Gas Storage industry
segments are much smaller and less dispersed than the basin-wide
facility definitions in the Onshore Petroleum and Natural Gas
Production and in the Onshore Petroleum and Natural Gas Gathering and
Boosting industry segments, and because these facilities are generally
expected to have a lower number of natural gas pneumatic devices where
facility-wide monitoring of devices can be accomplished within a day or
two. We recognize that facilities in the Natural Gas Distribution
industry segment can be very large and may have a significant number of
natural gas pneumatic devices, and we recognize that this approach
could encourage the use of default population emission factors.
However, we have not currently defined nor proposed to define
``distribution sites'' that account for all site types within this
industry segment. Furthermore, facilities in the Natural Gas
Distribution industry segment are not subject to the WEC. Based on
these considerations, we determined it was appropriate to retain
facility-level requirements for the Natural Gas Distribution industry
segment.
We are finalizing as proposed that the measurement interval for
facilities in the Onshore Natural Gas Processing, Onshore Natural Gas
Transmission Compression, Underground Natural Gas Storage, and Natural
Gas Distribution industry segments be dependent on the number of
devices at the facility. For facilities with 25 or fewer natural gas
pneumatic devices, we are requiring measurement of all devices
annually. For facilities with 26 to 50 devices, we are requiring
measurement of all devices in a two-year period. The required interval
period increases with every 25 devices, until reaching a maximum cycle
time of 5 years for facilities with 101 or more natural gas pneumatic
devices that are vented directly to the atmosphere.
Under Calculation Method 2, we are finalizing measurement
requirements as proposed that each pneumatic device vent measurement,
except for isolation valve actuators, must be conducted for a minimum
of 15 minutes; measurements for pneumatic isolation valve actuators
must be conducted for a minimum of 5 minutes. The reduced monitoring
duration for isolation valve actuators is provided because these
devices actuate very infrequently, and the monitoring is targeted to
confirm the valve actuators are not malfunctioning (i.e., emitting when
not actuating) rather than to develop an average emission rate
considering some limited number of actuations. If there is a measurable
flow during the measurement period, the average flow rate measured
during the measurement period must be used as the average flow rate for
that device and multiplied by the total hours the device is in service
(i.e., supplied with natural
[[Page 42109]]
gas) to calculate annual emissions (by pneumatic device type). For
continuous bleed devices, if there is no measurable flow rate (i.e.,
flow rate is below the method detection limit), we are requiring
reporters to confirm the device is in service when measured and that
the device type is correctly characterized. If the device was not in
service, the device must be retested at a time when it is in service.
If a continuous high bleed device was correctly characterized and
confirmed to be in service, the device must be retested using a
different measurement method and/or a longer duration until a
measurable flow is detected. When these remeasurements are made, we are
adding language to clarify that natural gas emissions from the device
must be calculated according to 40 CFR 98.233(a)(2)(iv). For continuous
low bleed devices, if there is no measurable flow rate during testing,
the manufacturer's steady state bleed rate must be used to estimate the
device's emissions. For cases where the manufacturer's steady state
bleed rate is not available, but the device is confirmed to be a
continuous low bleed pneumatic device, we are adding clarifying
language that remeasurement of the device is required. For intermittent
bleed devices, if there is no measurable flow rate and the device is
determined not to be in service, the device must be retested at a time
when it is in service. The lack of any emissions during a 5-minute or
15-minute period, as applicable, when the device is in service would
indicate that the device did not actuate and that the device is seating
correctly when not actuating. In cases where testing of in-service
intermittent bleed devices does not detect measurable flow, we are
finalizing as proposed that engineering calculations must be made to
estimate emissions per activation and that company records or
engineering estimates must be used to assess the number of actuations
per year to calculate the emissions from that device for the reporting
year. In response to concerns raised by commenters, we are clarifying
in the final provisions for Calculation Method 2, consistent with our
intent at proposal, that the measurements required under these methods
must be made under representative conditions and not immediately after
conducting maintenance on the device or after manually actuating the
device. These clarifying changes are also being made for Calculation
Method 2 for pneumatic pumps.
Under Calculation Method 2, if pneumatic device vent measurements
are made over several years (as allowed for facilities in the Onshore
Natural Gas Processing, Onshore Natural Gas Transmission Compression,
Underground Natural Gas Storage, and Natural Gas Distribution industry
segments), we are requiring as proposed that all measurements made
within a multi-year measurement cycle must be used to calculate a
facility-specific emission factor by device type (continuous high
bleed, continuous low bleed, and intermittent bleed). The emissions
measurements for the pneumatic device vents measured during the
reporting year must be used directly for those devices and reporters
must use the facility-specific emission factor (by device type) to
calculate the emissions from the pneumatic devices that were not
measured during the reporting year.
In the final rule, we are not finalizing the proposed Calculation
Method 2 reporting requirements for Onshore Petroleum and Natural Gas
Production and Onshore Petroleum and Natural Gas Boosting and Gathering
industry segments pertaining to multi-year measurement cycles as this
is no longer an option for facilities in these industry segments in the
final rule. Reporters in these industry segments must still report
other Calculation Method 2 data elements for each well-pad site or
gathering and boosting site, as applicable, consisting of the total
number of natural gas pneumatic devices by type measured in the
reporting year, the primary measurement method, the average time the
devices were in service (i.e., supplied with natural gas) during the
calendar year, and the GHG emissions for each type of natural gas
pneumatic device.
As proposed, reporters in the Onshore Natural Gas Processing,
Onshore Natural Gas Transmission Compression, Underground Natural Gas
Storage, and Natural Gas Distribution industry segments using
Calculation Method 2 would report for each facility, the total number
of natural gas pneumatic devices by type, the number of years in the
measurement cycle, the number of devices measured in the reporting
year, the primary measurement method (when emissions were measured),
the value of the emission factor for the reporting year as calculated
using equation W-1A and the devices upon which the emission factor is
based, the average time the devices were in service (i.e., supplied
with natural gas) during the calendar year, and the GHG emissions for
each type of natural gas pneumatic device.
We are finalizing calculation and reporting requirements as
proposed for Calculation Method 2 for pneumatic pumps in 40 CFR
98.233(c)(2) and 40 CFR 98.236(c)(4), respectively. Only facilities in
the Onshore Petroleum and Natural Gas Production and in the Onshore
Petroleum and Natural Gas Gathering and Boosting industry segments are
currently required to report emissions from pneumatic pumps and based
on the analysis performed as described in section III.C.1. of this
preamble and documented in the subpart W TSD, we are not adding this
source type for any other industry segment. As proposed, under the
final rule Calculation Method 2 for pneumatic pumps allows measurements
to be conducted over multiple years not to exceed 5 years for all pumps
at a facility in the Onshore Petroleum and Natural Gas Production or
Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments. For pneumatic pumps, we are finalizing as proposed that
reporters must measure for a minimum of 5 minutes while liquid is
continuously being pumped. We are also finalizing requirements, as
proposed, that the emissions must be calculated as the product of the
measured natural gas flow rate and the number of hours the pneumatic
pump was pumping. Under Calculation Method 2 for pneumatic pumps, we
are finalizing reporting data elements in 40 CFR 98.236(c)(4) per well-
pad site or gathering and boosting site to include the number of years
in the measurement cycle; an indication of whether emissions were
measured or calculated; the primary measurement method (when emissions
were measured); the value of the calculated emission factor, the total
number of pumps measured and used in calculating the emission factor,
the number of pumps that vented to atmosphere, and the estimated
average number of hours per year that the vented pumps were pumping
liquid (when the emissions were calculated); the total measured
CO2 and CH4 emissions; and the total calculated
CO2 and CH4 emissions.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to add direct measurement methods for natural
gas pneumatic devices and natural gas pneumatic pumps.
Comment: Numerous commenters opposed the requirement to measure all
devices at the facility using Calculation
[[Page 42110]]
Method 2 within a 5-year period, indicating that this requirement would
be overly burdensome. Some commenters suggested allowing facilities to
develop a facility-specific emission factor based on a representative
sampling of, for example, 20 percent of their pneumatic devices as an
alternative to measuring all pneumatic devices. Several commenters
suggested allowing the use of population factors to eliminate the
burden of the measurement/monitoring requirements proposed,
particularly since natural gas pneumatic devices will be phased out as
a result of NSPS OOOOb and EG OOOOc regulations.
Response: We recognize that some oil and gas facilities may be
geographically dispersed and may contain large numbers of pneumatic
devices, so measuring all devices may require significant effort. After
considering these comments, for the reasons discussed in section
III.E.3. of this preamble, the EPA has decided to provide a fourth
calculation method that provides a default population emission factor
for all devices. This also led to us further assessing and updating
from proposal Calculation Method 2 in the final rule, as explained
above, to allow facilities in the Onshore Petroleum and Natural Gas
Production and in the Onshore Petroleum and Natural Gas Gathering and
Boosting industry segments (those segments we assessed had facilities
that were geographically dispersed and contained large numbers of
pneumatic devices) to elect to use Calculation Method 2 for pneumatic
devices for some well-pad sites or gathering and boosting sites and to
elect to use other methods for other sites, subject to certain
requirements. Regarding the suggestion to allow one-time measurements
on a subset of devices to create site-specific emission factors, we
find the proposed requirement to instead measure all devices (over a
period of up to 5 years) provides the best approach for developing a
representative emission factor. This approach ensures that measurements
from all pneumatic devices will ultimately be used in the development
of the facility's emission factors rather than allowing measurements of
only a subset of pneumatic devices to be used, which could be selected
to bias the resulting emission factors low. Also, since the NSPS
requirements are expected to phase out these devices across many
industry segments, it is unclear how representative the measurements
made over the next few years will be for devices that may remain in
operation 5 years from now. As such, we did not revise the requirements
to allow the development and use of a site-specific emission factor for
natural gas pneumatic devices based on a one-time measurement of a
subset of devices. However, our final Calculation Method 2 requirements
we noted in this response (which allow measurements of natural gas
pneumatic devices at some well-pads or gathering and boosting sites
using Calculation Method 2 and allow the use of default population
emission factors for other sites within that facility) should
appropriately address commenters concerns, and should promote the use
of measurement data for facilities in the Onshore Petroleum and Natural
Gas Production or Onshore Petroleum and Natural Gas Gathering and
Boosting industry segments. As we noted, this approach is consistent
with our approach for equipment leaks where we have allowed and
continue to allow site-by-site equipment leak surveys to constitute a
complete leak detection survey for facilities in the Onshore Petroleum
and Natural Gas Production or Onshore Petroleum and Natural Gas
Gathering and Boosting industry segments.
Comment: One commenter suggested that Calculation Method 1 be used
on representative number of devices to ensure that measurements or
monitoring conducted under Calculation Methods 2 or 3 are accurate and
representative. The commenter also recommended that the EPA directly
address the issue of timing pre-inspections and repairs before formal
measurement and monitoring efforts to comply with GHGRP are carried out
to ensure measurements are done randomly with respect to repairs and
that the EPA require operators to report the date of measurements and
inspections performed for Calculation Method 2 or 3, and the date(s) of
any repairs performed on pneumatic controllers, including ``resetting''
controllers by manually actuating them. According to the commenter, it
would be essential to ensure that operators are not manipulating
results of Calculation Method 2 or 3 by repairing malfunctioning
controllers shortly before inspecting them or measuring their
emissions.
Response: We believe it would be difficult to ensure that a subset
of devices measured using continuous flow meters (Calculation Method 1)
would be representative of the pneumatic devices for which Calculation
Method 2 or 3 would be used. We agree that any measurements or
monitoring conducted according to Calculation Method 2 or 3 should be
done during representative periods, which would preclude monitoring
immediately after device repairs or manual actuations to reset the
device. Monitoring immediately after repairs or manual actuations of
devices that are stuck open would result in underestimating emissions
by not capturing the emissions associated with malfunctioning devices
and devices stuck open that occurred prior to the repair or manual
actuation, and that are likely to reoccur after the repair or manual
actuation. Therefore, in the final provisions we have added language in
both Calculation Methods 2 and 3 that measurements or monitoring must
be conducted during representative conditions and must not be conducted
immediately after device repair or manual actuation. With these
changes, we expect both Calculation Method 2 and 3 to provide accurate
estimates of emissions from pneumatic devices as they are based on
direct measurement of emissions, monitoring to identify periods of
malfunction, and emission factors representative of average emissions
and inclusive of malfunction emissions. Finally, we note that under the
final rule, we will still be able use the data obtained when
Calculation Method 1 is employed as a way to assess the data collected
via Calculation Method 2 or 3. For the reasons stated above, we
determined that it is not necessary or appropriate at this time to
require that a representative number of devices be measured using
continuous flow meters.
2. Intermittent Bleed Pneumatic Device Surveys
a. Summary of Final Amendments
The EPA is finalizing amendments to subpart W to provide an
alternative methodology to calculate emissions from intermittent bleed
pneumatic devices based on the results of inspections or surveys,
consistent with section II.B. of this preamble. Specifically, we are
finalizing provisions in 40 CFR 98.233(a)(3) providing an alternative
calculation methodology for facilities in the Onshore Petroleum and
Natural Gas Production and in the Onshore Petroleum and Natural Gas
Gathering and Boosting industry segments that monitor for
malfunctioning intermittent bleed pneumatic devices analogous to a
``leaker factor'' approach used for equipment leaks. In this final
rule, after consideration of concerns raised by commenters regarding
the applicability of emission factors developed based on data from
Onshore Petroleum and Natural Gas Production and Onshore Petroleum and
Natural Gas Gathering
[[Page 42111]]
and Boosting industry segments to other segments of the industry, we
are limiting this method to Onshore Petroleum and Natural Gas
Production and in the Onshore Petroleum and Natural Gas Gathering and
Boosting industry segments because our assessment is that those are the
only segments for which we have the appropriate data needed to develop
the emission factors for this approach at this time. We included this
``leaker factor'' approach in the 2022 Proposed Rule using data from an
API study as presented by Tupper (2019),\40\ and we included this
``leaker factor'' approach in the 2023 Subpart W Proposed Rule using
peer reviewed study data from Luck et al. (2019).\41\ The study
presented by Tupper included pneumatic devices predominately at oil and
gas production sites; the Luck et al. (2019) study evaluated pneumatic
devices exclusively and gathering and boosting compressor stations. We
decided to use the Luck et al. (2019) data in the 2023 Subpart W
Proposed Rule because it was peer reviewed and because we did not have
raw data from the API study to verify the summary data presented by
Tupper. These raw data were ultimately provided by API as part of their
comments on the 2023 Subpart W Proposal.
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\40\ Tupper, P. 2019. ``API Field Measurement Study: Pneumatic
Controllers'' presented at the EPA Stakeholder Workshop on Oil and
Gas in Pittsburgh, Pennsylvania, on November 7, 2019. Available in
the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
\41\ Luck, B., et al., 2019. ``Multiday Measurements of
Pneumatic Controller Emissions Reveal the Frequency of Abnormal
Emissions Behavior at Natural Gas Gathering Stations.''
Environmental Science & Technology Letters 6 (6), 348-352. DOI:
10.1021/acs.estlett.9b00158. Available in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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Because of the differences in the scope of these studies, as
discussed in further detail in section III.E.2.b. of this preamble, we
are finalizing this ``leaker factor'' approach using the Tupper (2019)
equation parameters for well-pad sites and using the Luck et al. (2019)
equation parameters for gathering and boosting sites. We refer to this
monitoring/leaker factor approach as Calculation Method 3 for pneumatic
devices. As noted in the GRI/EPA (1996) study, natural gas intermittent
bleed pneumatic devices in the natural gas processing, transmission,
and storage segments are used only for isolation valve actuators.\42\
These isolation valve actuators operate infrequently and have different
designs than the pneumatic device controllers used in the production
and gathering and boosting industry segments. Therefore, we determined
it was inappropriate to use either of these equation factors for the
other natural gas industry segments.
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\42\ GRI/EPA, 1996. Methane Emissions from the Natural Gas
Industry. Volume 12 Pneumatic Devices. GRI-94/0257.29; EPA-600/R-96-
080I. June. Available in the docket for this rulemaking, Docket ID.
No. EPA-HQ-OAR-2023-0234.
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As proposed, if Calculation Method 3 is elected, all intermittent
bleed pneumatic devices that vent to the atmosphere at the well-pad or
gathering and boosting site (except those for which natural gas supply
is measured according to Calculation Method 1) must be monitored at
least once in the calendar year according to the leak detection methods
in 40 CFR 98.234(a)(1) through (3), but with a monitoring duration of
at least 2 minutes or until a malfunction is identified. As discussed
in section III.E.1.b. of this preamble, after consideration of comment,
we are clarifying in the final provisions for Calculation Method 3,
consistent with our intent at proposal, that monitoring conducted for
Calculation Method 3 must be performed under representative conditions
and not immediately after conducting maintenance on the device or after
manually actuating the device.
Because under the final provisions we are allowing different well-
pads or gathering and boosting sites at the same facility in the
Onshore Petroleum and Natural Gas Production and in the Onshore
Petroleum and Natural Gas Gathering and Boosting industry segments to
elect to use different calculation methods (and thus are no longer
including in the final provisions the proposed requirement to measure
or monitor all devices at a facility within a 5-year period), we are
specifying that, with the exception of emissions from devices for which
natural gas supply is measured according to Calculation Method 1,
emissions from all devices within an individual well-pad or gathering
and boosting site must be calculated using the same method (i.e.,
Calculation Method 2 or Calculation Method 3 or Calculation Method 4,
if applicable) for a given calendar year.
Under Calculation Method 3, all intermittent bleed pneumatic
devices that are vented directly to the atmosphere present at the well-
pad or gathering and boosting site (except those for which natural gas
supply is measured according to Calculation Method 1) must be monitored
to identify malfunctioning devices at least once in the calendar year.
As proposed, under the final provisions, if a ``leak'' is observed
from the intermittent bleed pneumatic device for more than 5 seconds
during a device actuation, then the device is considered to be
``malfunctioning'' and the malfunctioning device emission factor
(similar to a leaker emission factor) would be applied to that device.
However, as discussed in section III.E.2.b. of this preamble, we are
including special provisions for devices that actuate for more than 5
seconds during normal operations, such as isolation valves on large
diameter pipes, to allow reporters to clearly identify these devices
using a permanent tag that includes the allowable actuation time for
the device under normal operating conditions. Emissions from
intermittent bleed pneumatic devices that were not observed to be
malfunctioning must be calculated based on the default emission factor
for ``properly functioning'' intermittent bleed pneumatic devices. We
are finalizing as proposed in the definition of the variable
``Tz'' in equation W-1C that the time that a device is
assumed to be malfunctioning must be determined following the same
procedures as the determination of the duration of equipment leaks
identified during a leak survey conducted under 40 CFR 98.233(q) (see
the variable ``Tp,z'' in equation W-30 for equipment leaks).
For example, if only one survey of intermittent bleed natural gas
pneumatic devices is conducted during the reporting year, then any
device found to be malfunctioning during the survey would be required
to be assumed to be malfunctioning for the entire year. This approach
effectively assumes that the emissions identified during the monitoring
survey are representative of the emissions that occur throughout the
year. We recognize that some malfunctioning devices may be repaired,
but other devices may also begin to malfunction. Based on our analysis
of equipment leak durations as conducted to support leaker factor
revisions to subpart W finalized in 2016, we maintain that this is the
most representative and accurate assumption when determining emission
from leaks during annual or periodic surveys.\43\
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\43\ De Figueiredo, M., 2016. Memorandum to Docket ID No. EPA-
HQ-OAR-2015-0764 regarding ``Greenhouse Gas Reporting Rule:
Technical Support for Leak Detection Methodology Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems
Final Rule.'' November 1. Available in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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Under Calculation Method 3, we are also finalizing as proposed
requirements that emissions from continuous bleed pneumatic controllers
(other than those for which the natural gas supply flow is measured as
specified in Calculation Method 1) would be determined either by
annually measuring the emissions from the pneumatic device vent
[[Page 42112]]
following the methods provided in Calculation Method 2 or by using
applicable default population emission factors for continuous high
bleed and continuous low bleed pneumatic devices.
We are finalizing as proposed reporting requirements for
intermittent bleed pneumatic devices for which emissions are calculated
using Calculation Method 3 under 40 CFR 98.236(b)(5), except (1) those
proposed reporting requirements pertaining to multi-year measurement
cycles as this is no longer an option under the final provisions, and
(2) those proposed reporting requirements applicable to segments other
than Onshore Petroleum and Natural Gas Production and Onshore Petroleum
and Natural Gas Gathering and Boosting industry segments, which are not
permitted the option to use this methodology under the final
provisions. Therefore, reporters using proposed Calculation Method 3
must report for each well-pad or gathering and boosting site, as
applicable, the total number of natural gas pneumatic devices by type,
the method used to estimate emissions from continuous bleed natural gas
pneumatic devices, the frequency of monitoring for intermittent
devices, the number of devices at the facility monitored in the
reporting year, the number found to be malfunctioning, the average time
the malfunctioning devices were assumed to be malfunctioning under 40
CFR 98.236(b)(5), the average time that devices that were monitored but
were not detected as malfunctioning year were in service (i.e.,
supplied with natural gas) during the calendar year, and the GHG
emissions for each type of natural gas pneumatic device. For more
information regarding Calculation Method 3 for natural gas intermittent
bleed pneumatic devices, see the subpart W TSD, available in the docket
for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to survey intermittent bleed natural gas
pneumatic devices.
Comment: Similar to the comments received regarding Calculation
Method 2, numerous commenters opposed the requirement to monitor all
devices at the facility within a 5-year period, indicating that this
requirement would be overly burdensome. Some commenters suggested
allowing facilities to develop a facility-specific emission factor or
fraction of malfunctioning devices based on a representative monitoring
of, for example, 20 percent of their intermittent bleed pneumatic
devices. Several commenters suggested allowing the use of population
factors for intermittent bleed devices to eliminate the burden of the
monitoring requirements proposed.
Response: As explained previously, in the final rule the EPA is
adding a fourth calculation method that provides a default population
emission factor for all devices. This option, combined with the update
from proposal in the final provisions allowing different well-pad or
gathering and boosting sites at the same facility in the Onshore
Petroleum and Natural Gas Production and in the Onshore Petroleum and
Natural Gas Gathering and Boosting industry segments to elect to use
different calculation methods, appropriately addresses commenters'
concerns regarding the requirement to measure or monitor all natural
gas pneumatic devices in such facilities that we agreed could be
geographically dispersed and contain a large number of pneumatic
devices. Under the final provisions for these industry segments that
may use Calculation Method 3, the proposed requirement to measure and
monitor all devices at a facility over a period of up to 5 years is not
included and instead was updated to a requirement to calculate
emissions from all devices within an individual well-pad or gathering
and boosting site using the same method (i.e., Calculation Method 2 or
Calculation Method 3 or Calculation Method 4, if applicable) for a
given calendar year. Regarding the suggestion to allow monitoring on a
subset of devices to create site-specific fraction of malfunctioning
devices as opposed to all devices within an individual well-pad or
gathering and boosting site, we expect that the fraction of
malfunctioning devices will be a function of the age of the device,
make and model number of the device, and the number of actuations per
year of the device. We also expect that the number of devices found
malfunctioning would change based on the implementation of a monitoring
survey (assuming some or all of the malfunctioning devices are
repaired). Requiring only a subset of devices to be monitored would
allow facilities to monitor devices expected to emit at lower rates and
bias the resulting emission factor low. Therefore, we find the final
requirement to monitor all devices at a site provides the best approach
for developing a representative fraction of malfunctioning devices for
that year for that site. Also, since the NSPS requirements are expected
to phase out these devices across many industry segments, it is unclear
how representative the fraction of malfunctioning devices as determined
over the next few years will be for devices that may remain in
operation 5 years from now. As such, we did not revise the requirements
to allow the development and use of a site-specific fraction of
malfunctioning intermittent bleed natural gas pneumatic devices.
However, we expect that the updates in the final provisions that we
discussed earlier in this response to promote the use of monitoring
data for facilities in the Onshore Petroleum and Natural Gas Production
or Onshore Petroleum and Natural Gas Gathering and Boosting segments,
given that they allow monitoring of intermittent bleed natural gas
pneumatic devices at some well-pads or gathering and boosting sites
using Calculation Method 3 and allow the use of default emission
factors for other sites within that facility. This approach is
consistent with our approach for equipment leaks where we have allowed
and continue to allow site-by-site equipment leak surveys to constitute
a complete leak detection survey for facilities in the Onshore
Petroleum and Natural Gas Production or Onshore Petroleum and Natural
Gas Gathering and Boosting industry segments.
Comment: We received numerous comments regarding the proposed
emission factors for properly functioning and malfunctioning
intermittent bleed pneumatic devices within the equation for
Calculation Method 3. Several commenters suggested that the properly
operating device emission factor from Tupper as included in the 2022
Proposed Rule should be used over the factor from Luck et al. (2019) as
included in the 2023 Subpart W Proposal. According to these commenters,
the Tupper study is more representative because it measured a larger
number of devices predominately at production sites whereas Luck study
included only gathering and boosting sites and measured emissions from
much fewer devices. A couple of commenters suggested developing an
aggregated emission factor considering the data from both of these
studies and one commenter suggested that the EPA also assess data from
Footer et al. (2023) in developing aggregated emission factors for use
with Calculation Method 3. According to one commenter, Allen et al.
(2015) reported a national average of 14.0 scf/hr for controllers (both
properly functioning and not properly
[[Page 42113]]
functioning) associated with compressors, which is approximately three
times the average emission rate for controllers in service of other
equipment (5.0 scf/hr for both properly functioning and not functioning
properly). Some commenters suggested that the EPA allow reporters to
use engineering calculations for intermittent bleed devices determined
to be properly functioning in place of or as an alternative to the
default emission factor for properly functioning intermittent bleed
pneumatic devices.
Response: We agree with commenters that the API/Tupper study was
primarily focused on production sites while the Luck study was focused
on gathering and boosting sites. After considering these comments, we
determined it was appropriate to base the final emission factors on the
API/Tupper study for well-pad sites at an Onshore Petroleum and Natural
Gas Production or Onshore Petroleum facility because the API/Tupper
study was focused on production sites. We also determined it was
appropriate to base the final emission factors on Luck et al. (2019)
for gathering and boosting sites at an Onshore Petroleum and Natural
Gas Gathering and Boosting facility because the Luck study was focused
on gathering and boosting sites. We also determined it was appropriate
to base the final emission factors on these respective studies because,
based on the comparison of pneumatic device emission factors between
devices associated with compressors and devices associated with other
equipment as presented in Allen et al. (2015),\44\ it is logical to
conclude that properly operating intermittent bleed devices at
gathering and boosting facilities, which often have more compressors,
would have higher emissions per device than devices at onshore
production facilities, which have fewer compressors.
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\44\Allen, D.T., et al., 2015. ``Methane Emissions from Process
Equipment at Natural Gas Production Sites in the United States:
Pneumatic Controllers.'' Environ. Sci. Technol. 49, 633-640.
dx.doi.org/10.1021/es5040156. Available in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------
For other industry segments, we initially expected that the
pneumatic devices used at the Onshore Petroleum and Natural Gas
Gathering and Boosting industry segment with its compressor stations
would be more analogous to the other mid and downstream industry
segments. This is evidenced by the fact that the correctly functioning
intermittent bleed device emission factor of 2.8 scf/hr from Luck et
al. (2019) which is based on measurements at gathering and boosting
sites, is very similar to the historic population emission factor used
in subpart W for the Onshore Natural Gas Transmission Compression
industry segment of 2.35 scf/hr, which was based on engineering
calculations that assume the device is properly functioning. However,
after reviewing available data, we determined that we did not have
sufficient data to provide separate malfunctioning and non-
malfunctioning emission factors for Calculation Method 3 for Onshore
Natural Gas Processing, Onshore Natural Gas Transmission Compression,
Underground Natural Gas Storage, and Natural Gas Distribution
facilities, and are not allowing Calculation Method 3 as an option for
these industry segments at this time. As noted in the GRI/EPA 1996
study, natural gas intermittent bleed pneumatic devices used in the
natural gas processing, transmission, and storage industry segments are
isolation valve actuators. These isolation valve actuators actuate
seldomly and have different designs and functions from the natural gas
intermittent bleed pneumatic controllers measured in the API/Tupper
study or the Luck et al. (2019) study. We found no study data available
focused on isolation valve actuators at these ``downstream'' industry
segments by which to characterize emissions from malfunctioning
devices. For more information on our review of available data on
pneumatic devices by industry segment, see the subpart W TSD, available
in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
We also considered whether the correctly functioning emission
factor should be based on engineering calculations or other measurement
data. While we agree that engineering calculations can be accurate,
this is the case only when accurate estimates of the actuation
frequency can be made, which will not necessarily be the case for all
intermittent devices. We also considered that, if reporters could elect
to use the default factor for some intermittent bleed devices and use
engineering calculations for other devices, facilities would likely use
engineering calculations only for those devices that have emissions
less than the default and use the default for all other devices,
thereby biasing the emissions low and not resulting in accurate total
emissions reported. We also note that the use of engineering
calculations is allowed under Calculation Method 2 for devices that do
not have measurable emissions during the measurement period. Reporters
preferring to use device-specific engineering calculations for properly
functioning intermittent bleed pneumatic devices are encouraged to use
Calculation Method 2. Therefore, we are not providing or allowing
facilities to estimate device-specific emissions based on engineering
calculations when using Calculation Method 3.
Comment: A few commenters noted that some intermittent bleed
devices actuate longer the 5 seconds during normal actuations such that
assigning these devices as malfunctioning would overstate their
emissions when applying Calculation Method 3. One commenter noted that,
as an industry rule of thumb, the actuation time for a valve opening
and closing is one to two seconds per inch of pipe diameter. According
to the commenter, the proposed monitoring methodology would mistakenly
designate devices on pipes six inches or greater in diameter as
``malfunctioning.'' Another commenter noted that throttling
intermittent bleed pneumatic devices should not be assumed to be
malfunctioning or leaking merely because it actuates for longer than 5
seconds. This commenter recommended that the final rule should provide
that an operator must make an engineering determination confirmed by
field inspections that a throttling pneumatic device is actually
malfunctioning before using the malfunctioning device emission factor.
Response: While we maintain that the 5-second duration of emissions
is reasonable for the vast majority of pneumatic devices, we
acknowledge that some larger devices may have actuation times exceeding
5 seconds. Therefore, we are including provisions in the final rule for
facilities to a priori identify those select devices that are expected
to have actuation emissions lasting longer than 5 seconds (like an
isolation valve on a 12-inch pipe) and the actuation times expected for
each of those devices. In the final rule, we are requiring reporters
that use Calculation Method 3 to specifically identify those
intermittent bleed devices with actuation times longer than 5 seconds
using a tagging system or similar method that indicates the expected
actuation time for the device. Facilities will also be required to
report the number of devices for which they are using extended emission
duration provisions. With these and corresponding provisions for
devices with longer actuation times, we maintain that the final rule
provides adequate provisions to accurately assess whether an
intermittent bleed device is properly functioning during a monitoring
survey.
[[Page 42114]]
3. Revisions to Emission Factors
a. Summary of Final Amendments
Regarding pneumatic devices, in our 2022 Proposed Rule, we proposed
to update the default population emission factors for all device types
based on recent study data. In the 2023 Subpart W Proposal, for
intermittent bleed devices, we proposed to remove default population
emission factors altogether and require measurement or monitoring of
these devices. In the proposal, we requested comment on this approach
and also requested comment on default population emission factors for
intermittent bleed devices in the event that this option was retained
in the final rule. In this final rule, under Calculation Method 4, we
are allowing the option to continue to use default population emission
factors to estimate emissions from both intermittent bleed devices and
continuous bleed devices at the well-pad site, gathering and boosting
site, or facility level, as applicable. Consistent with the overall
intent of this final rulemaking for reporting to be based on empirical
data, consistent with section II.B. of this preamble, if measurement or
survey data are available, we are requiring that emissions be
calculated based on those data when available. Therefore, in the final
rule, reporters cannot use Calculation Method 4 for devices for which
natural gas supply is measured according to Calculation Method 1 or for
devices at sites for which measurements or monitoring were conducted in
accordance with Calculation Method 2 or 3. For all other devices,
Calculation Method 4 is allowed. Regarding pneumatic pumps, the final
method based on a default emission factor is the same as the
methodology in 40 CFR 98.233(c) of the existing rule and is referred to
as Calculation Method 3 for pneumatic pumps in the final rule. As
proposed, for pneumatic pumps we are maintaining the existing default
population emission factor.
Under Calculation Method 4 for pneumatic devices, we are finalizing
that the default population emission factor for continuous low bleed
pneumatic devices is 6.8 standard cubic feet per hour per device (scf/
hr/device) for all applicable industry segments, based on recent study
data and consistent with the 2023 Subpart W Proposal. For continuous
high bleed pneumatic devices under Calculation Method 4, consistent
with the 2023 Subpart W Proposal, based on recent study data we are
finalizing a default population emission factor of 21 scf/hr/device for
devices in the Onshore Petroleum and Natural Gas Production and in the
Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments and a default population emission factor of 30 scf/hr/device
for continuous high bleed devices in the Onshore Natural Gas
Processing, Onshore Natural Gas Transmission Compression, Underground
Natural Gas Storage, and Natural Gas Distribution industry segments.
For facilities in the Onshore Petroleum and Natural Gas Production
and in the Onshore Petroleum and Natural Gas Gathering and Boosting
industry segments, we are finalizing an intermittent bleed pneumatic
device default population emission factor of 8.8 scf/hr/device and for
facilities in the Onshore Natural Gas Processing, Onshore Natural Gas
Transmission Compression, Underground Natural Gas Storage, and Natural
Gas Distribution industry segments, we are finalizing an intermittent
bleed pneumatic device default population emission factor of 2.3 scf/
hr/device, based on recent study data and consistent with those
population emission factors that we included in the 2022 Proposed Rule
and that we discussed in the preamble to the 2023 Subpart W Proposal
and for which we requested comment in the event the final rule included
such a method for intermittent bleed devices.
For more information regarding this review and development of the
emission factors, see the subpart W TSD, available in the docket for
this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
Finally, we note that for pneumatic pumps, we are maintaining the
existing default population emission factor, as proposed. Reporters
that do not have or do not elect to install a flow meter on the natural
gas supply line dedicated to any one or more natural gas driven
pneumatic pumps and that do not elect to measure the volumetric flow
rate of emissions from all the natural gas driven pneumatic pumps
vented directly to the atmosphere at a well-pad or gathering and
boosting site are required to continue using the current default
population emission factor for pneumatic pumps vented directly to the
atmosphere under Calculation Method 3 for pneumatic pumps.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments and requests for comments on population
emission factors for natural gas pneumatic devices and natural gas
pneumatic pumps.
Comment: Numerous commenters recommended that the EPA provide a
default emission factor for intermittent bleed devices. Many commenters
supported the EPA's suggested intermittent bleed pneumatic device
emission factor of 8.8 scf/hr; a few commenters suggested this default
emission factor should be lower. Commenters suggesting a lower emission
factor indicated that if the EPA used a device-weighted average, rather
than considering averages by study, and had included data from the
additional studies review, a lower emission factor would be calculated.
Several commenters opposed the proposed default emission factor for
continuous low bleed devices of 6.8 scf/hr arguing that it is
incongruous for a low bleed device, which is defined as a device with
continuous bleed rates less than 6 scf/hr, to have an emission factor
greater than 6 scf/hr.
Response: After considering these and other comments, the EPA is
adding a fourth calculation method that provides a default population
emission factor for all devices. In the final rule, we are including a
default population emission factor of 8.8 scf/hr for intermittent bleed
pneumatic devices in the Onshore Petroleum and Natural Gas Production
and the Onshore Petroleum and Natural Gas Gathering and Boosting
industry segments. For Onshore Natural Gas Processing, Onshore Natural
Gas Transmission Compression, Underground Natural Gas Storage, and
Natural Gas Distribution industry segments, we are finalizing an
intermittent bleed default population emission factor of 2.3 scf/hr. We
determined that these are the most appropriate values after considering
all available data. Regarding commenters suggesting that we develop the
emission factor weighted by the number of device measurements, we
decided that may not be representative. First, the Prasino Group, which
had high number of device measurements, selected device model numbers
to test and tested 30 of each model number. The equal number of
measurements by model number is not necessarily reflective of the
proportion of devices in use at U.S. production and gathering and
boosting facilities. Second, Luck et al. (2019) measured emissions from
pneumatic devices over 76 hours, which is 150 to 300 times longer than
other measurement studies. As such, even though Luck et al. (2019)
measured fewer devices, their measurements are expected to be much more
accurate and representative of device emissions, particularly for
devices that may have
[[Page 42115]]
excess emissions sporadically over time. Based on the different study
approaches and measurement methods, we determined that equally
weighting each study's average emission factor was appropriate. We did
not include study data from studies that relied entirely or
predominately on engineering calculations because those studies would
not fully characterize excess emissions from malfunctioning devices, so
would likely be biased low. For more information on our development of
the final population emission factors, see the subpart W TSD for the
final rule, available in the docket for this rulemaking, Docket ID. No.
EPA-HQ-OAR-2023-0234.
With respect to the proposed continuous low bleed default
population emission factor of 6.8 scf/hr, we maintain that this is the
appropriate default population emission factor under Calculation Method
4, as under this method the emission factor needs to account for times
the continuous low bleed device may be malfunctioning. Most reporters
use the manufacturer's design steady state bleed rates to determine
whether a continuous bleed device is classified as low or high bleed.
Therefore, they classify a continuous bleed controller as a low bleed
device when the manufacturer's design steady state bleed rate is 6 scf/
hr or less. However, across numerous measurement
studies,45 46 47 the study data show that ``malfunctioning''
low bleed devices can emit at higher rates than the design steady state
bleed rate. That is, devices with steady state bleed rates of less than
6 scf/hr (``low bleed'' devices) could often have measured emissions
higher the 6 scf/hr. We consider it essential to set the low continuous
bleed emission factor at the average emission rate determined across
all low bleed devices, including those devices that exhibited excess
emissions associating with malfunctioning devices. As such, we maintain
that the final low bleed default population emission factor is the most
appropriate and accurate value for estimating average emissions from
these devices under Calculation Method 4.
---------------------------------------------------------------------------
\45\ The Prasino Group (2013). ``Determining Emissions Factors
for Pneumatic Devices in British Columbia--Final Field Sampling
Report.'' November 15. Also, ``Final Report--For Determining Bleed
Rates for Pneumatic Devices in British Columbia.'' December 18.
Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2023-0234.
\46\ Allen, D.T., et al. (2015). ``Methane Emissions from
Process Equipment at Natural Gas Production Sites in the United
States: Pneumatic Controllers.'' Eviron. Sci. Technol. No. 49, pp.
633-640. Available in the docket for this rulemaking, Docket ID. No.
EPA-HQ-OAR-2023-0234.
\47\ Luck, B., et al., 2019. ``Multiday Measurements of
Pneumatic Controller Emissions Reveal the Frequency of Abnormal
Emissions Behavior at Natural Gas Gathering Stations.''
Environmental Science & Technology Letters 6 (6), 348-352. DOI:
10.1021/acs.estlett.9b00158. Available in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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4. Hours of Operation of Natural Gas Pneumatic Devices
a. Summary of Final Amendments
As proposed, consistent with section II.D. of this preamble, we are
finalizing revisions to the definition of variable ``Tt'' in
existing equation W-1 (which is now equation W-1B) in 40 CFR 98.233 and
the corresponding reporting requirements in proposed 40 CFR
98.236(b)(4)(ii)(C)(4), (b)(4)(iii)(C)(4), and (b)(5)(i)(C)(2) to use
the term ``in service (i.e., supplied with natural gas)'' rather than
``operational'' or ``operating,'' to clarify the original and current
intended meaning of that variable and term. We are making two minor
revisions to the proposed calculation requirements within Calculation
Method 2 to clarify the requirements with respect to ``in service''
time. First, we are adding a paragraph at 40 CFR 98.233(a)(2)(iii)(E)
to clarify how to use calculate the average measured emission rate
using the entire time of the measurement period, not just times when
the device is actively actuating, consistent with the rate needed
considering ``in service'' time. Second, we are deleting proposed
paragraph at 40 CFR 98.233(a)(2)(v)(C)(6), which specified how to
calculate an annual average emission rate based on actuation volumes
and number of actuation cycles and that time ``in service.'' This
average emission rate is not needed under this scenario and is not
needed to calculate the emissions under Calculation Method 2.
Therefore, we are removing this calculation requirement in the final
rule.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to clarify the time variable and meaning of
``in service'' time for use in the pneumatic device calculation
methods.
Comment: Most commenters supported the clarification regarding time
in service. A few commenters opposed the use of in service time
because, according to these commenters, use of the in service time
(default of 8,760 hours per year) assumes that intermittent bleed
devices are continuously emitting when applying the population emission
factor and even when applying Calculation Method 3 for properly
functioning devices. Because intermittent bleed devices do not
continuously emit natural gas under normal operations, the commenters
suggest that reporters be allowed to use actuation times and cycle
counts to determine the time parameter in the pneumatic device emission
calculations. According to these commenters, this approach would allow
the use of ``empirical data'' and yield more accurate emissions
estimates.
Response: We strongly disagree with the commenters that actuation
time rather than in-service time should be used in Calculation Method 3
or 4. The emission factor used in Calculation Method 3 for correctly
operating intermittent bleed devices is not the emission rate measured
only during an actuation but represents the average emission rate
measured across the measurement period and includes periods when the
device is actuating AND when it is not. Thus, the emission factor's
denominator is the time the device is ``in service (i.e., supplied with
natural gas)'' and not the time the device was actuating. Therefore, we
must use the same definition of time in service when applying the
emission factors used in Calculation Method 3 to determine annual
emissions. The exact same argument applies when using the default
population emission factors in Calculation Method 4. We note that in
many studies, no emissions were measured from the devices over a 15-
minute period. These ``zero'' emissions were factored into the average
population emission factor in these studies. Because the emission
factors were developed considering cumulative emissions released
divided by the cumulative time period the device was being measured
(including measurement periods when there were no actuations), the only
accurate definition of the time variable in the pneumatic device
calculation equations is the time in service (i.e., the time the device
is supplied with natural gas). Use of actuation times in these
equations would significantly underestimate emissions and would not
result in accurate reporting of total emissions. We note that this use
of consistent logic in matching between the measurement approach and
the calculation approach is reflected within each calculation method.
For example, when measurements are made under Calculation Method 2, we
require calculation of the average emission rate over the measurement
period. We are adding paragraph at 40 CFR 98.233(a)(2)(iii)(E) to
clarify how this
[[Page 42116]]
calculation is made and that it includes the entire measurement period,
not just times when the device is actuating. This is also consistent
with how the emission factors are calculated under Calculation Methods
3 and 4 and consistent with the use of ``in service'' hours for the
annual emission calculation. When there is no measurable flow from the
device, actuation volumes and number of actuation cycles can be used
under Calculation Method 2 to estimate annual emissions from those
devices and the time ``in service'' is not needed. We proposed to
require calculation of the annual average emission rate considering the
number of hours the device is ``in service'' but that requirement does
not impact the annual emissions rate to be reported for that device.
Since the average emission rate is not used in this case, we are
removing that paragraph of the calculation procedures for the average
emission rate, which was proposed at 40 CFR 98.233(a)(2)(v)(C)(6).
5. Natural Gas Pneumatic Devices and Natural Gas Driven Pneumatic Pumps
Routed to Control
We understand that emissions from some natural gas pneumatic
devices and/or natural gas driven pneumatic pumps are routed to control
(i.e., a flare, combustion unit, or vapor recovery system). The
population emission factor is based on natural gas vented directly to
the atmosphere from these pneumatic devices/pumps and does not
accurately reflect emissions from controlled pneumatic devices/pumps.
Therefore, consistent with section II.B. of this preamble, we are
finalizing as proposed revisions to 40 CFR 98.233(a) and (c) to clarify
requirements for calculating emissions from natural gas pneumatic
devices and natural gas driven pneumatic pumps, respectively, that are
vented directly to the atmosphere versus pneumatic devices/pumps that
are routed to control, consistent with the intent of this rule. The EPA
received only minor comments regarding natural gas pneumatic devices
and natural gas driven pneumatic pumps routed to control. See the
document Summary of Public Comments and Responses for 2024 Final
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems under the Greenhouse Gas Reporting Rule in Docket ID. No.
EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
We are finalizing revisions to 40 CFR 98.233(a) and (c) to clarify
that the existing population emission factor calculation methodology is
intended to apply only to pneumatic devices/pumps vented directly to
the atmosphere, as proposed. The new calculation methodologies
described in sections III.E.1. and 2. of this preamble also specify
that they apply only to pneumatic devices/pumps vented directly to the
atmosphere.
We are finalizing requirements that flared emissions from natural
gas pneumatic devices or pumps are not required to be calculated and
reported separately from other flared emissions, consistent with the
2023 Subpart W Proposal. Instead, emission streams from natural gas
pneumatic devices or pumps that are routed to flares are required to be
included in the calculation of total emissions from the flare according
to the procedures in 40 CFR 98.233(n) and reported as part of the total
flare stack emissions according to the procedures in 40 CFR 98.236(n),
in the same manner as emission streams from other source types that are
routed to the flare. Similarly, as proposed, emissions from natural gas
pneumatic devices or pumps that are routed to a combustion unit are
required to be combined with other streams of the same fuel type and
used to calculate total emissions from the combustion unit as specified
in 40 CFR 98.233(z) and reported as part of the total emissions from
the combustion unit as specified in 40 CFR 98.236(z). We are also
finalizing as proposed provisions that specify that reporters would not
calculate or report emissions from natural gas pneumatic devices or
pumps if the emissions are routed to vapor recovery and are not
subsequently routed to a combustion device (e.g., are routed back to
process or sales). Finally, we are making clarifying edits to the
language in 40 CFR 98.233(c)(4) for pumps that are vented to the
atmosphere for part of the year and routed to a flare, combustion, or
vapor recovery for another part of the year.
We are also finalizing as proposed requirements in 40 CFR
98.236(b)(2) and 98.236(c)(2) to report the total number of continuous
low bleed, continuous high bleed, and intermittent bleed natural gas
pneumatic devices and the total number of natural gas driven pneumatic
pumps at the site (regardless of vent disposition), the number of these
devices/pumps that are vented to the atmosphere for at least a portion
of the year, and the number of these devices/pumps that are routed to
control for at least a portion of the year (which includes natural gas
pneumatic devices/pumps routed to a flare, combustion unit, or vapor
recovery system). We added a sentence at 40 CFR 98.233(a)(8) and (c)(4)
to further clarify these reporting requirements apply even when
emissions from the pneumatic devices or pumps are required to be
reported under other sources (flares or combustion) or not required to
be reported.
F. Acid Gas Removal Unit Vents
1. Reporting of Methane Emissions From Acid Gas Removal Units
a. Summary of Final Amendments
Reporters currently report only CO2 emissions from AGR
vents using one of the four calculation methodologies provided in 40
CFR 98.233(d). The EPA is finalizing as proposed the amendments to 40
CFR 98.233(d) and 98.236(d) to require calculation and reporting of
CH4 from AGR vents, which will improve the coverage of total
CH4 emissions reported to subpart W, consistent with section
II.A. of this preamble. As proposed, the final amendments provide three
calculation methods for reporting of CH4 from AGR vents and
nitrogen removal unit vents, with modifications from proposal regarding
when those methods apply. The final Calculation Method 2 requires, as
proposed, that if a vent flow meter is installed, including the
volumetric flow rate monitor on a continuous emissions monitoring
system (CEMS) for CO2, the reporter must use the annual
volume of vent gas from the flow meter and the CH4
composition from either a continuous gas analyzer or quarterly gas
samples to calculate emissions using equation W-3 (40 CFR
98.233(d)(2)). However, based on consideration of public comments
regarding safety concerns with measuring the composition of vent gas if
high concentrations of H2S are expected to be present, the
EPA is finalizing a modification from proposal in Calculation Methods 2
and 4 for CH4 and an amendment to Calculation Methods 2 and
4 for CO2 that allows reporters to use Calculation Method 4,
modeling simulation via software (40 CFR 98.233(d)(4)), for an AGR even
if a vent flow meter, including the volumetric flow rate monitor on a
CEMS for CO2, is installed. Reporters who elect to use
Calculation Method 4 for an AGR with a vent flow meter will be required
to determine the difference between the annual volume of vent gas
measured by the vent meter and the simulated annual volume of vent gas
(as calculated by new equation W-4D), and report the annual volume of
vent gas measured by the vent meter, the simulated annual volume of
vent gas from the model, and a reason for the difference in flow rates
if the difference (as calculated by new equation W-4D) is greater than
20 percent. The EPA considers the selected
[[Page 42117]]
20 percent interval to be low enough to ensure reasonable agreement
between the flow rates obtained by the different methods but high
enough to reasonably account for the expected uncertainties, as
described in more detail in section III.F.1.b. of this preamble.
Under the final provisions, if neither a CEMS for CO2
nor a vent flow meter is installed, for CH4 reporters may
use Calculation Method 3, engineering equations, with one exception (40
CFR 98.233(d)(3)) or Calculation Method 4, modeling simulation via
software (40 CFR 98.233(d)(4)). For Calculation Method 3, the EPA is
finalizing as proposed the revisions to the existing equations W-4A and
W-4B and finalizing as proposed the new equation W-4C. With the
addition of CH4 as a component for these equations,
reporters need to have information on four parameters rather than the
three they currently need to know. Based on consideration of public
comment, the EPA is adding a specification in the final provision that
if the volumetric emissions calculated using Calculation Method 3 are
less than or equal to 0 cubic feet per year, the reporter may not use
this calculation method for either CH4 or CO2 and
must instead use Calculation Method 4. As noted in section III.F.1.b.
of this preamble, there could be times when the normal variability in
flow rate and concentration measurements could result in concerns with
the accuracy of Calculation Method 3, particularly for CH4,
and in those cases, modeling simulations can take into account more
variables than the final engineering equations, which will result in
more accurate emissions calculations. For Calculation Method 4, the EPA
is finalizing as proposed the addition of the CH4 content of
the feed natural gas and the outlet natural gas as parameters that must
be used to characterize emissions. This specification is analogous to
the existing requirement to use acid gas content of the feed natural
gas and the acid gas content of outlet natural gas to characterize
CO2 emissions.
The EPA is also finalizing as proposed the addition of relevant
reporting elements for CH4 from each AGR to 40 CFR
98.236(d). The additional data elements include annual CH4
emissions vented directly to the atmosphere; annual average volumetric
fraction of CH4 in the vent gas if using Calculation Method
2; additional inputs for Calculation Method 3, depending on the
equation used (i.e., as applicable, the annual average volumetric
fraction of CH4 in the natural gas flowing out of the AGR,
annual average volumetric fraction of CH4 content in natural
gas flowing into the AGR, annual average volumetric fraction of
CO2 in the vent gas exiting the AGR and annual average
volumetric fraction of CH4 in the vent gas exiting the AGR);
and the CH4 content of the feed natural gas and outlet
natural gas if using Calculation Method 4.
Under the current provisions of subpart W, reporters with AGRs
routed to flares are required to report the CO2 emissions
from the AGR that pass through the flare as AGR vent emissions, and the
emissions that result from combustion of any CH4 in the AGR
vent stream are reported as flare stack emissions. The EPA proposed to
revise subpart W such that AGR vents routed to a flare would follow the
same calculation requirements as other emission source types and would
begin reporting flared AGR emissions (CO2, CH4,
and N2O) separately from vented AGR emissions
(CO2 and CH4). While the final flaring provisions
differ somewhat from the proposed provisions, as explained in more
detail in section III.N. of this preamble, the final amendments
generally specify as proposed that vented AGR emissions include only
those emissions vented directly to the atmosphere and emissions routed
to a flare are considered flare stack emissions. In a similar
amendment, we are finalizing as proposed the specification that for AGR
vents routed to an engine, reporters will calculate CO2,
CH4, and N2O emissions using the provisions of 40
CFR 98.233(z) or subpart C, whichever is applicable to that industry
segment. We are also finalizing as proposed the requirement that AGRs
routed to an engine or flare for the entire year report the information
in amended 40 CFR 98.236(d)(1) except for the calculation method and
the CO2 and CH4 emissions from the unit, if the
flare emissions are calculated using continuous monitors, as finalized
in 40 CFR 98.233(n). If the AGR routed to an engine or flare only for
part of the year, the other information in amended 40 CFR 98.236(d)(1)
will be required to be reported for the part of the year in which
emissions were vented directly to the atmosphere. Consistent with the
final provisions of 40 CFR 98.233(n), if the flow rate and composition
of the AGR or NRU stream routed to the flare is determined using a
calculation method in 40 CFR 98.233(d), then reporters will be required
to provide the information in amended 40 CFR 98.236(d)(1) and (2). In a
related amendment, because gas routed to a flare will be calculated and
reported as flared emissions and not vented emissions, we are revising
the definition of ``acid gas removal unit (AGR) vent emissions'' to
remove the phrase ``or a flare,'' so that it includes only those acid
gas emissions released to the atmosphere.
Finally, after consideration of public comments regarding the
inconsistent calculation of emissions from AGRs with vapor recovery
systems compared to the treatment of emissions routed to vapor recovery
systems for other source categories, the EPA is adding provisions for
AGR vents routed to vapor recovery systems to final 40 CFR
98.233(d)(11) and correspondingly removing the existing (now redundant)
provisions in current 40 CFR 98.233(d)(11) that direct reporters to
adjust emissions downward to account for CO2 emissions
recovered and transferred outside the facility. For AGRs and nitrogen
removal units with vents routed to vapor recovery systems and flares,
the final provisions in 40 CFR 98.233(d)(11) specify how to account for
emissions during periods when emissions from those vents are released
directly to the atmosphere instead (i.e., the vapor recovery system or
flare is bypassed). These final provisions are similar to the final
provisions for dehydrators routed to vapor recovery systems or flares.
Reporters will be required to indicate whether the vent was routed to a
vapor recovery system, and if so, whether it was routed for the entire
year or only part of the year in 40 CFR 98.236(d)(1)(iv); we are
correspondingly removing the existing (now redundant) provisions in
current 40 CFR 98.233(d)(1)(iv) to report whether CO2
emissions were recovered and transferred outside the facility. Similar
to the reporting for AGRs routed to an engine or flare, AGRs routed to
a vapor recovery system for the entire year report the information in
amended 40 CFR 98.236(d)(1) except for the calculation method and the
CO2 and CH4 emissions from the unit. If the AGR
is routed to a vapor recovery system only for part of the year, the
other information in amended 40 CFR 98.236(d)(1) is required to be
reported for the part of the year in which emissions were vented
directly to the atmosphere.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to add reporting of CH4 emissions
from AGRs.
Comment: Commenters expressed concern about the accuracy of
Calculation Method 3 for calculating CH4 emissions from AGRs,
particularly
[[Page 42118]]
equation W-4C, which relies on the AGR inlet and outlet flow rates and
compositions. Commenters indicated that the volume of methane vented
from AGRs is generally negligible when compared to the overall methane
flow through the AGR, and the difference in methane concentration in
the AGR inlet and outlet streams may be negligible. Consequently, using
this method could potentially yield negative methane emissions values
or otherwise inaccurate estimates.
Response: The EPA has considered the comments and agrees that there
could be times when the normal variability in flow rate and
concentration measurements could result in concerns with the accuracy
of Calculation Method 3; however, the EPA does not find it appropriate
to remove the ability to use Calculation Method 3 or equation W-4C in
all cases. Therefore, in response to this comment, the EPA is
finalizing the addition of a statement in 40 CFR 98.233(d)(3) to
indicate that if the annual total volumetric emissions for an AGR or
nitrogen removal unit vent calculated using Calculation Method 3 are
less than or equal to 0 cubic feet per year, a reporter may not use
this calculation method for that vent. Aside from this newly finalized
restriction on Calculation Method 3, the existing rule allows reporters
to choose between Calculation Method 3 or Calculation Method 4.
Therefore, if the calculated emissions are greater than 0 cubic feet
per year but the reporter is concerned that the results may not be
accurate, the reporter may choose to use Calculation Method 4 instead,
as provided by the existing rule.
Comment: Commenters noted that subpart W requires Calculation
Method 2 if a vent meter is installed, which mandates quarterly
sampling of the vented acid gas stream if a continuous gas analyzer is
not installed, and asserted that the vent stream typically has high
concentrations of H2S and the sampling is therefore
difficult and potentially dangerous to conduct. The commenters stated
that, for other source types, including tanks and glycol dehydrators,
the EPA has acknowledged that simulation software options are provided
instead of direct measurement in part due to safety concerns with
measurement (e.g., high temperature of dehydrator vent streams).
Commenters also indicated that some permits include modeling
requirements for AGRs, similar to dehydrators, but if a vent meter is
present on an AGR, subpart W mandates that reporters not use the
modeling results, which is also inconsistent with the requirements for
dehydrators. Commenters also provided information from published
literature regarding the accuracy of simulation software for methane
emissions. Commenters encouraged the EPA to allow the use of simulation
software for AGR vents even if a vent meter is present.
Response: The EPA has reviewed this comment and the directives of
CAA section 136 and determined it is appropriate to provide an
allowance to use Calculation Method 4 for AGRs that have a vent meter
and for which reporters are currently required to use Calculation
Method 2. The EPA agrees that in cases where a vent stream has high
concentrations of H2S, there could be safety concerns with
collecting the quarterly samples needed to determine the vent gas
composition under Calculation Method 2. The EPA recognizes that part of
the rationale for the structure and requirements for the original
calculation methods is that use of a continuous vent meter to directly
measure vent gas volumes was presumed to be more accurate than
simulations with inputs based on ``engineering estimate and process
knowledge based on best available data.'' However, based on our
assessment of currently available information, in cases where a vent
stream has high concentrations of H2S, the EPA agrees that
there could be safety concerns with collecting the quarterly samples
needed to determine the vent gas composition under Calculation Method
2. Additionally, in this final rule, our assessment is that simulation
software algorithms have improved since the original subpart W
rulemaking in 2010 and furthermore the EPA is revising Calculation
Method 4 as proposed to specify that certain simulation input
parameters must be based on certain measurements, which do not have the
same associated safety concerns (see section III.F.2. for further
information on that revision). These factors should decrease the
accuracy concerns between Calculation Methods 2 and 4. Finally, the EPA
is also revising the reporting requirements for Calculation Method 4 to
require additional verification information from the vent flow meter in
such circumstances. The evaluation of the information available to the
reporter though the vent flow meter could confirm or improve the
results of simulations under Calculation Method 4 even further. If the
simulations conducted under Calculation Method 4 do not agree with the
measured annual volume of vent gas, then that could be an indication
that the simulation results may not be an accurate representation of
the emissions. For example, if a reporter conducts a single simulation
for the reporting year and that single simulation results in an annual
vent gas volume that varies significantly from the measured annual vent
gas volume, the reporter could evaluate factors such as whether the
simulation parameters are appropriately representative of annual
operation or whether the operating parameters vary enough throughout
the year that multiple partial-year simulations might better
characterize the annual emissions.
Therefore, in summary, the EPA is finalizing an allowance for AGRs
that have a vent meter to use Calculation Method 4. As part of the
final provisions, the EPA is adding a new equation W-4D in 40 CFR
98.233(d) to determine the percent difference between the two vent gas
volumes and new requirements to report both vent gas volumes (i.e., the
annual volume of vent gas measured with the vent meter and the
simulated total annual volume of vent gas flowing out of the AGR) if
Calculation Method 4 is used in 40 CFR 98.236(d)(2)(iii)(O). The final
reporting requirements in 40 CFR 98.236(d)(2)(iii)(O) also specify that
if the difference between the vent gas volumes is greater than 20
percent as calculated using equation W-4D, the reporter must provide a
reason for that difference. As noted previously in this response, the
EPA agrees that software simulations have improved and should generally
be robust and accurate, and are thus consistent with CAA section
136(h), and also finds that the new information provided by reporters
who elect to use Calculation Method 4 for an AGR with a vent flow meter
installed will help to verify the data. The uncertainties in
measurements provided by continuous vent flow meters are expected to be
low (usually less than 5 percent). The uncertainties in
simulation results result from variability in the variety of input
parameters that must be provided and uncertainties inherent in the
equations built into the simulation flow rate; the overall uncertainty
is more difficult to quantify due to the combination of these factors.
The EPA considers the selected 20 percent interval to be
low enough to ensure reasonable agreement between the flow rates
obtained by the different methods but high enough to reasonably account
for the expected uncertainties. This interval is also consistent with
an example scale provided in the GHG Protocol's ``Short Guidance for
Calculating Measurement and Estimation Uncertainty for GHG
[[Page 42119]]
Emissions,'' in which uncertainties of 15 percent are
considered ``Good'' and uncertainties of 30 percent are
considered ``Fair.'' \48\
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\48\ GHG Protocol Initiative. Short Guidance for Calculating
Measurement and Estimation Uncertainty for GHG Emissions. Available
at https://ghgprotocol.org/sites/default/files/ghg-uncertainty.pdf
and in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-
2023-0234.
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Comment: Commenters requested that the EPA revise subpart W to
account for acid gas removal vents routed to vapor recovery systems, to
be consistent with other emission source types. Commenters also noted
that subpart W does allow reporters to subtract CO2
emissions recovered from AGRs and transferred outside the facility, but
it does not allow reporters to subtract the gas from AGR vent streams
that are sent to acid gas injection wells or sequestered underground.
The commenters stated that the EPA has previously stated that streams
that are subsequently injected underground or geologically sequestered
must be reported as emissions because the purpose of the GHG Reporting
Program is to ``collect[] data to inform future climate change
policies.'' \49\ However, commenters asserted that this position is not
consistent with the intent of the Inflation Reduction Act, so the EPA
should amend subpart W to allow reporters to subtract the gas from AGR
vent streams that are sent to acid gas injection wells or sequestered
underground because those streams are not emitted to the atmosphere.
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\49\ U.S. EPA, Mandatory Greenhouse Gas Reporting Rule Subpart
W--Petroleum and Natural Gas: EPA's Response to Public Comments at
1475 (Nov. 30, 2010). Available in the docket for this rulemaking,
Docket ID. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------
Response: As the commenters noted, the EPA's historic position on
the issue of injection and sequestration for subpart W is outlined in
Mandatory Greenhouse Gas Reporting Rule Subpart W--Petroleum and
Natural Gas: EPA's Response to Public Comments: ``In the final rule
establishing the GHG Reporting Program (74 FR 56260, October 30, 2009),
the EPA was clear that subpart methods and calculation procedures must
be followed whether or not there is subsequent injection underground or
geologic sequestration. The GHG Reporting Program is not an emissions
inventory; rather it is a reporting program that collects data to
inform future climate change policies. The same rationale applies to
subpart W in this final action. Data on CO2 from an acid gas
recovery unit is needed by the EPA to inform future climate change
policies, even if the CO2 stream is subsequently injected
underground. Therefore, such CO2 streams must report for the
AGR unit emission source.'' \50\
---------------------------------------------------------------------------
\50\ U.S. EPA, Mandatory Greenhouse Gas Reporting Rule Subpart
W--Petroleum and Natural Gas: EPA's Response to Public Comments,
November 2010, response to comment EPA-HQ-OAR-2009-0923-0582-31.
Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2023-0234.
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In August 2022, section 136 was added to the CAA. Section 136(c) of
the CAA states that ``the Administrator shall 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 of greenhouse gases emitted per year pursuant to
subpart W,'' and per CAA section 136(h), the emissions reported under
subpart W of the GHGRP must ``accurately reflect the total methane
emissions and waste emissions from the applicable facilities.'' While
subpart W of the GHGRP will continue to be used ``to inform future
climate change policies,'' due to the provisions in CAA section 136(h),
the EPA must also revise reporting for subpart W to accurately reflect
total emissions. Although the WEC will be imposed based on methane
emissions, it is also important for CO2 emissions to be
accurate for purposes of comparing facility CO2e emissions
to the threshold in CAA section 136(c).
The EPA has also reviewed the requirements for other emission
source types in subpart W and agrees with the commenters that for other
emission sources, subpart W provides provisions specific to vapor
recovery systems regardless of final disposition of the gas. Therefore,
after further consideration, the EPA is finalizing provisions for AGR
and nitrogen removal unit vents routed to vapor recovery that are
similar to the provisions for dehydrators and atmospheric storage tanks
routed to vapor recovery systems. The final provisions require the
reporters to determine emissions from the vent prior to the vapor
recovery system and then adjust those emissions to only report the
emissions that are not recovered and are released directly to the
atmosphere. These provisions will apply for all AGR vents routed to
vapor recovery systems, regardless of whether the recovered gas is
transferred outside the facility, injected underground, or sent
elsewhere in the facility (e.g., routed back to the process).
Specifically, the EPA is amending 40 CFR 98.233(d) to remove the
provisions related to CO2 emissions recovered and
transferred outside the facility in current 40 CFR 98.233(d)(9) and
replace them with provisions for calculating the emissions vented
directly to atmosphere from AGRs or nitrogen removal units routed to
vapor recovery systems or flares in 40 CFR 98.233(d)(11). Similarly,
the EPA is removing the requirement in current 40 CFR 98.236(d)(1)(iv)
to report whether any CO2 emissions from the acid gas
removal unit were recovered and transferred outside the facility. The
CO2 emissions recovered and transferred outside the facility
will continue to be reported under 40 CFR part 98, subpart PP
(Suppliers of Carbon Dioxide) rather than subpart W, as currently
required.
2. Calculation Method 4
The EPA is finalizing several revisions related to Calculation
Method 4 for acid gas removal units as described in this section. The
EPA received only minor comments regarding Calculation Method 4 for
acid gas removal units. See the document Summary of Public Comments and
Responses for 2024 Final Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems under the Greenhouse Gas
Reporting Rule in Docket ID. No. EPA-HQ-OAR-2023-0234 for these
comments and the EPA's responses.
Reporters with AGRs that elect to calculate emissions using
Calculation Method 4 are currently required to calculate emissions
using any standard simulation software package that uses the Peng-
Robinson equation of state and speciates CO2 emissions.
According to existing 40 CFR 98.233(c)(4), the information that must be
used to characterize emissions include natural gas feed temperature,
pressure, flow rate, and acid gas content; outlet natural gas acid gas
content and temperature; unit operating hours; and solvent temperature,
pressure, circulation rate, and weight. These parameters currently must
be determined for typical operating conditions over the calendar year
by engineering estimate and process knowledge based on best available
data. Consistent with section II.B. of this preamble, we are finalizing
as proposed that the input parameters related to the natural gas feed
that are used for the simulation software must be obtained by
measurement. Those parameters include natural gas feed temperature,
pressure, flow rate, acid gas content, CH4 content, and, for
nitrogen removal units, nitrogen content. We are finalizing as proposed
that reporters collect measurements reflective of representative
operating conditions over the time period covered by the simulation. We
did not propose and are not finalizing any changes to the
[[Page 42120]]
requirement that the other parameters must be determined for operating
conditions over the time period covered by the simulation based on
engineering estimate and process knowledge.
We are also finalizing as proposed that the parameters that must be
used to characterize emissions should reflect operating conditions over
the time period covered by the simulation rather than just over the
calendar year. Under this change, reporters may continue to run the
simulation once per year with parameters that are determined to be
representative of operating conditions over the entire year.
Alternatively, reporters will be allowed to conduct periodic simulation
runs to cover portions of the calendar year, as long as the entire
calendar year is covered. The reporter will then sum the results at the
end of the year to determine annual emissions. In that case, the
parameters for each simulation run will be determined for the operating
conditions over each corresponding portion of the calendar year. We
note that parameter measurements used in a previous periodic simulation
within the same reporting year may be used for subsequent simulations
if they are representative of that parameter under the operating
conditions of the subsequent simulation. Finally, we are finalizing as
proposed the clarification that the information reported under 40 CFR
98.236(d)(2)(ii) should be provided on an annual basis, either as an
average across the year, or a total for the year (in the case of
operating hours for the unit).
We are also finalizing as proposed the replacement of the existing
requirement to report solvent weight in existing 40 CFR
98.236(d)(2)(iii)(L) with a requirement in final 40 CFR
98.236(d)(2)(iii)(N) to report the solvent type and, for amine-based
solvents, the general composition. Reporters must choose the solvent
type option from a pre-defined list that most closely matches the
solvent type and, for amine-based solvents, the general composition,
used in their AGR. The standardized response options will include the
following: ``SelexolTM,'' ``Rectisol[supreg],''
``PurisolTM,'' ``Fluor Solvent'' ``BenfieldTM,''
``20 wt% MEA,'' ``30 wt% MEA,'' ``40 wt% MDEA,'' ``50 wt% MDEA,'' and
``Other (specify).'' In the event that reporters use more than one type
of solvent in their AGR during the year, as proposed, the final
reporting requirement specifies for reporters to select the option that
corresponds to the solvent used for the majority of the year. The EPA
expects that this final amendment to collect standardized information
about the solvent will result in more useful data that will improve
verification of reported data and better characterize AGR vent
emissions, consistent with section II.C. of this preamble. It will also
improve the quality of the data reported compared to the apparently
inconsistent application of the current requirements by reporters.
3. Reporting of Flow Rates
The EPA is finalizing several revisions related to Calculation
Method 4 for acid gas removal units as described in this section. The
EPA received only supportive comments regarding the revisions to flow
rate reporting for acid gas removal units. See the document Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems
under the Greenhouse Gas Reporting Rule in Docket ID. No. EPA-HQ-OAR-
2023-0234 for these comments and the EPA's responses.
We are finalizing as proposed several amendments to improve the
quality and verification of AGR flow rate information, consistent with
section II.C. of this preamble. Reporters are currently required to
report the total feed rate entering the AGR in units of million cubic
feet per year (existing 40 CFR 98.236(d)(1)(iii), proposed 40 CFR
98.236(d)(1)(iv)). The existing rule does not specify million standard
cubic feet per year or million actual cubic feet per year, so reporters
may provide this feed rate in either of those units of measure.
Therefore, we are first finalizing the proposal to require that the
total annual feed rate that is required to be reported for all AGRs
regardless of the how the emissions are calculated (existing 40 CFR
98.236(d)(1)(iii), amended 40 CFR 98.236(d)(1)(iv)) must be reported at
standard conditions (i.e., in units of MMscf per year). Second, we are
finalizing as proposed the requirement to report the temperature and
pressure that correspond to the flow rates reported for Calculation
Methods 1, 2, or 3 (reporters using Calculation Method 4 are already
required to report the temperature and pressure of the acid gas feed,
under existing 40 CFR 98.236(d)(2)(iii)(B) and (C)). The additions, at
40 CFR 98.236(d)(2)(i)(D) and (E) and (d)(2)(ii)(I), (J), (L), and (M),
specify that reported temperature and pressure must be the actual
temperature and pressure if the flow rate is reported in actual
conditions, or standard temperature and pressure if the flow rate is
reported in standard conditions. The EPA received only supportive
comments on these additions.
G. Dehydrator Vents
1. Selection of Appropriate Calculation Methodologies for Glycol
Dehydrators
a. Summary of Final Amendments
The EPA is finalizing revisions to the calculation methodologies
for glycol dehydrators largely as proposed, except for one update from
proposal after consideration of comments.
We are finalizing as proposed the revised calculation requirements
of 40 CFR 98.233(e) to allow reporters the ability to use Calculation
Method 1 or Calculation Method 2 when determining emissions from
dehydrators that have an annual average of daily natural gas throughput
that is less than 0.4 MMscf per day. After consideration of comments,
we are finalizing the conditions under which a facility is required to
use 40 CFR 98.233(e) with a modification. The proposed requirement
stated that if reporters conduct modeling for environmental compliance
or reporting purposes, including but not limited to compliance with
Federal or state regulations, air permit requirements, or annual
inventory reporting, or internal review, they would use those results
for reporting under subpart W. Based on consideration of public comment
concerning the nature of modeling for internal review purposes by
facilities, and differences in program requirements, we are not
finalizing the proposed requirement to use the results from such
modeling for reporting under subpart W. We are instead requiring in the
final provisions that if a facility is required to use a software
program for compliance with federal or state regulations, air permit
requirements or annual emissions inventory reporting that meets the
requirements of 40 CFR 98.233(e)(1), they must use 40 CFR 98.233(e)(1)
for reporting under subpart W. We anticipate that modeling consistent
with the methodology outlined in 40 CFR 98.233(e)(1) could be conducted
by reporters for environmental compliance or reporting purposes or
reporters may run a simulation solely for the purpose of reporting
under subpart W. This will ensure that the facility is able to use
modeling results that are representative of actual operating conditions
and meet the requirements of 40 CFR 98.233(e)(1) without requiring that
models completed for other purposes meet the requirements under this
subpart. As noted in the preamble to the proposed rule, we expect that
these revisions will improve the quality of the data collected. For
this reason and consistent with section II.B. of this preamble, we
[[Page 42121]]
are requiring that facilities that are already completing modeling for
other required reporting must use modeling to report to subpart W. The
EPA is also finalizing as proposed the revisions to 40 CFR 98.236(e) to
specify the applicable reporting requirements based on the selected
calculation method rather than the throughput of the dehydrator. This
amendment will improve the quality of the data collected, consistent
with section II.B. of this preamble.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed selection of calculation methodologies for glycol
dehydrators.
Comment: One commenter reported that simulations are run for
``internal review'' for a variety of purposes, including ``what-if''
scenarios (i.e., exploring possible engineering adjustments), and may
not meet the EPA's goal of estimating emissions based on operating
conditions. The commenter recommended that only simulations run for
compliance purposes should be used.
Response: We agree with the commenter that simulations run for
other purposes may not result in emissions estimations based on
representative operating conditions, as facilities may complete models
for a variety of purposes, including models to consider future
adjustments to the operation of the unit that are based on possible
future, not actual, operating conditions. We are not finalizing the
proposed requirement that all results from simulations run for the
purposes of ``internal review'' or modeling completed for environmental
compliance or reporting purposes are required to be used for reporting.
We are instead requiring in the final provisions that if a facility
performs emissions modeling of a glycol dehydrator for compliance with
federal or state regulations, air permit requirements or annual
emissions inventory reporting using a software program that meets the
requirements of 40 CFR 98.233(e)(1), they must also use 40 CFR
98.233(e)(1) for reporting under subpart W. We expect that these
amendments as finalized will increase the quality of data collected
without requiring the inclusion of results from inappropriate modeling
runs. We have revised the language in 40 CFR 98.233(e) introductory
text to clarify these requirements.
Comment: One commenter requested clarification on whether reporters
are compelled to use the simulation(s) from other compliance programs
that may have different requirements, or if reporters can (or must) run
a new simulation with an analysis pulled during the reporting year.
Response: We are not finalizing the proposed requirement to use all
the results from modeling, that may have been performed for programs
with different requirements, for reporting under subpart W. We are
instead requiring in the final provisions that if a facility performs
emissions modeling of a glycol dehydrator for compliance with federal
or state regulations, air permit requirements or annual emissions
inventory reporting using a software program that meets the
requirements of 40 CFR 98.233(e)(1), they must also use 40 CFR
98.233(e)(1) for reporting under subpart W. We anticipate that modeling
consistent with the methodology outlined in 40 CFR 98.233(e)(1) could
be conducted by reporters for environmental compliance or reporting
purposes, or reporters may run a simulation for the purpose of
reporting under subpart W. We have revised the language in 40 CFR
98.233(e) introductory text to clarify these requirements.
2. Controlled Dehydrators
a. Summary of Final Amendments
The EPA is finalizing revisions to controlled dehydrator
requirements largely as proposed, except for two clarifications from
proposal in the final provisions after consideration of comments.
We are finalizing as proposed revisions to the methodologies for
calculating emissions from dehydrator vents controlled by a vapor
recovery system, flare, or regenerator firebox/fire tubes currently
provided in 40 CFR 98.233(e)(5) and (6), respectively. The new language
in 40 CFR 98.233(e)(4) provides a methodology for calculating emissions
vented directly to the atmosphere during periods of time when emissions
are not routed to the vapor recovery system, flare, or regenerator
firebox/fire tubes. For flared dehydrator emissions, the 40 CFR
98.233(e) provisions direct reporters to the methodologies in 40 CFR
98.233(n). As a regenerator firebox/fire tubes does not meet the
definition of a flare per 40 CFR 98.238, we are finalizing
methodologies as proposed for calculating combusted emissions from a
regenerator firebox/fire tubes in 40 CFR 98.233(e)(5) using the
combustion source equations W-39A, W-39B, and W-40 of 40 CFR
98.233(z)(3). We are also finalizing as proposed new reporting
requirements for dehydrator units with emissions routed to a firebox/
fire tubes in 40 CFR 98.236(e)(1)(xvi) and (xvii), (e)(2)(v), and
(e)(3)(vii) that are consistent with the reporting requirements for
combustion sources in 40 CFR 98.236(z)(2). By finalizing these
amendments, the EPA enhances the overall quality of the data collected
under the GHGRP, consistent with sections II.B. and II.D. of this
preamble.
The EPA is also finalizing revisions as proposed to two terms
consistent with the amendments for reporting for glycol dehydrators
with an annual average daily natural gas throughput greater than or
equal to 0.4 MMscf per day. The EPA is finalizing the definition of
``dehydrator vent emissions'' in 40 CFR 98.6 to confirm that dehydrator
emissions reporting should include emissions from both the dehydrator
still vent, and if applicable, the dehydrator flash vent. We are also
finalizing as proposed the removal of the term ``reboiler'' from the
definition of ``dehydrator vent emissions'', as the term
``regenerator'' refers to the same piece of equipment. Finally, we are
finalizing expansion of the dehydrator control types referenced in the
definition of ``dehydrator vent emissions'' to include regenerator
fireboxes/fire tubes and vapor recovery systems. Additionally, the EPA
is finalizing the amended definition of ``vapor recovery system'' in 40
CFR 98.6 to clarify that routing emissions from a dehydrator
regenerator still vent or flash tank separator vent to the regenerator
firebox/fire tubes does not qualify as vapor recovery for purposes of
40 CFR 98.233. Based on consideration of commenter feedback, the EPA is
also finalizing two clarifications from proposal in the final
provisions. We are amending from proposal the final text in 40 CFR
98.233(e)(4)(i) to clarify that reporters must calculate the emissions
that would potentially be emitted if the vapor recovery system, flare,
or regenerator firebox/fire tubes was not present as a first step. We
are also finalizing an amendment to make the language in 40 CFR
98.233(e) introductory text consistent with the final requirements in
40 CFR 98.233(e)(4). In finalizing these edits, the EPA will improve
the quality of the emissions data reported and confirm the original
intent of these terms.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to the reporting requirements for controlled
dehydrators.
Comment: One commenter requested the removal of the requirement in
40
[[Page 42122]]
CFR 98.233(e)(4)(i) to calculate the ``maximum potential annual vented
emissions.'' The commenter noted that the requirement conflicts with
the requirements that simulations should ``represent the operating
conditions.'' The commenter noted that determining a maximum potential
case requires assuming worst-case conditions, which does not reflect
actual operations and does not further the EPA's goal of accurately
determining emissions.
Response: The EPA agrees with the commenter that emissions need to
be determined based on operating conditions. The intent was not for
reporters to calculate the emissions that the dehydrator has the
potential to emit based on worst-case conditions; the intention was for
reporters to calculate the emissions that would potentially be emitted
if the vapor recovery system, flare, or regenerator firebox/fire tubes
was not present, as the first step in the process of calculating
emissions that are vented directly to the atmosphere during periods of
time when emissions are not routed to that device. The EPA has amended
text from proposal in final 40 CFR 98.233(e)(4)(i) to clarify this
intent.
Comment: One commenter noted that the 40 CFR 98.233(e) introductory
text implies that uncontrolled emissions are calculated and then
adjusted downward. The commenter stated that proposed 40 CFR
98.233(e)(4) directs reporters to calculate only those proposed
emissions directly vented to the atmosphere. The commenter recommended
that the EPA revise the 40 CFR 98.233(e) introductory text to remove
the reference to adjusting emissions downward.
Response: The EPA agrees with the commenter that the reporter must
calculate only emissions directly vented to the atmosphere. The
language in 40 CFR 98.233(e) introductory text is consistent with the
current requirements in 40 CFR 98.233(e)(5) for dehydrators with vapor
recovery, but it was inadvertently not adjusted in the proposal to
match the proposed requirements in 40 CFR 98.233(e)(4). The EPA is
finalizing an amendment to the language in 40 CFR 98.233(e)
introductory text consistent with the final requirements in 40 CFR
98.233(e)(4).
3. Calculation Method 1 for Glycol Dehydrators
a. Summary of Final Amendments
The EPA is finalizing revisions to the Calculation Method 1 for
glycol dehydrators largely as proposed, except for three clarifications
and updates from proposal after consideration of comment.
We are finalizing that reporters would collect measurements of the
simulation input parameters listed under 40 CFR 98.233(e)(1) consistent
with section II.B. of this preamble, with one change from the proposal
The final parameters required to be measured include feed natural gas
water content, wet natural gas temperature and pressure at the absorber
inlet, and wet natural gas composition. The proposal also included a
requirement to measure feed natural gas flow rate. However, after
consideration of comments received, in an effort to reduce burden on
reporters, we are not finalizing the requirement to directly measure
feed natural gas flow rate; instead, we are requiring that feed natural
gas flow rate must be determined based on measured data. For example,
facilities may determine the feed natural gas flow rate based on
measured outlet natural gas flow; we expect that this method
determining feed natural gas flow rate to be accurate and less
burdensome for facilities by using existing instrumentation.
Requirements for measurement frequency for 40 CFR 98.233(e)(1)(i),
(ii), (x) and (xi) are being finalized as proposed; for these input
parameters, where parameters are determined to be representative of
operating conditions over the entire year, the measurements must be
taken at least once per year or where the measurements are only
reflective of representative operating conditions over shorter time
periods the measurements must be taken multiple times per year.
However, given the significant burden noted by commenters to sample
composition each reporting year, the EPA is finalizing a reduced
frequency schedule for composition sampling and analysis (40 CFR
98.233(e)(1)(xi)). Reporters must sample and analyze composition at
least once every five years. We are clarifying in the final rule that
if physical or operational changes are made such that the measured
sample is no longer representative of operating conditions, reporters
must collect a new sample and re-analyze composition. We are requiring
that samples must be collected within six months of the startup of
production or by January 1, 2030 (i.e., within five years of the
effective date of the rule), whichever date is later and at least once
every five years thereafter. Until such time that a sample can be
collected, reporters may continue to determine these parameters by
using one of the existing methods. We believe that samples taken at
this frequency will be sufficiently representative as we do not expect
significant changes except in cases where physical or operational
changes, (e.g., increased TEG circulation rate) are made.
We are also finalizing as proposed that the parameters that must be
used to characterize emissions should reflect operating conditions over
the time period covered by the simulation rather than just over the
calendar year. Under this change, reporters could continue to run the
simulation once per year with parameters that are determined to be
representative of operating conditions over the entire year.
Alternatively, reporters would be allowed to conduct periodic
simulation runs to cover portions of the calendar year, as long as the
entire calendar year is covered. The reporter will then sum the results
at the end of the year to determine annual emissions. In that case, the
parameters for each simulation run will be determined for the operating
conditions over each corresponding portion of the calendar year. In the
case of more than one simulation covering the reporting period, the
reported parameter is the average of the parameters for each
simulation. Finally, we are finalizing a clarification that the
information reported under 40 CFR 98.236(e)(1) should be provided on an
annual basis, either as a total for the year (in the case of operating
hours for the unit and emissions) or as an average across the year (for
all other input parameters).
We are finalizing as proposed the addition of ProMax as an example
software program for calculating dehydrator emissions per 40 CFR
98.233(e)(1) for clarity for reporters. Consistent with the EPA's
approval of ProMax for NESHAP HH compliance, the EPA is finalizing as
proposed the requirement that if reporters elect to use ProMax, they
will be required to use version 5.0 or above.
In order to assess potential emissions changes between reporting
years, the EPA is also finalizing the addition of a new provision under
40 CFR 98.236(e)(1)(xviii) to request reporting of the modeling
software used to calculate emissions for each dehydrator unit using
Calculation Method 1. These amendments will improve the quality of the
data collected, consistent with section II.B. of this preamble.
The EPA is finalizing as proposed under 40 CFR 98.236(e) the
requirement to separate reporting of emissions for a modeled glycol
dehydrator's still vent and flash tank vent. These amendments will
improve the quality of the data collected, consistent with section
II.C. of this preamble.
[[Page 42123]]
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the Calculation Method 1 for glycol dehydrators.
Comment: Two commenters noted that the proposed requirement to
measure feed natural gas flow rate is impractical, would require
significant investment, and does not increase data quality. The
commenters noted that facilities are not equipped with meters upstream
of the dehydration unit, but gas flow is measured at the unit outlet.
The commenters recommend that feed natural gas flow rate be determined
based on measured data.
Response: After further consideration, the EPA is not finalizing
the proposed requirement to measure the feed natural gas flow rate as
our assessment is that there are other measurements that could be used
to determine the feed natural gas flow rate that would have similar
data quality. The EPA is instead requiring that reporters determine the
feed natural gas flow rate based on measured data, which could include
facility discharge meters or wellhead meters. Our assessment is that
this will allow the use of existing instrumentation and also decrease
burden, while maintaining data quality.
Comment: One commenter requested clarification on the proposed
measurement frequency of model input parameters. The commenter also
requested that even for multiple simulations a re-collection of
parameters only be required upon suspected changes. The commenter noted
that an operator can conduct one simulation on an annual basis using
one set of parameters collected by the operator. Additionally, an
operator may conduct periodic simulations. The commenter stated that
conducting periodic simulations assists an operator in ensuring that it
fully complies with the regulations in a timely manner that allows for
any potential errors to be addressed in subsequent simulations. The
commenter stated that the EPA disincentives periodic simulations by
requiring an operator to perform field measurements to establish the
parameters for every simulation.
Response: We are clarifying in the final rule that the frequency of
measurement for the input parameters at for 40 CFR 98.233(e)(1)(i),
(ii) and (x) must be measured at least once per year, but the
measurement may be used in simulations covering different portions of
the calendar year if the measurement is reflective of operating
conditions over the time period of the simulation. After consideration
of comment, the EPA is also finalizing a reduced frequency schedule
from that proposed for the measurement of composition. Reporters must
sample and analyze composition at least once every 5 years.
Additionally, input parameters must be remeasured if no longer
representative of operating conditions; for example, if physical or
operational changes are made that may result in an increase in
CH4 or CO2 emissions, reporters must collect and
analyze a new sample. After consideration of the burden noted by
commenters to collect samples within one year of finalization of the
rule, the EPA is allowing 5 years from the date of publication of this
final rule, or within 6 months of the startup of production, whichever
date is later, for reporters to collect a composition sample. Until a
sample is collected, facilities may use the existing methods. We
believe that measurements taken at this frequency will be sufficiently
representative of operating conditions as we do not expect significant
changes except in cases where physical or operational changes (e.g.,
increased TEG circulation rate) are made.
Comment: One commenter requested clarification on the reporting
requirements for the inputs to the simulation. The commenter noted that
40 CFR 98.233(e)(1) requires reporters to ``collect measurements
reflective of representative operating conditions for the time period
covered by the simulation'' but 40 CFR 98.236(e)(1) requires reporting
as an ``annual average.'' The commenter noted that ``annual average''
implies a different standard than ``measurements reflective of
representative operating conditions.''
Response: The EPA agrees with the commenter that the reporter must
collect measurements reflective of representative operating conditions.
The EPA updated the final 40 CFR 98.236(e)(1) to clarify that in the
case of more than one simulation covering the reporting period, the
data reported is to be either the total (in the case of operating hours
or emissions) and the average of the inputs to each simulation for all
other input parameters.
4. Calculation Method 2 for Glycol Dehydrators
The EPA is finalizing revisions to the Calculation Method 2
reporting requirements for glycol dehydrators as proposed. The EPA
received only supportive comments regarding the revisions to
Calculation Method 2 for glycol dehydrators. See the document Summary
of Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems
under the Greenhouse Gas Reporting Rule in Docket ID. No. EPA-HQ-OAR-
2023-0234 for these comments and the EPA's responses.
Specifically, the EPA is finalizing as proposed the clarification
in 40 CFR 98.233(e)(2) that the dehydrators for which emissions are
calculated should be those with annual average daily natural gas
throughput greater than 0 MMscf per day and less than 0.4 MMscf per day
(i.e., the count should not include dehydrators that did not operate
during the year). Similarly, the EPA is finalizing as proposed
clarification in 40 CFR 98.236(e)(2) introductory text that the count
of dehydrators in existing 40 CFR 98.236(e)(2)(i) (amended 40 CFR
98.236(e)(2)(ii)) should also be those with annual average daily
natural gas throughput greater than 0 MMscf per day and less than 0.4
MMscf per day. These amendments will improve implementation and
verification of reported data, consistent with section III.C. of this
preamble.
The EPA is finalizing as proposed revisions to the data collected
under current 40 CFR 98.236(e)(2)(iii) (amended 40 CFR
98.236(e)(2)(iv)) to emphasize the original intent of the rule. We are
finalizing as proposed the requirement to specifically state that the
reporting of ``other'' control devices should only include control
devices that reduce CO2 and/or CH4 emissions.
This final revision will allow the EPA to verify the expected
reductions in vented CO2 and/or CH4 emissions due
to the use of the control device. This final amendment will improve
implementation and verification of reported data, consistent with
section III.C. of this preamble.
5. Desiccant Dehydrators
a. Summary of Final Amendments
The EPA is finalizing revisions to the reporting requirements for
desiccant dehydrators in 40 CFR 98.236(e) largely as proposed, except
for three clarifying corrections and updates from proposal after
consideration of comment. The EPA also is finalizing related changes to
definitions of ``dehydrator'' and ``desiccant'' in 40 CFR 98.6 as
proposed.
Specifically, we are finalizing removal of the cross-references
from 40 CFR 98.236(e)(3) to 40 CFR 98.236(e)(2)(i) through (iv) and
instead are including all of the applicable reporting requirements from
current 40 CFR 98.236(e)(2)(i) through (iv) for desiccant dehydrators
under 40 CFR 98.236(e)(3). Replicating the requirements under 40 CFR
98.236(e)(3) will make the rule easier to follow and allow the EPA to
[[Page 42124]]
further clarify the required reporting data elements for desiccant
dehydrators. One clarifying correction that is being finalized
consistent with public comment is removal of the proposed reference to
flash tanks in 40 CFR 98.236(e)(3)(vii)(B), which was referenced in
error. A second clarifying correction that is being finalized
consistent with public comment is all proposed references to
regenerator firebox/fire tubes in 40 CFR 98.236(e)(3) have been
replaced with references to non-flare combustion units as commenters
noted that desiccant dehydrators are not known to have configurations
with regenerator firebox/fire tubes. The final rule also includes
conforming changes in 40 CFR 98.233(e)(5) to specify procedures for
calculating emissions from non-flare combustion units used with
desiccant dehydrators that are the same as the procedures for
calculating emissions from regenerator fireboxes/fire tubes that are
used with small glycol dehydrators.
The EPA also is finalizing as proposed the addition of four new
desiccant dehydrator reporting data elements in 40 CFR 98.236(e)(3), we
are not finalizing one proposed reporting element, and we are
finalizing as proposed the removal of reporting the total count of
desiccant dehydrators at the facility as required in 40 CFR
98.236(e)(3)(i) of the existing rule. The four new data elements are
the total volume of all opened desiccant dehydrator vessels in 40 CFR
98.236(e)(3)(iii), the total number of desiccant dehydrator openings in
the calendar year in 40 CFR 98.236(e)(3)(iv), the count of opened
desiccant dehydrators that used deliquescing desiccant (e.g., calcium
chloride or lithium chloride) in 40 CFR 98.236(e)(3)(ii)(A) (proposed
40 CFR 98.236(e)(3)(ii)(B)), and the count of opened desiccant
dehydrators that used regenerative desiccant (e.g., molecular sieves,
activated alumina, or silica gel) in 40 CFR 98.236(e)(3)(ii)(B)
(proposed 40 CFR 98.236(e)(3)(ii)(C)). The proposal also included a
requirement to report the total count of opened desiccant dehydrators
in 40 CFR 98.236(e)(3)(ii)(A). However, to eliminate duplicative
reporting requirements, we are not finalizing the requirement to report
the total count of opened desiccant dehydrators, as we will have the
information through the sum of the opened dehydrators using
deliquescing desiccant and the opened dehydrators using regenerative
desiccant. After removing the data element for the total count of
opened desiccant dehydrators, the two new reporting data elements for
the count of opened desiccant dehydrators that used deliquescing
desiccant and the count of opened desiccant dehydrators that used
regenerative desiccant have been moved to 40 CFR 98.236(e)(3)(ii)(A)
and (B) in the final amendments. These amendments will improve
verification of reported data and ensure accurate reporting of
emissions, consistent with section II.C. of this preamble.
The EPA is also finalizing revisions to the definitions of
``dehydrator'' and ``desiccant'' in 40 CFR 98.6 as proposed. In the
definition of ``dehydrator,'' we are finalizing the change to replace
the word ``absorb'' with ``remove,'' and we are finalizing the change
to clarify that desiccant is not a type of liquid absorbent. In the
definition of ``desiccant'' we are finalizing the change to include
``molecular sieves'' in the list of example desiccants and we are
finalizing the change to clarify that desiccants include, ``but are not
limited to,'' molecular sieves, activated alumina, pelletized calcium
chloride, lithium chloride and granular silica gel material. We expect
these amendments will improve the overall quality and completeness of
the emissions data collected by the GHGRP, consistent with section
II.A. of this preamble.
b. Summary of Comments and Responses on Desiccant Dehydrators
This section summarizes the major comments and responses related to
the proposed amendments to reporting requirements for desiccant
dehydrators.
Comment: One commenter noted that references to ``regenerator
firebox/fire tubes'' throughout the desiccant dehydrator reporting
requirements in 40 CFR 98.236(e)(3) appear to be a mistake because the
commenter is not aware of desiccant dehydrators that route emissions to
regenerator firebox/fire tubes. The commenter suggested that references
to non-flare combustion calculations may be more appropriate. The
commenter also noted that 40 CFR 98.236(e)(3)(vii)(B) should be changed
to remove the reference to flash tanks because flash tanks are used
only with glycol dehydrators, not desiccant dehydrators.
Response: We agree with the commenter that regenerator firebox/fire
tubes are not used with desiccant dehydrators. Regenerator firebox/fire
tubes are used with glycol dehydrators to provide the energy needed to
drive water out of rich glycol to produce lean glycol for recirculation
to the absorber, but they are not needed in the operation of desiccant
dehydrators. The current rule requires reporting of combusted emissions
from dehydrator emission streams that are routed to a flare or
regenerator firebox/fire tubes. Since regenerator firebox/firetubes are
not needed for operation of desiccant dehydrators, it is possible that
all combustion emissions reported for desiccant dehydrators under
subpart W are from flares. However, to allow for the possibility that
some emissions from desiccant dehydrators may be routed to a
regenerator firebox/fire tubes for a glycol dehydrator at the same
site, and to allow reporting of combusted emissions from thermal
oxidizers or other types of combustion devices, we are replacing the
proposed references to regenerator firebox/firetubes in 40 CFR
98.236(e)(3) in the final rule provision with references to ``non-flare
combustion unit.'' This change will allow complete and accurate
reporting of all combusted emissions from desiccant dehydrators.
We also agree with the commenter that the proposed reference to
flash tanks in the desiccant dehydrator reporting requirements is
incorrect. Flash tanks reduce the pressure of the rich glycol stream
out of the absorber for a glycol dehydrator, thereby separating a
significant portion of the high vapor pressure compounds, such as
methane, from the liquid glycol upstream of the regenerator; flash
tanks are not applicable for desiccant dehydrators. Thus, after
considering both this comment and the one above, the reporting
requirement in 40 CFR 98.236(e)(3)(vii)(B) of the final rule was
changed from proposal to read as follows: ``Total volume of gas routed
to non-flare combustion units, in standard cubic feet.''
Comment: One commenter stated that the EPA should eliminate
reporting elements that are duplicative of other data it is already
collecting and that simply add steps to reporters without any
additional information to be gained. As an example, the commenter cited
the proposed requirement in 40 CFR 98.236(e)(3)(ii)(A) to report the
total number of opened desiccant dehydrators, which should be equal to
the sum of the total number of opened desiccant dehydrators that used
deliquescing desiccant in proposed 40 CFR 98.236(e)(3)(ii)(B) plus the
total number of opened desiccant dehydrators that used regenerative
desiccant in proposed 40 CFR 98.236(e)(3)(ii)(C).
Response: After consideration of public comment to eliminate
duplicative reporting requirements, we are not finalizing the proposed
requirement to report the total count of opened desiccant dehydrators
because
[[Page 42125]]
this quantity can be calculated as the sum of the reported count of
opened dehydrators using deliquescing desiccant plus the reported count
of opened dehydrators using regenerative desiccant and is, therefore,
redundant.
H. Liquids Unloading
1. Summary of Final Amendments
The EPA is finalizing several changes to calculation methods and
the reporting requirements for liquids unloading. These changes are
expected to improve data quality while recognizing the operational
challenges that facility operators can face in the field when managing
unloading events, including monitoring and measuring emissions from
those events.
Consistent with section II.C. of this preamble, we are clarifying
the proposal that required reporters to calculate and report emissions
when natural gas emissions from well venting for liquids unloading are
routed to the atmosphere or to a control device, recognizing that some
reporters may choose to flare or use natural gas at the well-pad. In
the final rule, we are narrowing this to require reporting of liquids
unloading emissions when natural gas is vented to the atmosphere or to
a flare because use in other combustion equipment on-site will be
captured by the combustion source. We have expanded, as proposed, the
type of unloading from just plunger lift or non-plunger lift unloadings
to also include a designation of whether each unloading event is a
manual or automated unloading. Therefore, there are now four unloading
types: automated plunger lift, manual plunger lift, automated non-
plunger lift and manual non-plunger lift. The EPA proposed and is
finalizing this requirement to more accurately characterize emissions
from liquids unloading. In addition to changes to 40 CFR 98.233(f) and
98.236(f), we are finalizing as proposed definitions in 40 CFR 98.238
for ``Manual liquids unloading'' and ``Automated liquids unloading.''
The EPA is finalizing further clarifying changes to liquids
unloading calculation methods in 40 CFR 98.233(f)(2) after
consideration of public comment to more accurately calculate emissions
from liquids unloading. For Calculation Method 2, the definition of
CDp, casing diameter, is amended in the final rule to
clarify that CDp can also include the tubing diameter when
stoppage packers have been placed downhole in the annulus, forcing
unloadings to travel to the surface through the tubing string rather
than the annulus. The definition of WDp, well depth, for Calculation
Method 2 is also amended in the final rule to clarify that well depth
may be measured from either the bottom of the well or the top of the
fluid column. This has a direct bearing on the first part of equation
W-8, which estimates the quantity of natural gas in the production
column that will be initially emitted when the well is unloaded.
Reporters are not required to determine the top of the fluid column,
but allowing reporters to have the option to define the top of the
liquid column and establish that depth as the bottom of the well
recognizes that the available capacity in the wellbore to hold
accumulated gas volumes is displaced by liquids and results in more
accurate emissions measurements. Although some natural gas may be
entrained in the liquid column, the volume of gas is likely to be very
small compared to volume of gas in the borehole above the liquid
column. Additionally, liquids from the unloading are expected to be
directed to an atmospheric tank or separator where gas emissions from
gas entrained in the liquids will be reported in the tanks source under
40 CFR 98.233(j). If the reporter is unable to determine the top of the
fluid column or chooses not to do so, the reporter must assume that
well depth is the bottom of the well. We are finalizing a similar
clarifying change to the definition of well depth in the calculation
requirements for Calculation Method 3 for the same reasons.
For well depth in Calculation Method 2, we are also finalizing a
clarification in defining the bottom of the well for horizontal wells,
to be the point at which the borehole pivots downhole from vertical to
horizontal. Horizontal wells produce gas along one or more horizontal
laterals directing flow from the producing formation through the cased
hole to the production string at the base of the vertical portion of
the well. Unloadings are required when wells, primarily gas wells,
accumulate liquids in the wellbore, and velocity up the production
tubing is not sufficient to lift liquids to the surface. The well is
effectively shut-in and ceases production until the liquids are lifted
and gas flow is restored. Horizontal laterals are perforated at varying
intervals and liquids accumulation in a horizontal well will generally
occur first in the horizontal portion of the well because that is where
gas with entrained liquids will enter the production string. Eventually
liquids will accumulate throughout the horizontal lateral to the base
of the vertical section of the well or even closure to the surface.
This change recognizes that it is very likely that a horizontal well
requiring an unloading will have liquids accumulation from the top of
the fluid column at the bottom of the vertical portion of the well
downhole through the extent of the horizontal portion of the well. We
are, therefore, allowing reporters using Calculation Method 2 for non-
plunger unloadings to consider the bottom of the well for a horizontal
well to be the point at which the vertical borehole pivots to a
horizontal direction. This change only affects Calculation Method 2.
The bottom of the well in Calculation Method 3 is defined as tubing
depth to the plunger bumper, which is generally at the bottom of the
vertical portion of a well.
We are also finalizing amendments in 40 CFR 98.233(f) and 98.236(f)
that recognize that some reporters may direct natural gas emissions
from liquids unloading to flare stacks. Prior to this rulemaking,
natural gas emissions from unloadings were assumed to be from venting
the unloadings. Based on review of public comment submitted to the EPA
in response to the proposed amendments from June 2022, we understand
that some reporters may be considering directing emissions to a flare
stack or other control device. Therefore, in the proposal for this
rulemaking, we included regulatory text to require reporting of
emissions and other data if natural gas flow from a liquids unloading
is directed to a flare or control device. We are finalizing provisions
in 40 CFR 98.233(f) directing reporters to use the calculation methods
in 40 CFR 98.233(n) for flare stacks to calculate associated unloading
emissions from flaring and report these emissions under 40 CFR
98.236(n). If natural gas from unloadings is directed to other control
devices, the emissions should be calculated as part of that source
(e.g., through the combustion source type) under the 40 CFR 98.233
provisions for those source types.
With respect to Calculation Method 1, the EPA proposed to require
use of this method to calculate emissions for each well at least once
every 3 years. Calculation Method 1 requires that a reporter record an
average flow rate at a representative well by placing a recording flow
meter on the vent line from the well to an atmospheric tank, separator
or other device to vent the gas. The flow rate may be applied to other
wells in the same sub-basin/unloading type/pressure-diameter
combination. Therefore, the EPA's proposal would have required
reporters to measure a representative well in each sub-basin at least
once every 3 years. We received many comments suggesting the
requirement was overly burdensome
[[Page 42126]]
and unrealistic given the operational, logistical, and technical
challenges of placing flow meters on the vent lines to so many wells.
Unloadings are not steady state events, and the variability of flow in
an unloading event can also impact the accuracy of measurement using a
single flow meter as there will often be a large expulsion of gas at
the initiation of the unloading followed by a quickly declining
emission rate until gas begins flowing again to the sales line or other
flow line. After consideration of public comment and given the
challenges with flow measurement discussed above, the EPA is not
finalizing the proposed requirement to use Calculation Method 1 to
measure a representative well in each sub-basin at least once every 3
years in this final rule. Instead, the EPA is retaining the existing
requirement that allows reporters to choose Calculation Method 1 as an
option over the engineering equations in Calculation Methods 2 and 3.
In doing so we encourage reporters to use measured data in Calculation
Method 1 where feasible. However, we are confident that use of the
engineering equations in Calculation Methods 2 and 3 provides accurate
estimates of emissions from unloadings because inputs to the equations
are based on well-specific empirical data including casing and tubing
diameter, well depth, shut-in or line pressure, the flow line rate of
gas, and the time the well is left open for venting. Furthermore, the
additional granularity of reported data including all data inputs to
the equations and disaggregated reporting at the well level will allow
for more thorough verification by the EPA of reported data.
Although the final rule does not require use of Calculation Method
1 at least once every three years, the rule retains the existing
requirement that reporters electing to use Calculation Method 1 must
calculate a new average flow rate every other calendar year starting
with the first calendar year of data collection.
The EPA is also finalizing as proposed revisions to 40 CFR
98.236(f)(1) and (2) to require the reporting of certain data elements
that are included in existing equations W-8 and W-9 for Calculation
Methods 2 and 3 when calculating emissions from unloadings but which
were previously not reported. For Calculation Method 2, for wells
without plunger lifts, reporting of the following additional data
elements will now be required: well depth (WDp), the average
flow-line rate of gas (SFRp), the hours that wells are left
open to the atmosphere during unloading events (HRp,q), and
the shut-in, surface or casing pressure (SPp). For
Calculation Method 3, required reporting for wells with plunger lifts
will now include the additional following data elements: tubing depth
(WDp), the flow-line pressure (SPp), the average
flow-line rate of gas (SFRp), and (HRp,q).
Requiring reporting of these data elements will improve verification of
annual reports to the GHGRP and will allow the EPA and the public to
replicate calculations and more confidently confirm reported emissions
than is currently possible.
2. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to liquids unloading.
Comment: The EPA received comments asserting that the proposed rule
language that requires Calculation Method 1 every 3 years is
unnecessary and burdensome and will not lead to more accurate
reporting. Commenters also requested that the EPA allow an operator
that uses direct measurement in the first year to use the data obtained
from that first-year direct measurement in calculating emissions in
subsequent years (i.e., years 2 and 3). One commenter further asserted
that the EPA did not consider the Allen et al. (2015) study that
directly measured emissions from liquids unloading.\51\ Commenters
stated that knowing which wells will require and how often they require
liquids unloading venting is not predictable or consistent. Commenters
stated that when unloadings are needed is variable and does not
necessarily occur every 3 years. Commenters also suggested that
placement of a flow meter on the vent line will result in unacceptable
back-pressure on the well, effectively defeating the purpose of an
unloading, which is to relieve back pressure on the well. One commenter
also noted that the EPA does not require operators under NSPS OOOOb to
install a flow meter for liquids unloading venting. One commenter
provided anecdotal evidence from an operator, based on placement of
flow meters at 12 wells, that doing so caused significant operational
problems at the wells. Commenters requested that the EPA instead
continue to allow use of the engineering equations in Calculation
Methods 2 and 3, remove the proposed requirement to use Calculation
Method 1 every 3 years, and retain Calculation Method 1 as an option
for calculating emissions from liquids unloading.
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\51\ Allen, D.T., et al., 2015. ``Methane Emissions from Process
Equipment at Natural Gas Production Sites in the United States:
Liquid Unloadings.'' Eviron. Sci. Technol. 49, 641-648. https://pubs.acs.org/doi/10.1021/es504016r. Available in the docket for this
rulemaking, Docket ID. No. EPA-EQ-OAR-2023-0234.
---------------------------------------------------------------------------
Response: The EPA acknowledges that there can be challenges
associated with installing, operating, and monitoring flow meters on
well-pads. Liquid unloadings are not typically steady state events.
Back pressure on the vent line could result from use of orifice flow
meters with orifice cross-sections that are unable to manage highly
variable flow rates, especially following an initial surge of liquids
from the early stage of unloading. Back pressure can be alleviated by
changing out the orifice plates. However, we acknowledge that this can
be technically challenging in cases where unloading events are subject
to highly variable flow rates and/or in cases when the occurrence of
unloading events is not predictable. The EPA does note that Allen et.
Al. in their 2015 study on liquids unloading, placed flow meters on the
vent lines to tanks and did not report any back pressure or impediments
to the vent line.
We agree with the commenters that robust engineering equations for
liquids unloadings can provide reasonable estimates of emissions if all
unloading events are recorded accurately and all inputs to engineering
equations are recorded and reported accurately. In addition, the
additional new reporting requirements for unloadings in this final rule
require all data elements in equations W-8 and W-9 to be reported,
allowing for more thorough verification of reported emissions. Given
these considerations, the EPA is not finalizing the proposed
requirement to use Calculation Method 1 every 3 years. Instead,
Calculation Method 1 will remain an option for reporters, who may
choose between the three robust Calculation Methods under the final
rule. Should a reporter elect to use Calculation Method 1, the reporter
must comply with the existing requirement to calculate a new average
flow rate every other calendar year starting with the first calendar
year of data collection. For a new producing sub-basin category, the
reporter must calculate an average flow rate beginning in the first
year of production.
The EPA agrees that operators are not required to install a flow
meter under NSPS OOOOb; however, we note that program and this program
have complimentary but not identical goals. As such, the EPA disagrees
with the commenter's assertion that the lack of a requirement for flow
meters under the NSPS on its own would be justification for not
requiring measurement of liquids unloading events under subpart W.
[[Page 42127]]
The Allen et. Al. study measured emissions from liquids at 107
wells in four producing regions in the U.S. The study noted that
measured emissions at wells with plunger lift unloadings exceeded
calculated emissions using equation W-9. Conversely, emissions at wells
with non-plunger lift unloadings using equation W-8 were greater than
emissions measured by study. The conclusion of the study was that the
GHGRP nationwide total unloading emissions and the study's nationwide
estimate extrapolated from the 107 wells in the study were roughly
equivalent. Although the study found some variance between the results
of the engineering equations used for liquids unloading in the GHGRP
and the measurements taken in the field, the EPA believes the relative
consistency of nationwide results confirms the adequacy of the
equations. In addition, the new reporting requirements that further
differentiate the type of unloading between manual and automated
plunger lift and non-plunger lift unloadings and the required reporting
of all data elements in equations W-8 and W-9 will result in more
effective use of, and accurate results from, the engineering equations.
Comment: Commenters supported the proposed revisions to add
reporting requirements for liquids unloading events, including whether
the unloading event is automatic or manual, specific flow-line and
tubing depth data, and the hours that wells are left open during
unloading events. However, commenters suggested that the EPA clarify
that reporting for unloading events should only apply when the gas is
vented directly to the atmosphere or routed to a control device to
improve clarity for reporters and provide greater context for the
reported emissions for the EPA. Other commenters requested
clarification on what constitutes a control device.
Response: The EPA acknowledges the commenters' support for the new
reporting requirements for liquids unloading and is finalizing those
requirements largely as proposed. Additionally, the EPA agrees with the
commenter's recommendation to include language that clarifies that only
gas vented directly to the atmosphere or routed to a flare should be
reported and is finalizing language to this effect.
The EPA proposed to limit the calculation and reporting of
emissions to unloadings that vented directly to the atmosphere or to a
control device because it is those unloadings that release greenhouse
gas emissions. After further consideration, the EPA is retaining this
language in the final rule but is changing the proposed ``control
device'' reference to flares to be more specific. It is possible that
some natural gas from unloading events is routed to other types of
control devices, but emissions from these events will be covered under
those other sources (e.g., the combustion source). Although we do not
expect large volumes of natural gas to be directed to flares given the
purpose, nature and duration of unloading events, there may be some
instances of flaring gas off an unloading, and the EPA believes it is
important to capture these emissions. The final rule in 40 CFR
98.233(f) directs reporters who flare natural gas from unloadings to
calculate emissions using the calculation methods in 40 CFR 98.233(n),
Flare Stacks and report those emissions under 40 CFR 98.236(n).
Comment: The EPA received comments recommending that it consider
revising the definition of Casing Diameter (CDp) in equation
W-8 to IDp (Internal Diameter) to allow the application of
either tubing diameter if the well is equipped with tubing string and
no plunger lift, or casing diameter if the well does not have tubing
and plunger lift. According to the commenter, it is common practice for
operators to first install a tubing string to increase flow velocity
and install a plunger lift later when the well undergoes production
decline. The commenter stated that the diameter that is used in the
equation should be the diameter of the portion of the well that is
vented, whether venting the casing, tubing, or both. The commenter also
recommended that the EPA should clarify that the well depth is based
only on the vertical depth for horizontal wells. The commenter stated
that the volume of liquid should not be considered gas that is vented,
and rather only the depth above the fluids should be used to quantify
the vented gas.
Response: The EPA recognizes that operators may place stoppage
packers in the annulus of some wells, thereby removing the potential
for gas lift in the annulus so that the gas lift occurs in the tubing
string. Therefore, the EPA is amending the definition of CDp
in this final rule to address the use of stoppage packers. The
definition of CDp in the final rule states that it means,
``Casing internal diameter for well, p, in inches or the tubing
diameter for well, p, when stoppage packers are used in the annulus to
restrict flow of gas up the annulus to the surface.'' We disagree,
however, with the recommendation to revise the definition of casing
diameter in equation W-8 to internal diameter (IDp) because
there could be gas lift in the annulus between the casing and the
tubing string.
The EPA also agrees with the commenter that the depth should be
based on the vertical depth for horizontal wells. In most cases, the
horizontal portion of the well is very likely to be filled with liquids
from the end of the well bore up to at least the pivot point when the
horizontal hole pivots to vertical. While we acknowledge that
horizontal wells are very rarely truly horizontal through the well-
bore, and there is a possibility that some small quantities of gas may
exist in the non-vertical portion of the well-bore, these are likely to
be limited cases. The vertical portion of the well bore is where the
gas column will be mostly located. Horizontal wells produce gas along
one or more horizontal laterals directing flow from the producing
formation through the cased hole to the production string at the base
of the vertical portion of the well. Unloadings are required when
wells, primarily gas wells, accumulate liquids in the wellbore, and
velocity up the production tubing is not sufficient to lift liquids to
the surface; the well is effectively shut-in and ceases production
until the liquids are lifted and gas flow is restored. Horizontal
laterals are perforated at varying intervals along the lateral and
liquids accumulation in a horizontal well will generally occur first in
the horizontal portion of the well because that is where gas with
entrained liquids enters the production string. Eventually liquids are
likely to accumulate throughout the horizontal lateral to the base of
the vertical section of the well or even closer to the surface. In the
final rule, we have modified the definitions for well depth in equation
W-8 to add clarifying language allowing reporters using Calculation
Method 2 for non-plunger unloadings to consider the bottom of the well
for a horizontal well to be the point at which the vertical borehole
pivots to a horizontal direction. This change recognizes that it is
very likely that a horizontal well requiring an unloading will have
liquids accumulation from the top of the fluid column at the bottom of
the vertical portion of the well downhole through the extent of the
horizontal portion of the well. We do not believe the additional
language is necessary for equation W-9. The bottom of the well in
Calculation Method 3 is defined as tubing depth to the plunger bumper
and the bumper will normally be at the vertical base of the well.
Regarding well depth and the fluid column, the final rule allows
for reporters to consider the fluid column
[[Page 42128]]
depth in equations W-8 and W-9. More specifically, for wells where the
fluid column extends above the bottom of the well, well depth may be
measured from the top of the fluid column and this change is made in
the definition of WDp in equations W-8 and W-9 in the final
rule. This is optional for reporters and if they do not use the top of
the fluid column, they must consider the well depth to extend to the
bottom of the vertical portion of the well in equation W-8 for
Calculation Method 2 and to the plunger bumper in equation W-9 for
Calculation Method 3. The EPA is finalizing the rule with this option
because we understand that the available capacity to hold accumulated
gas volumes below the top of the fluid level in the wellbore is
displaced by liquids. Allowing reporters to consider the top of the
fluid column to be the bottom of the well in these instances will
result in more accurate emissions measurements. The EPA acknowledges
that in some cases small volumes of gas may be entrained in the
liquids. The entrained gas will separate from the liquids at a
separator or atmospheric tank downstream of the well and the entrained
gas emissions are subject to reporting in the hydrocarbon liquids and
produced water storage tanks source under 40 CFR 98.233(j). The
proposed definition for WDp in W-8 was ``Well depth from
either the top of the well or the lowest packer to the bottom of the
well, for well, p, in feet.'' In the final rule, we have added
additional clarifying language so that the final definition reads,
``Well depth from either the top of the well or the lowest packer to
the bottom of the well or to the top of the fluid column, for well, p,
in feet. For horizontal wells the bottom of the well is the point at
which the vertical borehole pivots to a horizontal direction.'' In
equation W-9, the definition for well depth, WDp, in the
final rule is ``Tubing depth to plunger bumper or to the top of the
fluid column for well, p, in feet.''
I. Gas Well Completions and Workovers With Hydraulic Fracturing
1. Summary of Final Amendments
The EPA is finalizing certain revisions to calculation and
reporting requirements in 40 CFR 98.233(g) and 98.236(g) for
completions and workovers with hydraulic fracturing with several
notable changes from the proposed requirements.
To calculate emissions from this source, reporters must use
equation W-10A or W-10B. Both equations are designed to calculate the
volumes of gas produced during the initial flowback, or pre-separation,
stage and during the separation stage when sufficient quantities of gas
are available to flow to a separator until the well moves to
production. Flow rates in the separation stage are measured or
calculated, but flow rates in the initial flowback period are currently
based on a calculation assuming the gas flow rate in the initial stage
is one half the gas flowrate at the beginning of the separation stage.
Consistent with section II.B. of this preamble, the EPA is finalizing a
change to equations W-10A and W-10B to allow use of multiphase flow
meters to measure gas flow rates during the initial flowback stage as
an alternative to assuming the flowrate is one half the flow rate at
the beginning of separation. Reporters may choose either option to
calculate the produced gas volume during the initial separation stage.
To include measurement with multiphase flow meters as an option, the
final rule includes minor changes from those proposed to equations W-
10A and W-10B in 40 CFR 98.233(g) to allow reporters to choose either
option, use of the original assumption of a flow rate that is half the
flow rate at the beginning of separation or a measured flow rate using
the multiphase meter. In addition, although we proposed removing the
engineering equations to calculate flow rates for gas well completions,
equations W-11A for sub-sonic flow and W-11B for sonic flow, following
review and consideration of public comment, we are retaining these
equations. The EPA is finalizing this change to the calculation methods
in 40 CFR 98.233(g) from proposal to allow use of calculated flow rates
for gas well completions using engineering equations only if it is not
possible to measure the flow rate for use in equations W-10A and W-10B.
The EPA is finalizing the rule to add reporting requirements in 40
CFR 98.236(g) to ensure consistency with requirements for the
determination of gas flow volumes and gas composition in the flare
stack emissions source. As discussed elsewhere in this preamble, the
EPA is finalizing calculation and reporting requirements for natural
gas emissions routed to the flare stacks from multiple sources.
Reporters routing gas to a flare from hydraulically fractured
completions and workovers must calculate CH4, CO2
and N2O emissions according to the calculation methods in 40
CFR 98.233(n), Flare stacks. Determination of gas flow volumes using
continuous parameter monitoring systems is specified in 40 CFR
98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and determination of gas
composition use continuous gas composition analyzers or gas sampling is
specified in 40 CFR 98.233(n)(4). If the reporter does not use
continuous flow measurements, the reporter must calculate natural gas
emissions routed to the flare using the calculation methods in 40 CFR
98.233(g) as specified in 40 CFR 98.233(n)(3)(ii)(B).
In addition, the EPA is finalizing changes to reporting
requirements in 40 CFR 98.236(g) from the proposal. In the final rule,
reporters are required to indicate how the flow during the initial
flowback period was determined. More specifically, reporters must
indicate whether the flow rate during the initial flowback period was
determined using a recording flow meter (digital or analog) at the
beginning of the separation, using a multiphase flow meter or using one
of the engineering equations, W11-A or W-11B. If a multiphase flowmeter
was used to measure the flow rate during the initial flowback period,
reporters are required to report the average flow rate measured by the
multiphase flow meter from the initiation of flowback to the beginning
of the period of time when sufficient quantities of gas present to
enable separation in standard cubic feet per hour. We are also
finalizing reporting requirements in 40 CFR 98.236(g) that require
reporters to indicate whether the flow rate measured during the
separation stage was measured using a using a recording flow meter
(digital or analog) installed on the vent line or calculated through
use of engineering equations W-11A or W-11B. In addition, we are
finalizing proposals to add reporting of additional identifiers for
completion and workover well type combinations, notably whether the
well is flared or vented and whether or not it is a reduced emission
completion or workover.
As discussed above, the EPA is not finalizing the proposed removal
of engineering equations W-11A and W-11B, the choke flow equations,
which can be used with equation W-10A as an option to calculate back
flow rates at gas well completions and workovers with hydraulic
fracturing. The EPA had proposed removing this option, which allows
reporters to use the engineering equation to calculate a flow rate for
gas well completions and workovers rather than measuring the flow rate.
Following receipt of comment and after further consideration, the EPA
understands there may be situations in the field where measurement may
not always be possible (for example, when a meter fails, if safety is
at risk or for some other operational reason). In the 2023 Subpart W
proposal, we explained that if we ultimately retained the choke flow
[[Page 42129]]
equation, we planned to amend the reporting requirements in the final
rulemaking to improve data quality and transparency. Therefore, we have
added a new reporting requirement in 40 CFR 98.236(g) to require
reporters that use equation W-10A to indicate whether the backflow rate
for the representative well is measured using a flow meter or
calculated using equations W-11A or W-11B. Under the existing
regulations, reporters using equation W-10A to calculate emissions from
gas well completions and workovers do not state in their annual GHGRP
reports whether the emissions were calculated using a measured flow
rate at the representative well or were calculated using the choke flow
equations, equation W-11A or W-11B. Although this provides the EPA with
an understanding of how many wells use a representative well as the
basis to calculate emissions, we do not have any clarity on the number
of wells that use the choke flow equations to calculate the gas flow
rate for the representative wells versus those that use a measured flow
rate at the representative wells. We believe reporting these data
improves data quality by helping the EPA better understand how many
reporters use the choke flow equations, the number of wells with
completions and workovers with emission calculations based on choke
flow equation measurements and the associated emissions. These
additional data elements will provide the EPA with a better
understanding of the bases for the reported emissions, which will
improve the EPA's ability to verify the reported data and, ultimately,
improve the accuracy of emissions.
2. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to gas well completions and workovers with
hydraulic fracturing.
Comment: Several commenters stated that existing methodologies for
calculating emissions from oil and gas well completions and workovers
with hydraulic fracturing are not based on empirical data, in
particular when estimating emissions during the initial flowback
period.
Response: The EPA disagrees with the commenters that proposed
methodologies were not based on empirical data. The equations in 40 CFR
98.233(g) used to calculate emissions from these sources rely on
empirical data measured for the well, including measured flowback flow
rates at the start of separation and throughout the separation stage.
The EPA acknowledges that equations W-10A and W-10B assume the average
flow rate is one half of the flow rate at the beginning of separation,
but we emphasize that the pre-separation flow rate is still calculated
based on a measured separation flow rate. In addition, as described in
the summary of final amendments for this source and later in this
comment and response section, the EPA is finalizing revisions to the
rule to allow use of multiphase flow meters during the initial pre-
separation stage as an option to directly measure gas flow rates
through the full initial flowback period. We intend to continue to
assess alternatives for determining gas flow rates and flow volumes
during the pre-separation stage.
The current rule includes equations W-11A and W-11B, the choke flow
equations, which are engineering equations that provide an option for
calculating flow rates at gas wells when direct measurement is not
possible. This final rule will continue to include these equations (as
discussed later in this comment and response section) but we note that
they also rely on well-specific and empirical data, such as the
pressure upstream and downstream of the choke.
Comment: The EPA received a comment with a suggestion to allow use
of multiphase flow meters to measure backflow rates prior to the
separation stage. The commenter stated that multiphase flow meters can
measure oil, gas, and water without the need for separation and that,
therefore, they are capable of measuring flowback from the beginning of
flowback to the separation stage.
Response: The commenter suggested use of a flowmeter upstream of
the separator to measure flow rates during the initial flowback period
to complement the existing use of flow meters downstream of the
separator to measure flow rates once separation is possible, which is
consistent with the purpose of the proposed amendments to add empirical
methods to the provisions and a potential refinement of the existing
calculation methodology to improve data quality. The EPA acknowledges
that use of multiphase meters is growing in the oil and gas industry.
In addition, given that current methodologies rely on gas flow rates
metered during the separation stage to estimate the flow rate during
the initial flowback period, the EPA agrees that using multiphase
meters to directly measure the initial flowback period flow rates
should improve the accuracy of emission estimates during the initial
flowback period under the existing methodology. We are, therefore,
amending 40 CFR 98.233(g) to include use of average flow rate
measurements from multiphase flow meters as an option for calculating
natural gas emissions during the initial flowback period.
Correspondingly, in the final provisions the EPA is also finalizing
changes to reporting requirements in 40 CFR 98.236(g) to require
reporters to indicate whether they used a multiphase flow meter to
calculate emissions from completions and workovers with hydraulic
fracturing. Under the final provisions in 40 CFR 98.233(g), reporters
may either use the assumption that the initial flowback rate is one
half of the flowrate at the beginning of separation or use flow rates
measured with a multiphase meter. While the EPA recognizes that
multiphase metering upstream of a separator could potentially be used
to extrapolate downstream flow rates, this would require complex
modeling of the change in the thermodynamic state of the fluid between
upstream and downstream conditions and an assumed separation efficiency
to quantify the gas flow downstream of the separator. Therefore, after
considering this and that use of a multiphase meter is a new approach
to quantifying emissions from completions and workovers, when metering
of the gas flow during the separation period is required under the
final provisions, the EPA is continuing to require use of a flowmeter
downstream of the separator even if a multiphase meter is placed
upstream of the separator.
Comment: The EPA received comments requesting to retain equations
W-11A and W-11B, the choke flow equations, noting that these equations
are used by reporters and further stating that the EPA provided no
rationale as to why it proposed to remove this calculation option other
than it is not used that often. In addition, several commenters also
suggested that the EPA should consider allowing use of a Gilbert-type
equation to be used to calculate gas flow rates. One commenter
recommended that the EPA evaluate the use of a Gilbert-type equation
while another commenter suggested replacing the existing choke flow
equations with a Gilbert-type equation.
Response: In the 2023 Subpart W Proposal, we proposed removing
equations W-11A and W-11B altogether, thus requiring use of measured
flow rates at hydraulically fractured completions and workovers. Based
on further consideration, including of the public comments we received,
we recognize that field conditions, operating conditions, or health and
safety considerations may preclude the use of flow meters to
[[Page 42130]]
measure back flow rates in certain cases. Therefore, the EPA is
retaining the existing choke flow equations, W-11A and W-11B, as an
option in the final rule.
The EPA is finalizing the rule without the addition of the Gilbert-
type equation. We only proposed and sought comment on whether to remove
the existing engineering equations; therefore, the suggestion to
finalize the rule with a new engineering equation is outside the scope
of this rulemaking. However, we thank the commenters for their
suggestion and we may consider the equation in a future rulemaking.
We note that inputs to the equations are based on well-specific
measurements for the orifice cross section, temperature, and pressure
upstream and downstream of the choke. However, the EPA expects that
flow rates determined based on direct measurements to be more accurate.
Therefore, the rule is finalized to specify that the engineering
equations can only be used when the reporter is unable to place a flow
meter on the line to a vent or flare.
Finally, in the final rule, we have added a new reporting
requirement in 40 CFR 98.236(g) to require reporters that use equation
W-10A to indicate whether the backflow rate for the representative well
is measured using a flow meter or calculated using equation W-11A or W-
11B.
J. Blowdown Vent Stacks
1. Summary of Final Amendments
Subpart W currently requires reporting of blowdowns either using
unique physical volume calculations by equipment or event types (40 CFR
98.233(i)(2)) or using flow meter measurements (40 CFR 98.233(i)(3)).
The EPA is finalizing as proposed, consistent with section II.D. of
this preamble, to move the listings of event types and the apportioning
provisions to a new 40 CFR 98.233(i)(2)(iv) so that the introductory
paragraph in 40 CFR 98.233(i)(2) would be more concise and provide
clearer information regarding which requirements are applicable for
each blowdown. Final 40 CFR 98.233(i)(2)(iv) includes separate
paragraphs for each set of equipment and event type categories and
provides clearer information regarding the applicable requirements for
each industry segment.
The EPA is finalizing as proposed revisions to the descriptions of
the facility piping and pipeline venting categories, which were
previously in 40 CFR 98.233(i)(2) and are now in the new 40 CFR
98.233(i)(2)(iv), to reflect the EPA's intent regarding which equipment
or event type category is appropriate for each blowdown, consistent
with section II.D. of this preamble. Our intent is that the ``facility
piping'' equipment category is limited to unique physical volumes of
piping (i.e., piping between isolation valves) that are located
entirely within the facility boundary. In contrast, the intent for the
``pipeline venting'' equipment category is that a portion of the unique
physical volume of pipeline is located outside the facility boundary
and the remainder, including the blowdown vent stack, is located within
the facility boundary. Additionally, we are finalizing as proposed the
removal of the reference to ``distribution'' pipelines in the
description of these two categories because we did not intend to limit
the pipeline venting category to unique physical volumes that include
such pipelines. Finally, we note that for the ``facility piping''
equipment category and the ``pipeline venting'' equipment category, the
existing phrase ``located within a facility boundary'' in the
descriptions of those categories generally refers to being part of the
facility as defined by the existing provisions of subpart A or subpart
W, as applicable, and we are not finalizing and did not propose to
change that portion of those descriptions.
We are finalizing as proposed the extension of the provisions in
equation W-14A of 40 CFR 98.233(i)(2)(i) that allow use of engineering
estimates based on best available information to determine the
temperature and pressure of an emergency blowdown to the Onshore
Natural Gas Transmission Pipeline segment, which aligns the
requirements for the two geographically dispersed industry segments
currently required to report blowdown vent stack emissions (Onshore
Natural Gas Transmission Pipeline and Onshore Petroleum and Natural Gas
Gathering and Boosting) and increases clarity of reporting requirements
for Onshore Natural Gas Transmission Pipeline industry segment
reporters, consistent with section II.D. of this preamble. As described
in section III.C.1. of this preamble, we are also finalizing as
proposed the use of engineering estimates to determine the temperature
and pressure for emergency blowdowns in equation W-14A for the
geographically dispersed industry segments that will begin reporting
emissions from blowdown vent stacks (Onshore Petroleum and Natural Gas
Production and Natural Gas Distribution).
As we explained at proposal, similar provisions to allow use of
engineering estimates based on best available information to determine
the temperature and pressure of an emergency blowdown were not added to
equation W-14B of 40 CFR 98.233(i)(2)(i) in 2015 (80 FR 64262, October
22, 2015). We are finalizing as proposed to add provisions to equation
W-14B of 40 CFR 98.233(i)(2)(i) to allow use of engineering estimates
to determine the temperature and pressure of an emergency blowdown for
both the geographically dispersed industry segments that currently
report blowdown vent stack emissions (Onshore Natural Gas Transmission
Pipeline and Onshore Petroleum and Natural Gas Gathering and Boosting)
as well as the geographically dispersed industry segments that will be
required to begin reporting blowdown vent stack emissions as described
in section III.C.1. of this preamble (Onshore Petroleum and Natural Gas
Production and Natural Gas Distribution), consistent with equation W-
14A. Additional minor technical corrections for clarity associated with
the blowdowns vent stack source are described in table 3 in section
III.V. of this preamble.
After consideration of public comments, we are also finalizing
additions to 40 CFR 98.236(i)(1) to specify how to assign blowdowns to
a well-pad site or gathering and boosting site if a blowdown event is
not directly associated with a specific well-pad or gathering and
boosting site or could be associated with multiple well-pad or
gathering and boosting sites. The final provisions direct reporters to
associate the blowdown with either the nearest well-pad or gathering
and boosting site upstream from the blowdown event or the well-pad or
gathering and boosting site that represented the largest portion of the
emissions for the blowdown event, as appropriate.
2. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to blowdown vent stacks.
Comment: One commenter stated that the EPA is proposing to require
site-level details regarding blowdowns and recommended that the EPA
instead allow reporters to aggregate events by type. The commenter
stated that aggregating events by type would avoid line-by-line
reporting per event and greatly reduce the complexity of reporting for
the source category, without impacting data quality or transparency.
The commenter also noted that some blowdowns such as mid-field pipeline
blowdowns are not
[[Page 42131]]
associated with a given well-pad or gathering station, so reporting
those pipelines by site could be challenging. The commenter suggested
allowing those types of blowdown events to be aggregated by county,
which is consistent with other pipeline reporting under PHMSA.
Response: The EPA did not propose and is not taking final action in
this rule to require individual blowdown reporting. The EPA did
propose, and is finalizing, reporting of certain emission source types
by well-pad site or gathering and boosting site, as described further
in section III.D. of this preamble. To implement those provisions, the
EPA is finalizing as proposed the additional requirement to report a
well-pad ID or gathering and boosting site ID for blowdowns at
facilities in the onshore petroleum and natural gas production and
onshore petroleum and natural gas gathering and boosting industry
segments, respectively, so that blowdown event reporting in these
industry segments is aggregated by equipment or event type at each
well-pad site or gathering and boosting site for facilities, as
appropriate. To further clarify this in the final provision, the EPA is
moving the requirement to report the equipment or event type from the
introductory text of 40 CFR 98.236(i)(1) to a separate reporting
element in 40 CFR 98.236(i)(1)(ii).
Regarding the concern with reporting a site for mid-field pipeline
blowdowns or other similar circumstances, in the final provisions, the
EPA has provided guidance in 40 CFR 98.236(i)(1) and (2) to assist with
these kinds of determinations. The final provisions direct reporters to
associate the blowdown with either the nearest well-pad or gathering
and boosting site upstream from the blowdown event or the well-pad or
gathering and boosting site that represented the largest portion of the
emissions for the blowdown event, as appropriate. This approach for
reporting is more appropriate for the final rule than a county-based
approach because very little data will be reported on a county (or sub-
basin) basis with the changes in reporting levels described in section
III.D. of this preamble. Further, it is similar to the established
approach for assigning blowdowns and emissions to an equipment or event
type when a blowdown event results in emissions from multiple equipment
or event types.
K. Atmospheric Storage Tanks
1. Open Thief Hatches
a. Summary of Final Amendments
The EPA is finalizing several amendments regarding thief hatch
monitoring on atmospheric storage tanks. These revisions to the
atmospheric tank calculation methodologies and reporting requirements
will help quantify the impact of open thief hatches on atmospheric
storage tank emissions and enhance the overall quality of the data
collected under the GHGRP, consistent with section II.B. of this
preamble.
The EPA is finalizing as proposed revisions to 40 CFR 98.233(j)(4)
that specifically state that emissions vented directly to the
atmosphere during times of reduced control system capture efficiency
are required to be calculated. Reduced capture efficiency may occur
during periods when the control device is not operating or is not
effectively capturing emissions, such as when thief hatches are open or
due to other causes such as open pressure relief devices.
We are also finalizing as proposed the calculation methodology in
40 CFR 98.233(j)(4) for determining reduced capture efficiencies when a
control device is in use but a thief hatch is open. We are finalizing
revisions to 40 CFR 98.233(j)(4)(i)(C) to require facilities to assume
that no emissions are captured by the control device (0 percent capture
efficiency) when the thief hatch on a tank is open, with one revision.
After consideration of comments received, we are clarifying in 40 CFR
98.233(j)(4)(i)(C) that a thief hatch is open if it is fully or
partially open such that there is a visible gap between the hatch cover
and the hatch portal, as the EPA did not intend for leaks from an open
thief hatch that are only identifiable using OGI technologies to be
required to assume a capture efficiency of zero.
The EPA is finalizing the requirements of 40 CFR 98.233(j)(7) to
require monitoring of the thief hatch with revisions from proposal. We
are finalizing as proposed that if a thief hatch sensor is present and
operating on the tank, sensor data must be used to inform the periods
of time that a thief hatch is open. Regarding the proposed revision
that the thief hatch sensor must be capable of transmitting and logging
data whenever a thief hatch is open and when the thief hatch is
subsequently closed, in the final provision we removed the requirement
that the sensor be capable of transmitting data, in order to include
use of sensor data in situations where the sensor has local logging
capabilities but is not able to remotely transmit the data.
Additionally, after consideration of comments, we are adding in the
final provisions a requirement that if a thief hatch sensor is not
operating but a tank pressure sensor is operating on a controlled
atmospheric pressure storage tank, reporters must use data obtained
from the pressure sensor to determine periods when the thief hatch is
open. Similar to an applicable thief hatch sensor, an applicable
operating tank pressure sensor must be capable of logging tank pressure
data. It is expected that operators would assume that a pressure
indication outside of normal operating range would indicate an issue
with the thief hatch. Pressure indication is similar in accuracy as a
visual inspection in the case of open thief hatches.
The EPA is finalizing the requirements in 40 CFR 98.233(j)(7) as
proposed with revisions to clarify that if neither an applicable thief
hatch sensor nor an applicable tank pressure sensor is operating on the
controlled atmospheric storage tank, reporters must perform a visual
inspection of each thief hatch on a controlled atmospheric storage
tank. We are further clarifying in the final rule that visual
inspections in accordance with 40 CFR 98.233(j)(7)(i) through (iii)
must be performed for tanks equipped with thief hatch or pressure
sensors during periods of time when the thief hatch or pressure sensor
is not operating or malfunctioning for longer than 30 days. We feel
that 30 days is a reasonable amount of time during which the facility
can return the sensor back into service before triggering a visual
inspection requirement to assure proper operation of the equipment.
This is similar to the requirements for continuous flare pilot flame
monitoring that requires a monthly visual inspection (which is the
requirement in absence of continuous monitoring) if the continuous
monitoring device is out of service for more than 4 weeks. We are
finalizing 40 CFR 98.233(j)(7)(i) with a correction to an inadvertent
error from proposal, requiring that if the thief hatch is required to
be monitored as part of a cover or closed vent system, rather than to
comply with requirements of 40 CFR 60.5397b, to comply with 40 CFR
60.5395b or the applicable EPA-approved state plan or the applicable
Federal plan in 40 CFR part 62 on a controlled atmospheric storage
tank, visual inspections must be conducted at least as frequent as the
required AVO inspection described in 40 CFR 60.5416b or the applicable
EPA-approved state plan or the applicable Federal plan in 40 CFR part
62, or annually (whichever is more frequent). A similar correction is
also being made to 40 CFR 98.233(j)(7)(ii). Additionally, we are
removing the phrase ``fugitive emissions'' from 40 CFR 98.233(j)(7)(i)
[[Page 42132]]
and (ii) as tank covers are not considered fugitive emission components
under the updated cross-referenced provisions. We are finalizing the
requirements in 40 CFR 98.233(j)(7)(ii) and (iii) as proposed, which
require visual inspections once per calendar year, at a minimum, for
tanks not equipped with thief hatch or pressure sensors and for tanks
with malfunctioning thief hatch or pressure sensors. We are finalizing
as proposed that if one visual inspection is conducted in the calendar
year and an open thief hatch is identified, the reporter is required to
assume that the thief hatch had been open for the entire calendar year
or the entire period that the sensor(s) was not operating or
malfunctioning if the visual inspection occurred during the period in
which it was malfunctioning or not operating. If multiple visual
inspections are conducted in the calendar year and an open thief hatch
is identified, the reporter is required to assume that the thief hatch
had been open since the preceding visual inspection (or the beginning
of the year if the inspection was the first performed in a calendar
year) through the date of the visual inspection (or the end of the year
if the inspection was the last performed in a calendar year).
We are finalizing the reporting requirements for open thief hatches
in 40 CFR 98.236(j) as proposed. We are finalizing the addition of 40
CFR 98.236(j)(1)(x)(F) to require reporting of the number of controlled
atmospheric storage tanks with open thief hatches within the reporting
year, as well as the addition of 40 CFR 98.236(j)(1)(xv) to require
reporting of the total volume of gas vented through the open thief
hatches, for Calculation Methods 1 and 2. We are finalizing similar
requirements for atmospheric storage tanks with emissions calculated
using Calculation Method 3 in 40 CFR 98.236(j)(2)(ii)(D) and (H) for
hydrocarbon liquids tanks and 40 CFR 98.236(j)(2)(iii)(D) and (F) for
produced water tanks.
We are finalizing the revisions in 40 CFR 98.233(j)(4)(i)(D) as
proposed to require facilities to account for time periods of reduced
capture efficiency from causes other than open thief hatches when
determining total emissions vented directly to atmosphere based on best
available data, with one clarification. As described for open thief
hatches, the EPA understands that pressure monitoring data may be used
to determine when a pressure relief device is open and venting to the
atmosphere on a controlled atmospheric storage tank. Thus, the EPA is
clarifying in 40 CFR 98.233(j)(4)(i)(D) that best available data may
include, but is not limited to, data from operating pressure sensors on
atmospheric pressure storage tanks. In cases where a pressure relief
device is open, reporters must use pressure sensor data (if available)
to assist in the determination of the duration of the release and use
best available data to determine the reduction in capture efficiency.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to open thief hatches on atmospheric storage
tanks.
Comment: Several commenters requested that the EPA provide a
definition of an open or not properly seated thief hatch and clarify
whether leaks that can only be identified through use of an OGI camera
or similar detection technology do not meet the definition of an open
or not properly seated thief hatch. Many commenters noted that it is
inaccurate to assume a small, wisping leak only seen through an OGI
camera would require an operator to assume 0 percent capture efficiency
when most of the storage tank vapors remain in the tank, are captured,
or are routed to a control device. Additionally, commenters noted that
small leaks would not be identified with the proposed technology
suggested by the EPA: thief hatch sensor or visual inspection
monitoring methods.
Response: In the final rule, the EPA is removing from the proposed
provisions the phrase ``not properly seated'' in 40 CFR
98.233(j)(4)(i)(C) through (D) and 40 CFR 98.233(j)(4)(ii) and instead
specifying that a thief hatch is open if it is fully or partially open
such there is a visible gap between the hatch cover and the hatch
portal. The requirements to perform a visual inspection to identify a
gap on applicable atmospheric storage tank thief hatches would not
necessitate the use of OGI technologies to identify emissions. Thus, in
this final rule, emissions from an open thief hatch that are only
identifiable using OGI technologies would not be required to assume a
capture efficiency of 0 percent but these emissions would still have to
be quantified under 40 CFR 98.233(j)(4)(i)(D) based on best available
data, including any data from operating pressure sensors on atmospheric
pressure storage tanks. A visible gap creates a larger more direct path
of emissions to the atmosphere, so we are maintaining the assumed a 0
percent capture efficiency for this case. While we are not requiring
emissions that are only identifiable using OGI technologies to assume a
capture efficiency of 0 percent, such emissions identified through OGI
may still constitute a violation of emission standards under NSPS OOOOb
or a state or federal plan implementing EG OOOOc.
We note that we may consider the option of incorporating thief
hatches into the leak requirements in 40 CFR 98.233(q) and (r) in
future rulemakings.
Comment: Many commenters requested that tank pressure sensors be
acceptable to determine if tank thief hatches are open or not properly
seated. One commenter stated that on controlled tanks, these sensors
will register (for example) between 0.8 and 8 pounds of pressure. The
commenter notes that a pressure indication outside of this range would
indicate an issue with the thief hatch. Pressure indication could in
fact be more accurate than a visual inspection in the case of a not
properly seated thief hatch.
Response: The EPA agrees with the commenters that the use of
pressure monitors on atmospheric storage tanks are appropriate for
determining the duration of time a thief hatch is open. The EPA concurs
with commenters that, on controlled tanks, pressure sensors will
typically register within a normal operating range (e.g., between 0.8
and 8 pounds of pressure). If a thief hatch is open, the tanks will not
build up pressure. A pressure indication outside of the normal
operating range would indicate an issue with the thief hatch and could
be used to determine duration of a thief hatch opening. Thus, in the
final rule, we are adding language to 40 CFR 98.233(j)(7) to include
requirements for the use of pressure sensors on applicable atmospheric
storage tanks with thief hatches. Specifically, we are adding language
to specify that if a thief hatch sensor is not operating but a pressure
sensor is present and operating on the tank, pressure sensor data must
be used to inform the periods of time that a thief hatch is open. The
thief hatch sensor must be capable of logging data whenever a thief
hatch is open and when the thief hatch is subsequently closed. We agree
that including requirements for the use of pressure sensor data for
open thief hatch determinations as specified in the final provisions
will improve the accuracy of reported emissions and incorporate
empirical data.
Comment: One commenter noted that thief hatch sensors do
periodically malfunction and may falsely indicate an open thief hatch.
The commenter requested that the EPA allow reporters to exclude thief
hatch sensor
[[Page 42133]]
malfunction periods and instead use best available monitoring data
(e.g., TEMS, other parametric monitoring, last inspection) when
determining the time that the thief hatch was open in calculating and
reporting storage tank emissions.
Response: In the final rule, the EPA is finalizing that operators
are required to use thief hatch sensors or pressure monitors where they
are already installed and operating, which implies properly functioning
equipment. As proposed, the EPA states in 40 CFR 98.233(j)(7) that
thief hatch sensors (and in the final rule, pressure monitors) must be
capable of logging data whenever the thief hatch is open. Thus,
malfunctioning equipment would not meet these requirements and should
not be used to determine periods of time when thief hatches are open.
In the final rule, the EPA is further clarifying that during periods of
time when the sensor is malfunctioning for periods greater than 30
days, facilities must perform visual inspections and determine thief
hatch opening durations according to the methodologies in 40 CFR
98.233(j)(7)(i) through (iii).
2. Malfunctioning Dump Valves
a. Summary of Final Amendments
The EPA is finalizing as proposed revisions to the equation
variables (particularly the subscripts) in equation W-16 to clarify the
intent of this equation. Specifically, we are finalizing the change of
the variable ``En'' to ``Es,i'' to further
clarify that these are the volumetric atmospheric storage tank
emissions determined using the procedures in 40 CFR 98.233(j)(1), (2),
and, if applicable, (j)(4). We are also finalizing the replacements of
the ``n'' and ``o'' subscripts in the other variables with a ``dv''
subscript to indicate that these are the emissions from periods when
the gas-liquid separator dump valves were not closed properly and that
the emissions from these periods should be added to the emissions
determined using the procedures in 40 CFR 98.233(j)(1), (2), and, if
applicable, (j)(4).
The EPA is finalizing the requirements of 40 CFR 98.233(j)(5)(i) to
require monitoring of the gas-liquid separator liquid dump valve with
revisions from proposal, consistent with section II.B. of this
preamble. In the final rule, we are adding after consideration of
comment that if a parametric monitor is present and operating on the
tank or gas-liquid separator, then the parametric monitor data must be
used to inform the periods of time that a dump valve is stuck in an
open or partially open position as well as when the dump valve is
subsequently closed. Similar to pressure sensors on thief hatches, it
is expected that operators would assume that a parameter (e.g.,
pressure, temperature, flow) indication outside of normal operating
range would indicate an issue with the dump valve. Parameter indication
is similar in accuracy as a visual inspection in the case of
malfunctioning dump valves. We are also finalizing that the parametric
monitor must be capable of logging data whenever a gas-liquid separator
liquid dump valve is stuck in an open or partially open position and
when the gas-liquid separator liquid dump valve is subsequently closed,
which will allow reporters to accurately determine the time input for
equation W-16 (Tdv).
The EPA is finalizing the requirement to perform routine visual
inspections of separator dump valves to determine if the valve is stuck
in an open or partially open position when an applicable parametric
monitor is not present or is not operating, with a revisions from
proposal that expands the inspections to also include audio and
olfactory inspections. Audio, visual, and olfactory (AVO) inspections
would be required once per calendar year, at a minimum. Similar to the
provisions of 40 CFR 98.233(q) and 40 CFR 98.233(j)(7), if one AVO
inspection is conducted in the calendar year and a stuck dump valve is
identified, the reporter is required to assume that the dump valve had
been stuck open for the entire calendar year. If multiple AVO
inspections are conducted in the calendar year and a stuck dump valve
is identified, the reporter is required to assume that the dump valve
had been stuck open since the preceding AVO inspection (or the
beginning of the year if the inspection was the first performed in a
calendar year) through the date of the AVO inspection (or the end of
the year if the inspection was the last performed in a calendar year).
The EPA determined that this is an appropriate methodology as it is
consistent with the inspection requirements for dump valves under 40
CFR 98.233(k).
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to malfunctioning dump valves on separators
feeding on atmospheric storage tanks.
Comment: Many commenters requested that parametric monitoring be
acceptable to determine if a gas-liquid separator liquid dump valve is
stuck in an open or partially open position. Additionally, commenters
noted that an effective approach to identify stuck dump valves involves
auditory inspections of the tank, particularly in cases where tanks are
designed with submerged fill--a stuck dump valve allowing gas flow into
the tank produces noticeable ``bubbling'' sounds.
Response: The EPA agrees with the commenters that the use of
parametric monitors on atmospheric storage tanks and gas-liquid
separators are appropriate for determining the duration of time a gas-
liquid separator liquid dump valve is stuck in an open or partially
open position. The EPA concurs that, for operators of high-pressure
gas-liquid separators, wells will be shut-in or there will be alarms
requiring immediate response due to the separator reaching low liquid
level, which will happen if a gas-liquid separator liquid dump valve is
stuck in an open position. In other cases, operators will also monitor
the density of the fluid going to the tank and alarms on low density
will trigger follow up to inspect for a malfunctioning gas-liquid
separator liquid dump valve. Thus, in the final rule, we are adding
appropriate language to 40 CFR 98.233(j)(5)(i) to include the use of
parametric monitors on applicable atmospheric storage tanks and gas-
liquid separators. We agree that including use of parametric monitoring
data to determine whether or not a dump valve is stuck open as
specified in the final provisions will improve the accuracy of reported
emissions and incorporate empirical data.
The EPA also agrees that, for those tanks and separators without a
parametric monitor, auditory inspections should be used in conjunction
with visual inspections to determine if a gas-liquid separator liquid
dump valve is stuck in an open or partially open position. We agree
that an effective approach to identify stuck gas-liquid separator
liquid dump valves involves auditory inspections of the tank,
particularly in cases where tanks are designed with submerged fill--a
stuck dump valve allowing gas flow into the tank produces noticeable
``bubbling'' sounds. In the final rule, we are clarifying in 40 CFR
98.233(j)(5) that AVO inspections must be performed to determine if a
gas-liquid separator liquid dump valve is stuck in an open or partially
open position.
3. Applicability and Selection of Appropriate Calculation Methodologies
for Atmospheric Storage Tanks
a. Summary of Final Amendments
The EPA is finalizing several revisions with regard to the
[[Page 42134]]
applicability and selection of an appropriate calculation methodology
for atmospheric storage tanks, consistent with sections II.B. and II.C.
of this preamble. The EPA is finalizing revisions to the introductory
text of 40 CFR 98.233(j) as proposed to add language that clearly
states that the annual average daily throughput of hydrocarbon liquids
should be based on flow out of the separator, well, or non-separator
equipment determined over the actual days of operation. We are also
finalizing certain changes to the introductory text in 40 CFR 98.233(j)
as proposed, which amends the requirements in 40 CFR 98.233(j) to
specify that reporters may use Calculation Method 1, Calculation Method
2, or Calculation Method 3 when determining emissions from atmospheric
storage tanks receiving hydrocarbon liquids flowing out of wells, gas-
liquid separators, or non-separator equipment with throughput greater
than 0 barrels per day and less than 10 barrels per day. After
consideration of comments, we are finalizing the conditions under which
a facility is required to use 40 CFR 98.233(j)(1) with a modification.
The proposed requirement stated that if reporters conduct modeling for
environmental compliance or reporting purposes, including but not
limited to compliance with Federal or state regulations, air permit
requirements, or annual inventory reporting, or internal review, they
would use those results for reporting under subpart W. Based on
consideration of public comment concerning the nature of modeling for
internal review purposes by facilities, and differences in program
requirements, we are not finalizing the proposed requirement to use the
results from such modeling for reporting under subpart W. We are
instead requiring in the final provisions that if a facility is
required to use a software program for compliance with federal or state
regulations, air permit requirements or annual emissions inventory
reporting that meets the requirements of in 40 CFR 98.233(j)(1), they
must use 40 CFR 98.233(j)(1) for reporting under subpart W. We
anticipate that modeling consistent with the methodology outlined in 40
CFR 98.233(j)(1) could be conducted by reporters for environmental
compliance or reporting purposes or reporters may run a simulation
solely for the purpose of reporting under subpart W. This will ensure
that the facility is able to use modeling results that are
representative of actual operating conditions and meet the requirements
of 40 CFR 98.233(j)(1) without requiring that models completed for
other purposes meet the requirements under this subpart.
We are finalizing the removal of the ``fixed roof'' language when
referring to atmospheric pressure storage tanks subject to 40 CFR
98.233(j) as proposed. We are also finalizing revisions to 40 CFR
98.236(j)(1)(x) and 40 CFR 98.236(j)(2)(i) to require separate
reporting of the total count of fixed roof and floating roof tanks at
the facility. We are finalizing revisions of all instances of ``storage
tanks,'' ``atmospheric tanks,'' and ``tanks'' in 40 CFR 98.233(j) and
40 CFR 98.236(j) to instead use the term ``atmospheric pressure storage
tanks'' as proposed. We are finalizing the addition of a definition for
an atmospheric pressure storage tank as proposed, which is defined as
``a vessel (excluding sumps) operating at atmospheric pressure that is
designed to contain an accumulation of crude oil, condensate,
intermediate hydrocarbon liquids, or produced water and that is
constructed entirely of non-earthen materials (e.g., wood, concrete,
steel, plastic) that provide structural support. Atmospheric pressure
storage tanks include both fixed roof tanks and floating roof tanks.
Floating roof tanks include tanks with either an internal floating roof
or an external floating roof.''
We are moving the last sentence of 40 CFR 98.233(j), which contains
reference to ``paragraph (j)(4) of this section'' to be located prior
to discussion of ``paragraph (j)(5) of this section'' so that paragraph
references appear in the order in which they are contained in the
regulatory text. Relatedly, we are also deleting the sentence
immediately following discussion of ``paragraph (j)(5) of this
section'' because it is largely duplicative of the moved last sentence
of 40 CFR 98.233(j), as proposed.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to the application and selection of appropriate
calculation methodologies for atmospheric storage tanks.
Comment: One commenter reported that simulations run for ``internal
review'' for a variety of purposes, including ``what-if'' scenarios
(i.e., exploring possible engineering adjustments) may not meet the
EPA's goal of estimating emissions based on operating conditions. The
commenter recommended that only simulations run for compliance purposes
should be used.
Response: We agree with the commenter that simulations run for
other purposes may not result in emissions estimations based on
representative operating conditions, as facilities may complete models
for a variety of purposes, including models to consider future
adjustments to the operation of the unit that are based on possible
future, not actual, operating conditions. We are not finalizing the
proposed requirement that all results from simulations run for the
purposes of ``internal review'' or modeling completed for environmental
compliance or reporting purposes are required to be used for reporting.
We are instead requiring in the final provisions that if a facility
performs emissions modeling for compliance with federal or state
regulations, air permit requirements or annual emissions inventory
reporting using a software program that meets the requirements of 40
CFR 98.233(j)(1), they must also use 40 CFR 98.233(j)(1) for reporting
under subpart W. We expect that these amendments as finalized will
increase the quality of data collected without requiring the inclusion
of results from inappropriate modeling runs. We have revised the
language in 40 CFR 98.233(j) introductory text to clarify these
requirements.
4. Controlled Atmospheric Storage Tanks
a. Summary of Final Amendments
The EPA is finalizing the revisions to the methodologies for
calculating controlled atmospheric storage tanks emissions vented
directly to the atmosphere in 40 CFR 98.233(j)(4), consistent with
section II.D. of this preamble. We are finalizing 40 CFR
98.233(j)(4)(i) with modifications from proposal. As proposed, the
methodology under 40 CFR 98.233(j)(4)(i) for calculating emissions
vented to the atmosphere during periods of reduced capture efficiency
of the vapor recovery system or flare (e.g., when a thief hatch is open
or not properly seated or when a pressure relief valve is open) first
required reporters to determine the maximum potential vented emissions
as specified under 40 CFR 98.233(j)(1), (2), or (3) per 40 CFR
98.233(j)(4)(i)(A). In the final rule, the EPA is removing the term
``maximum potential'' from 40 CFR 98.233(j)(4)(i)(A); while this term
was meant to signify that reporters should not reduce for controls at
this step of the calculation, we understand that the terminology may
have been confused for worst-case condition potential-to-emit (PTE)
emissions. Thus, in the final rule, the EPA is adding language to 40
CFR
[[Page 42135]]
98.233(j)(4)(i)(A) to clarify consistent with our original intent.
The provisions for calculating recovered mass in 40 CFR
98.233(j)(4)(ii) are being finalized as proposed. For flared
atmospheric storage tank emissions, the revisions to 40 CFR 98.233(j),
which direct reporters to the methodologies in 40 CFR 98.233(n), are
being finalized as proposed. While the final flaring provisions differ
somewhat from the proposed provisions, as explained in more detail in
section III.N. of this preamble, the final amendments generally specify
as proposed that vented atmospheric storage tank emissions include only
those emissions vented directly to the atmosphere and emissions routed
to a flare are considered flare stack emissions.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to the calculation and reporting of emissions
from controlled atmospheric storage tanks.
Comment: One commenter requested that the EPA remove the term
``maximum potential'' from 40 CFR 98.233(j)(4)(i)(A), as assuming
worst-case conditions would be required to determine a maximum
potential case, which does not reflect actual operations. The commenter
states that this does not further the EPA's goal of accurately
determining emissions.
Response: The EPA did not intend for reporters to calculate
emissions using worst-case conditions for this step of the calculation
methodology for controlled atmospheric storage tank emissions. Rather,
the EPA had intended the language to signify that reporters should
calculate their vented emissions from the atmospheric storage tank
without reducing emissions for controls. However, we agree with the
commenter that this language could be misunderstood. In the final rule,
the EPA is revising 40 CFR 98.233(j)(4)(i)(A) from proposal by removing
the proposal term ``maximum potential'' and adding language to clarify
that emissions in this step of the methodology should represent the
emissions from the atmospheric storage tank prior to the vapor recovery
system or flare, consistent with the original intent of the provision.
5. Calculation Methods 1 and 2 for Atmospheric Storage Tanks
a. Summary of Final Amendments
The EPA is finalizing that reporters would collect measurements of
the simulation input parameters listed under 40 CFR 98.233(j)(1)(i)
through (vii), consistent with section II.B. of this preamble, with the
following changes from proposal. After consideration of comments
received, in an effort to reduce burden on reporters, we are specifying
that, with the exception of the API gravity, composition and Reid vapor
pressure required by 40 CFR 98.233(j)(1)(iii) and (vii), the
measurements must be taken at least annually since the maximum time
period covered by a simulation would be the reporting year, as we
expect these measurements to be more easily attainable or significantly
variable between reporting years. For API gravity, composition, and
Reid vapor pressure, and per 40 CFR 98.233(j)(1)(iii) and (vii),
measurements would be required to be conducted within six months of
start-up or by January 1, 2030 (i.e., within five years of the
effective date of the rule), whichever is later, and at least once
every five years thereafter. Relatedly, we are combining the API
gravity model input at 40 CFR 98.233(j)(1)(iii) with the composition
and Reid vapor pressure model inputs at 40 CFR 98.233(j)(1)(vii) so
that all model input parameters with the sampling frequency different
from annual are contained in the same subparagraph. Until such time
that a sample can be collected, reporters may continue to determine API
gravity by engineering estimate and process knowledge based on best
available data and composition and Reid vapor pressure by using one of
the existing methods described in 40 CFR 98.233(j)(1)(vii)(A) through
(C). We are finalizing similar edits in 40 CFR 98.233(j)(2)(i). We are
also finalizing the removal of the provisions of 40 CFR
98.233(j)(2)(ii) and (iii) as proposed, which allowed for
representative compositions to be used for tanks receiving liquids
directly from wells or non-separator equipment. For the measured
parameters in 40 CFR 98.233(j)(1)(i) through (vii), we are clarifying
in the final rule that measurements must only be taken if the parameter
is an input to the modeling software selected by the reporter.
We are finalizing the addition of ProMax as an example software
program for calculating atmospheric tank emissions per 40 CFR
98.233(j)(1) as proposed, consistent with section II.B. of this
preamble. Consistent with the EPA's revisions to 40 CFR 98.233(e)(1)
for dehydrators, the EPA is requiring the use of ProMax version 5.0 or
above.
The EPA is finalizing the amendments to 40 CFR 98.233(j) as
proposed such that facilities with wells flowing directly to
atmospheric storage tanks without passing through a separator may use
either Calculation Method 1, Calculation Method 2, or, for wells, gas-
liquid separators, or non-separator equipment with annual average daily
throughput greater than 0 barrels per day and less than 10 barrels per
day, Calculation Method 3, consistent with section II.B. of this
preamble. We are also finalizing the conforming edits within 40 CFR
98.233(j)(1) and (2) and 40 CFR 98.236(j)(1) to refer to parameters and
requirements for wells flowing directly to atmospheric storage tanks.
We are finalizing the reorganization of the reporting requirements
in 40 CFR 98.236(j)(1) as proposed, consistent with section II.C. of
this preamble. In the final rule, tank counts are collected under 40
CFR 98.236(j)(1)(x)(A) through (F), and the reporting of CO2
and CH4 vented emissions and recovered mass is reported
under 40 CFR 98.236(j)(1)(xi) through (xiv). The EPA is also finalizing
the removal of 40 CFR 98.236(j)(1)(xi) as proposed. The EPA is
finalizing 40 CFR 98.236(j)(1)(vii) and (viii) with revisions from
proposal to require the flow-weighted average concentration (mole
fraction) of CO2 and CH4 in the flash gas, rather
than the minimum and maximum values, for only those reporters that used
Calculation Method 1 to determine emissions from atmospheric storage
tanks.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to calculation methodologies 1 and 2 for
atmospheric storage tanks.
Comment: Several commenters requested clarification on whether the
EPA intends for input parameters to model tank emissions calculated
using Calculation Method 1 to be measured annually. Commenters
requested a five-year measurement time frame in which measurements are
gathered every five years due to the high level of burden that the
measurement and sampling requirements impose.
Response: The proposed requirements to measure certain inputs for
Calculation Methods 1 and 2 were not prescriptive with regard to a time
frame to obtain measurements. The EPA only specified in 40 CFR
98.233(j) that if an applicable parameter must be measured, the
reporter must ``collect measurements reflective of representative
operating conditions over the time period covered by the simulation.''
[[Page 42136]]
Regarding the frequency of measurement, as explained in the
preamble to the 2023 Subpart W Proposal, we proposed that reporters
would collect measurements reflective of representative operating
conditions over the time period covered by the simulation. In addition,
we proposed that the parameters that must be used to characterize
emissions should reflect operating conditions over the time period
covered by the simulation rather than just over the calendar year.
Under this proposed change, reporters could continue to run the
simulation once per year with parameters that are determined to be
representative of operating conditions over the entire year.
Alternatively, reporters would be allowed to conduct periodic
simulation runs to cover portions of the calendar year, as long as the
entire calendar year is covered. The reporter would then sum the
results at the end of the year to determine annual emissions. In that
case, the parameters for each simulation run would be determined for
the operating conditions over each corresponding portion of the
calendar year.
Requirements for measurement frequency for 40 CFR 98.233(j)(1)(i)
through (vi) are being clarified in the final provisions to specify
that for these input parameters, the measurements must be taken at
least once per year where parameters are determined to be
representative of operating conditions over the entire year, or the
measurements must be taken multiple times per year, where the
measurements are reflective of representative operating conditions over
shorter time periods. However, after consideration of the significant
burden noted by commenters to sample all hydrocarbon liquid and
produced water storage tanks within their facility each reporting year,
the EPA is finalizing a reduced frequency schedule in 40 CFR
98.233(j)(1)(vii) for API gravity, composition and Reid vapor pressure
sampling and analysis from each well, separator, or non-separator
equipment. Reporters must sample and analyze sales oil or stabilized
hydrocarbon liquids for API gravity, hydrocarbon liquids or produced
water composition, and hydrocarbon liquids Reid vapor pressure within
six months of equipment star-up, or by January 1, 2030, whichever is
later, and at least once every five years thereafter. Until such time
that a sample can be collected from the well, separator, or non-
separator equipment, reporters may determine API gravity by engineering
estimate and process knowledge based on best available data, and
composition and Reid vapor pressure using one of the representative
methods in 40 CFR 98.233(j)(1)(vii)(A) through (C). We believe that
measurements taken at this frequency will be sufficiently
representative of the API gravity, composition and Reid vapor pressure
as we do not expect significant changes in comparison to cases where
physical or operational changes, such as when a well feeding the
atmospheric pressure storage tank undergoes fracturing or refracturing,
are made.
Comment: One commenter stated that not all process simulation
software requires all of the input parameters listed in 40 CFR
98.233(j)(1) to run the model. The commenter noted that in some process
simulators (e.g., BR&E ProMax, AspenTech HYSYS), if a hydrocarbon
liquids composition is provided for the tank feed, API gravity and Reid
Vapor Pressure are not needed as inputs to the simulation as these can
be calculated from the other input parameters.
Response: The EPA understands that the different modeling software
options available to reporters may require different input parameters
in order to produce an accurate emissions estimate for atmospheric
tanks. We agree with the commenter that only the input parameters that
are required to run the model need to be measured. Therefore, in the
final rule, the EPA is clarifying the language in 40 CFR
98.233(j)(1)(i) through (vii) to reflect this.
Comment: One commenter noted that additional edits are required to
40 CFR 98.236(j)(1)(vii) and (viii), as these requirements to report
flash gas CO2 and CH4 concentrations seem to be
specific to Calculation Method 1. The commenter stated that for
Calculation Method 2, reporters must assume the CO2 and
CH4 in solution from the oil sent to tanks is emitted to
atmosphere, so the concentrations of CO2 and CH4
in the flash gas are not known.
Response: The EPA agrees with the commenter that, for reporters
using the emissions calculation methodology described in 40 CFR
98.233(j)(2), facilities must assume all CO2 and
CH4 in solution from hydrocarbon liquids sent to tanks would
be emitted to atmosphere. Therefore, the EPA agrees that these flash
gas concentrations for these GHGs are not known when using Calculation
Method 2 and so has revised 40 CFR 98.236(j)(1)(vii) and (viii) to be
only applicable when Calculation Method 1 is used.
6. Calculation Method 3 for Atmospheric Storage Tanks
The EPA is finalizing amendments for Calculation Method 3
atmospheric storage tanks as proposed, consistent with section II.C. of
this preamble. The EPA received only minor comments regarding the
revisions to Calculation Method 3 for atmospheric storage tanks. See
the document Summary of Public Comments and Responses for 2024 Final
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems under the Greenhouse Gas Reporting Rule in Docket ID. No.
EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
The EPA is finalizing amendments to 40 CFR 98.233(j)(3) as proposed
to clarify that the separators, wells, or non-separator equipment for
which emissions are calculated should be those with annual average
daily hydrocarbon liquids throughput greater than 0 barrels per day and
less than 10 barrels per day (i.e., the count variable in equation W-
15A should not include separators, wells, or non-separator equipment
that had no throughput during the year). Similarly, we are also
finalizing amendments as proposed to clarify that the count of
separators, wells, or non-separator equipment to report under 40 CFR
98.236(j)(2)(ii)(E) should also be those with annual average daily
hydrocarbon liquids throughput greater than 0 barrels per day and less
than 10 barrels per day.
The EPA is also finalizing as proposed amendments to require
reporting of all Calculation Method 3 emissions that are vented
directly to atmosphere under 40 CFR 98.236(j)(2)(ii). These revisions
amend subpart W to no longer require separate reporting of Calculation
Method 3 emissions from atmospheric storage tanks that did not control
emissions with flares and those that controlled emissions with flares.
The EPA is finalizing as proposed amendments to 40 CFR
98.236(j)(2)(ii)(E) to request the total number of separators, wells,
or non-separator equipment used to calculate Calculation Method 3
storage tank emissions. This revision will completely align the
reporting requirement with the total ``Count'' input variable in
equation W-15A. We are also finalizing requirements to collect this
information at the well-pad site, gathering and boosting site, or
facility level. The EPA is also finalizing as proposed the removal of
the reporting requirement previously in 40 CFR 98.236(j)(2)(i)(F) that
required reporting of the number of
[[Page 42137]]
wells without gas-liquid separators in the basin.
L. Flared Transmission Storage Tank Vent Emissions
The EPA is finalizing the removal of source-specific calculation
and reporting of flared emissions from transmission storage tanks
(renamed ``condensate storage tanks'' as described in section III.C.1.
of this preamble). The EPA received only minor comments regarding the
revisions for condensate storage tanks. See the document Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems
under the Greenhouse Gas Reporting Rule in Docket ID. No. EPA-HQ-OAR-
2023-0234 for these comments and the EPA's responses.
As discussed in the proposal preamble, the EPA determined that
including flared emissions from condensate storage tank vents in the
group of ``other flared sources'' instead of continuing to report
source-specific flared emissions from transmission tanks will not
affect data quality or accuracy, nor will it significantly impact the
EPA's knowledge of the industry sector, emissions or trends. Therefore,
consistent with section II.C. of this preamble, the EPA is finalizing
as proposed the removal of both the current requirements in 40 CFR
98.233(k)(5) that require reporters to calculate flared tank vent stack
emissions from this source separately from all other flared emissions
at the facility and the current associated reporting requirements at 40
CFR 98.236(k)(3). Instead, the final amendments, as proposed, require
data for streams from condensate storage tanks to be included in the
calculation of total emissions from a flare according to 40 CFR
98.233(n)(1) through (9), and the flared condensate storage tank
emissions are classified with all ``other'' flared sources under the
flare disaggregation requirements at 40 CFR 98.233(n)(10). Similarly,
the EPA is finalizing as proposed the reporting of flared condensate
storage tank emissions as part of the total emissions from the flare in
40 CFR 98.236(n)(16) through (18) and as part of the disaggregated
``other flared sources'' emissions in 40 CFR 98.236(n)(19).
M. Associated Gas Venting and Flaring
1. Summary of Final Amendments
The EPA is finalizing changes to associated gas venting and flaring
largely as proposed. More specifically, we are finalizing changes to 40
CFR 98.233(m)(3) that require a reporter measuring the flow of natural
gas to a vent using a continuous flow measurement device to use the
measured flow volumes to calculate the volume of gas vented, consistent
with section II.B. of this preamble. If the reporter does not use a
continuous flow measurement device, the reporter must calculate
emissions from associated gas using equation W-18. As proposed, we are
finalizing clarifying language for the data input, volume of gas sent
to sales (SGp), when using equation W-18. The volume of gas sent to
sales includes gas used for other purposes at the facility site,
including powering engines, separators, safety systems and/or
combustion equipment and not flared or vented. The final rule, as
proposed, also clarifies that reporters using equation W-18 use the
volume of gas sent to sales and the volume of oil produced as inputs
into equation W-18 only during periods when associated gas is vented or
flared. These changes will improve the accuracy of data collected for
venting and flaring associated gas. The final rule also includes
changes from proposal to 40 CFR 98.233(m) to clarify, consistent with
the intent of the proposed rule, that the use of measured gas flow (in
lieu of equation W-18) is not optional if reporters use a continuous
flow measurement device. We are finalizing the corresponding reporting
requirements in 40 CFR 98.236(m)(7) to include, as proposed, a
requirement to indicate whether a continuous flow monitor was used to
measure flow rates and a continuous composition analyzer was used to
measure CH4 and CO2 concentrations. For vented
wells, we are also finalizing as proposed the requirement to report the
flow-weighted mole fractions of CH4 and CO2 and
the total volume of associated gas vented from the well, in standard
cubic feet for all wells whether using GOR or continuous flow
measurement devices.
Consistent with treatment of flaring emissions in other sources and
as proposed, the EPA is finalizing calculation of flared associated gas
emissions under 40 CFR 98.233(n), Flare Stacks, with some data elements
for flaring associated gas continuing to be reported under 40 CFR
98.236(m) and others under 40 CFR 98.236(n). However, as further
discussed in section III.N. of this preamble, under certain
circumstances, the final rule provisions allow reporters to use
equation W-18 to determine inputs to the 40 CFR 98.233(n) flared
associated gas emission calculations. More specifically, reporters
determine gas flow volumes routed to flares using continuous parameter
monitoring systems as specified in 40 CFR 98.233(n)(3)(i) and
98.233(n)(3)(ii)(A) and determine gas composition using continuous gas
composition analyzers or gas sampling as specified in 40 CFR
98.233(n)(4). If the reporter does not use continuous flow
measurements, the reporter must calculate natural gas emissions for
associated gas routed to the flare using the calculation methods in 40
CFR 98.233(m) as specified in 40 CFR 98.233(n)(3)(ii)(B).
We are also finalizing several reporting requirements from the
proposal in 40 CFR 98.236(m). The volume of oil produced and the volume
of gas sent to sales reported in 40 CFR 98.236(m)(5) and (6),
respectively, when using equation W-18 are limited to the volumes
produced and sent to sales during periods when associated gas is vented
or flared. Further, as proposed, 40 CFR 98.236(m)(6) is finalized to
clarify that the volume of gas sent to sales includes volumes of gas
used on-site during periods when associated gas is vented or flared.
Finally, we are finalizing the rule as proposed to specify that
reporters do not report equation W-18 inputs if they calculate
volumetric emissions from associated gas venting and flaring using a
continuous flow measurement device rather than using equation W-18.
These equation W-18 data elements include the GOR, the volume of oil
produced, and the volume of gas sent to sales for wells with associated
gas venting or flaring.
2. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to associated gas venting and flaring.
Comment: Commenters strongly supported the EPA's proposal to
require operators to measure the volume of associated gas sent to
flares using flare stack methodologies instead of a GOR contending that
use of GOR is problematic, because gas production varies by large
factors over time scales from minutes to years.
Response: The EPA acknowledges that GOR can and does change,
especially over longer time horizons. This is expected as oil and gas
production leads to changing reservoir properties resulting in changes
to production quantities and GORs. At production sites, GOR is often
determined through a well test where produced oil and gas are routed to
a test separator for a specified period of time. Oil and gas volumes
are metered off the separator to determine a value for GOR.
[[Page 42138]]
In finalizing today's rule, the EPA believes that direct
measurement provides values for gas flow and composition with the
highest degree of confidence. We are, therefore, finalizing the
calculation methods in 40 CFR 98.233(m) to require that reporters use
measured data in calculating and reporting emissions from associated
gas venting and flaring if gas flow rates are metered in addition to
the existing requirements, which are not changing with this action,
that gas composition be determined through use of continuous gas
composition analyzers if these are available. Although we proposed that
equation W-18 would only be allowed for calculating vented emissions,
we recognize based on public comment that measurement may not always be
possible due to operational practices, site health and safety
protocols, equipment failure, or for other reasons. As such, we are
finalizing the rule today allowing use of equation W-18 in instances
where direct measurement data are not available for either venting or
flaring of associated gas. It is essential that reporters have access
to an alternative methodology that supports accurate calculation of
emissions from associated gas venting and flaring. The final rule also
addresses two factors that may have impacted the accuracy and
verification of reported emissions in previous years when using
equation W-18. The EPA, as discussed elsewhere in this section, is
finalizing the rule to require reporting of associated gas emissions
and other data elements at the well level. Under the existing rule,
facilities are required to report one average GOR value across all
associated gas wells in the sub-basin. Although equation W-18 currently
requires the use of a well-specific GOR for each well when calculating
emissions, it is possible that some reporters may have used the average
GOR value when calculating emissions for each well rather than the
well-specific GOR. Well-level reporting with well-specific GOR will
allow the EPA to verify that associated gas emission calculations are
being performed correctly using well-specific GOR values, and we are
finalizing this requirement in this action. The final rule also
specifies that, as proposed, the volume of oil produced and the volume
of gas sent to sales are only calculated during the period when
associated gas is vented or flared.
Comment: The EPA received comments supporting use of continuous
flow measurement as an alternative to equation W-18 to calculate
emission from associated gas and venting, stating that flexibility is
key for many owners and operators and reflects the diversity in
resources available to an owner or operator and the location and nature
of its assets. One commenter noted that it may be challenging to
accurately measure extremely low volumes or variable volumes of gas.
Response: The EPA acknowledges the commenter's support for the
proposed calculation methods for associated gas venting but is
clarifying the intent. As stated in section III.M. of the preamble to
the 2023 Subpart W Proposal and specified in the proposed regulatory
text, was to require reporters to use the measured data if they used a
continuous measurement device. Specifically, the preamble to the
proposed rule stated, ``For associated gas venting emissions, we are
proposing provisions in 40 CFR 98.233(m)(3) to specify that if the
reporter measures the flow to a vent using a continuous flow
measurement device the reporter must use the measured flow volumes to
calculate the volume of gas vented rather than using equation W-18.''
(88 FR 50332; August 1, 2023). Further, the EPA proposed the following
regulatory text in 40 CFR 98.233(m)(3) establishing this requirement,
``Estimate venting emissions using equation W-18 of this section.
Alternatively, if you measure the flow to a vent using a continuous
flow measurement device, you must use the measured flow volumes to
calculate vented associated gas emissions.'' (88 FR 50397; August 1,
2023). Therefore, the proposal intended equation W-18 to only be
available to calculate vented associated gas emissions if the reporter
does not use a continuous measurement device. Although we believe the
intent was clear, given the ``if you . . . you must . . .'' language,
we are further clarifying the provision in the final rule such that it
does not use the term ``alternatively'' and additionally changing the
order of the wording to first state that a reporter using a continuous
flow measurement device must use the measured flow volumes to calculate
emissions, and then state if the reporter does not use a measured flow
measurement device, then equation W-18 must be used.
Regarding the comments requesting flexibility with emphasis on
measurement of low flows and variability of flow, the EPA acknowledges
that gas flow rates during production can be variable. We disagree,
though, that it will be challenging to measure gas flow at low flow
rates. Flow meters used at production sites are capable of measuring
very low flow rates, even to less than 1,000 cubic feet per day
depending on pipe diameter. We agree, however, that variability in flow
can present a challenge to operators when measuring gas flow rates
using orifice meters. Flow rates that exceed the flow capacity of an
orifice cross section will necessitate change out of the orifice plate.
This can be challenging in cases with highly variable flow over short
periods of time due to the labor, time and equipment required to
replace the orifice plate at high frequency. Reporters anticipating or
experiencing high variability in flow may consider using flow meters
that are designed to manage the variability. If this is not possible or
reporters do not elect to do so, reporters may use equation W-18 to
calculate emissions from associated gas venting and flaring.
Comment: Most commenters supported not requiring the submission of
equation W-18 inputs if the equation is not used to calculate emissions
from venting associated gas. However, one commenter suggested that it
should be clearer that if equation W-18 is used, then reporters must
report those data elements.
Response: The EPA acknowledges the support for the proposed rule.
While the EPA agrees that under the final rule reporters do not report
equation W-18 inputs if they calculate volumetric emissions from
associated gas venting and flaring using a continuous flow measurement
device rather than using equation W-18, the EPA disagrees that further
clarification of the rule language is needed. The EPA is finalizing 40
CFR 98.236(m)(4) through (6) as proposed, which requires that each data
element be reported unless the reporter did not use equation W-18 to
calculate associated gas venting or flaring emissions.
Comment: A reporter sought clarification if the EPA is asking for
reporters to measure the amount of gas vented when bleeding pressure
off a well, stating that this would not be practical as it would
require many operational units to add flow measurement devices for many
day-to-day operations that scarcely ever vent, possibly only a couple
times a year. The commenter further noted that this would require every
pulling unit in the basin to add a flow meter, and composition
analyzer. They would be required to record and track this data daily
and report to the operator.
Response: The primary purpose in bleeding pressure off a well is to
allow for safe work on the well. Natural gas that is bled off an oil
well is considered associated gas because the natural gas being vented
is associated with oil production. Although the EPA recognizes these
are often short duration events, often just a few minutes, a bleed
[[Page 42139]]
off produces GHG emission at a well site if the gas is vented or
flared. Multiple well bleeding events at a well site could result in
sizeable emissions depending on the duration of the events. Generally,
vented emissions from well bleed offs at oil wells should be included
in reported associated gas emissions for the well. However, there may
be instances where emissions from bleeding a well are reported under a
different source, most likely completions and workovers without
hydraulic fracturing. For example, the commenter references pulling
units. Pulling units are often used at production pads to perform well
workovers. If so, emissions associated with bleeding the well are
considered to be from the workover. Emissions for this event would be
calculated and reported under the Completions and Workovers without
Hydraulic Fracturing source using the calculation methods in 40 CFR
98.233(h) and 98.236(h). Regardless, the EPA emphasizes that the final
rule does not require reporters venting associated gas to place a flow
meter on a vent line from the well as suggested by the commenter. As
proposed, the EPA is finalizing the calculation methods for associated
gas venting and flaring to require use of measured data when reporters
measure the gas flow rate. If flow rates are not measured, reporters
can use equation W-18 to calculate emissions from associated gas
venting, including well bleeding events.
N. Flare Stack Emissions
Flare stacks are an emission source type subject to emissions
reporting by facilities in seven of the ten industry segments in the
Petroleum and Natural Gas Systems source category.\52\
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\52\ Flare stacks are an emission source type currently subject
to emissions reporting by facilities in the following industry
segments: Onshore Petroleum and Natural Gas Production, Onshore
Petroleum and Natural Gas Gathering and Boosting, Onshore Natural
Gas Processing, Onshore Natural Gas Transmission Compression,
Underground Natural Gas Storage, LNG Import and Export Equipment,
and LNG Storage.
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The EPA is finalizing changes to the flared emissions calculation
methodologies and the flare data reporting requirements for both the
flared emissions from each source type and for each flare with
modifications from the proposed amendments, as discussed in the
following sections. The final changes will align the flared emissions
calculation methodology and reporting with the directives in CAA
section 136(h) that reported emissions be based on empirical data and
accurately reflect the total CH4 emissions from each
facility, consistent with section II.B. of this preamble. We are also
finalizing changes to clarify specific provisions.
1. Calculation Methodology for Total Emissions From a Flare
a. Summary of Final Amendments
The EPA is finalizing several revisions to the flare emission
calculation methods to improve the quality and accuracy of the
calculated and reported data. Additionally, after consideration of
public comments, the final requirements include several revisions from
the proposal as well as some minor clarifications and other
enhancements.
First, we are finalizing several revisions to requirements for
determining both the destruction efficiency and the combustion
efficiency to use in calculating emissions from flares. The current
rule and the proposal both specify only combustion efficiencies.
However, after consideration of comments and consistent with section
II.B. of this preamble, we are finalizing requirements to use
destruction efficiencies for calculating CH4 emissions and
to use combustion efficiencies for calculating CO2
emissions. Consistent with previous EPA determinations \53\ and
regulations such as the National Emission Standards for Hazardous Air
Pollutants From Petroleum Refineries (40 CFR part 63, subpart CC)
(hereafter referred to as ``NESHAP CC''), the final amendments specify
that combustion efficiency is 1.5 percent lower than the destruction
efficiency (e.g., if the destruction efficiency is 95 percent, then the
corresponding combustion efficiency is 93.5 percent). Consistent with
CAA section 136(h), we are finalizing as proposed a tiered approach to
setting a range of default efficiencies that provide higher defaults
when supported by data from the reporter implementing certain flare
monitoring procedures, in 40 CFR 98.233(n)(1). As noted by commenters,
the default efficiency values in the proposal were incorrectly
identified as combustion efficiencies; the final rule retains the
default values and correctly identifies them as destruction
efficiencies. In addition, the final amendments add corresponding
default combustion efficiencies that are 1.5 percent lower than the
default destruction efficiencies, which will result in more accurate
estimates of CO2 emissions. Specifically, the final default
destruction efficiency and combustion efficiency are 98 percent and
96.5 percent, respectively, for Tier 1, 95 percent and 93.5 percent,
respectively, for Tier 2, and 92 percent and 90.5 percent,
respectively, for Tier 3. We are finalizing as proposed that the
default Tier 1 efficiencies are appropriate and allowed where the
reporter follows specified procedures in NESHAP CC to ensure such
efficiencies are accurate.
---------------------------------------------------------------------------
\53\ See Parameters for Properly Designed and Operated Flares,
USEPA Office of Air Quality Planning and Standards. April 2012.
Available at https://www3.epa.gov/airtoxics/flare/2012flaretechreport.pdf and in the docket for this rulemaking,
Docket ID. No. EPA-HQ-OAR-2023-0234.
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Note that the definitions of flare in subpart W and in NESHAP CC
are not the same. In subpart W, a flare is defined as ``a combustion
device, whether at ground level or elevated, that uses an open or
closed flame to combust waste gases without energy recovery.'' In
NESHAP CC, the flare definition does not include combustion devices
with an enclosed combustion chamber (i.e., a closed flame). Thus, the
requirements in NESHAP CC are different for ``enclosed combustion
devices'' and for ``open'' flares. The final subpart W Tier 1
requirements recognize this difference in the NESHAP CC combustion
device requirements. Specifically, for enclosed combustion devices that
are utilizing the Tier 1 efficiencies, subpart W requires that the
applicable testing procedures specified in 40 CFR 63.645 are followed,
as well as the applicable monitoring procedures in 40 CFR 63.644. For
combustion devices that use an open flame, the applicable requirements
specified in 40 CFR 63.670 and 40 CFR 63.671 of NESHAP CC must be
followed. In addition, for either enclosed combustors or open flares,
subpart W Tier 1 requires that the applicable records in 40 CFR 63.655
are maintained to demonstrate that the NESHAP CC testing and monitoring
requirements are being followed. While subpart W cross-references the
NESHAP CC requirements, sources utilizing Tier 1 are not affected
sources that are subject to NESHAP CC.
The proposed rule did not specify how to address situations where
an owner or operator is utilizing the Tier 1 default efficiency but
fails to meet the testing and monitoring requirements (cross-
referencing certain requirements in NESHAP CC). Examples of ``failing
to meet the testing and monitoring requirements'' would include, but
not be limited to, instances where monitoring data was not collected
for 75 percent of the operating hours in a day, instances where the
monitoring parameters were outside of the established parameter ranges,
and instances where the required visible emissions testing was not
performed. Similarly, during periods when the applicable 40 CFR 63.644,
63.645,
[[Page 42140]]
63.670 and 63.671 requirements are not being met, it generally would
not be appropriate to continue to assume 98 percent destruction
efficiency (and 96.5 percent combustion efficiency). The EPA considered
requiring that the Tier 3 default efficiencies be applied any time
these requirements are not being met. However, the EPA recognizes that
there could be short-term episodes where one or more of the required
parameters are not being met, and such an immediate requirement would
require frequent oscillations between applying the Tier 1 and Tier 3
default efficiencies. The EPA concluded that this would be difficult to
implement and would likely be burdensome for owners and operators. The
EPA evaluated durations that would be appropriate to require switching
to the Tier 3 default to ensure accuracy of total emissions reported.
While NESHAP CC specifies a 45-day timeframe for allowing owners and
operators to correct various types of problems, for subpart W
regulations the purpose of the requirements is ensuring accurate total
emissions reporting through the appropriate use of the different tiers
of default destruction/combustion efficiencies. Therefore, for the
final rule, the EPA selected a 15-day time frame such that, if one or
more of the specific NESHAP CC testing and monitoring requirements that
apply in the Tier 1 requirements are not met for 15 consecutive days,
the owner or operator must apply the Tier 3 default efficiency from the
time the requirement was initially not met (i.e., at the beginning of
the 15 days) until such time that all requirements are being met once
again. At that time, the Tier 1 default efficiencies could be applied
going forward. The concept of applying different flare efficiencies
based on operating conditions is similar to adjusting the flare
emissions to account for periods when the flare is unlit and thus,
appropriately accounting for times when the flare is not achieving any
emission reduction (i.e., zero combustion efficiency). We expect that
the 15-day grace period will have a minimal impact on overall reported
emissions because we expect most periods when a reporter fails to meet
the testing and monitoring requirements will be short. The 15-day grace
period is intended to capture significant periods when the testing and
monitoring requirements are not met (i.e., a 15-day grace period for a
continuously operated flare would be 4.1 percent of the total operating
hours).
Similarly, we are finalizing as proposed that the default Tier 2
efficiencies are appropriate and allowed if the reporter follows the
requirements that ensure such efficiencies are accurate, and that such
requirements under subpart W are consistent with the procedures
specified in NSPS OOOOb corresponding to a 95 percent destruction
efficiency (as cross-referenced in the subpart W final regulations). As
discussed above, the final rule also includes the default combustion
efficiency of 93.5 percent. Owners and operators of sources that are
subject to NSPS OOOOb can utilize the Tier 2 efficiencies by complying
with the requirements. In addition, owners and operators that are not
subject to NSPS OOOOb can elect to follow the cross-referenced
requirements. Note that, as discussed above for NESHAP CC, voluntarily
following the NSPS OOOOb requirements in order to claim the subpart W
Tier 2 default efficiencies will not make the sources affected
facilities under NSPS OOOOb. While the proposed Tier 2 requirements
cross-referenced only the specific section in proposed NSPS OOOOb that
contained the monitoring requirements contained in 40 CFR 60.5417b, the
final rule includes additional requirements from those proposed,
through a more comprehensive cross-reference incorporation of relevant
requirements in NSPS OOOOb. As with NESHAP CC, the definition of flare
in NSPS OOOOb does not include enclosed combustors and there are
separate requirements for enclosed combustors and open flares. NSPS
OOOOb requires that enclosed combustors be tested to demonstrate 95
percent destruction efficiency, but includes the option for owners and
operators to use combustors initially tested by the manufacturer
(rather than to perform the initial test on-site). The final subpart W
recognizes the different NSPS OOOOb requirements for these three types
of combustion devices and includes cross-references accordingly.
Specifically, for enclosed combustion devices tested on-site, the
requirements in 40 CFR 60.5412b(a)(1) are cross-referenced, along with
testing requirements in 40 CFR 60.5413b, and the continuous compliance
and continuous monitoring requirements in 40 CFR 60.5415b(f) and
60.5417b, respectively. For enclosed combustion devices tested by the
manufacturer in accordance with 40 CFR 60.5413b(d), the final subpart W
Tier 2 requires that the NSPS OOOOb requirements in 40 CFR
60.5413b(b)(5)(iii) and (e) and the applicable continuous compliance
and continuous monitoring requirements in 40 CFR 60.5415b(f) and 40 CFR
60.5417b, respectively, are met. Finally, for open flares, the final
rule requires that the NSPS OOOOb requirements in 40 CFR 60.5412b(a)(3)
be followed, along with the applicable continuous compliance and
continuous monitoring requirements in 40 CFR 60.5415b(f) and 40 CFR
60.5417b, respectively. For all three types, the final rule requires
that the applicable records required by 40 CFR 60.5420b(c)(11) be
maintained to demonstrate that the testing, monitoring procedures are
being followed.
The EPA recognizes that many oil and gas sources that are not
subject to NSPS OOOOb will be subject to an approved state plan or
applicable Federal plan in 40 CFR part 62 that includes similar
requirements to NSPS OOOOb to ensure that flare/combustion device
destruction efficiency of 95 percent is met. For such sources,
compliance with such an approved state plan or applicable Federal plan
in 40 CFR part 62 allows the use of the Tier 2 efficiencies, provided
that the requirement is a 95 percent reduction in methane emissions.
As with Tier 1, if owners and operators fail to meet one or more of
the Tier 2 requirements for 15 consecutive days, the Tier 3 default
efficiencies must be used until such time that all requirements are
again met. Examples of failing to meet the Tier 2 requirements include,
but are not limited to, when the average value of a monitoring
parameter is above the maximum, or below the minimum, operating
parameter, when monitoring data are not available for at least 75
percent of the hours in an operating day, when the visible emission
testing results in visible emissions in excess of 1 minute in any 15
minute period.
Note that sources that are subject to either NSPS OOOOb or an
approved state plan or applicable Federal plan in 40 CFR part 62 are
allowed to voluntarily ``step up'' to Tier 1 and thus use the 98
percent destruction efficiency and 96.5 percent combustion efficiency
default values.
We are also finalizing as proposed that Tier 3 applies if neither
Tier 1 nor Tier 2 requirements are met. Additionally, the final Tier 3,
as proposed, would apply before the flare owner or operator has
implemented the relevant monitoring that would be required to comply
with NESHAP CC, NSPS OOOOb or an approved state plan or applicable
Federal plan in 40 CFR part 62.
After consideration of public comments and consistent with section
II.B. of this preamble, we are also finalizing several additional
changes from the proposed flare efficiency
[[Page 42141]]
requirements. One of the new final provisions is an option that allows
reporters to use destruction and combustion efficiencies different than
the default values when they elect to use an alternative test method
that has been approved under 40 CFR 60.5412b(d) of NSPS OOOOb. The
alternative test method must directly measure combustion efficiency,
and the procedures in 40 CFR 60.5415b(f)(1)(x) and (xi) and 40 CFR
60.5417b(i) must be met, as well as all conditions in the monitoring
plan prepared in accordance with 40 CFR 60.5417b(i)(2).
The final amendments also include a new option that applies to
enclosed combustion devices (a subset of flares in subpart W).
Specifically, as an alternative to conducting a performance test
following the procedures in NSPS OOOOb, the final amendments to this
subpart allow a reporter to conduct a performance test using EPA Other
Test Method 52 (OTM-52, Method for Determination of Combustion
Efficiency from Enclosed Combustors Located at Oil and Gas Production
Facilities, dated September 26, 2023, for enclosed combustion devices
that are not required to comply with NSPS OOOOb or an approved state
plan or applicable Federal plan in 40 CFR part 62. This method
determines combustion efficiency, whereas the test method specified in
NSPS OOOOb determines destruction efficiency. Thus, the final
amendments specify that when an OTM-52 test results in a combustion
efficiency greater than 93.5 percent, then the reporter may use the
default destruction and combustion efficiencies of Tier 2.
Second, for all flares, regardless of the tier discussed previously
in this section, we are finalizing requirements, mostly as proposed, to
determine the presence of a pilot flame or combustion flame. The final
amendments, like the proposed amendments, require either continuous
monitoring (40 CFR 98.233(n)(2)(i)) or visual inspection at least once
per month (40 CFR 98.233(n)(2)(ii)) for the presence of pilot flame or
combustion flame. However, the final amendments include a statement
specifying that the visual inspection option is allowed only when the
facility complies with the Tier 3 efficiency or an approved alternative
test method that does not include continuous monitoring for the
presence of a flame. This statement does not change the intent of the
pilot monitoring requirements since proposal. We added this statement
to clarify that facilities subject to or electing to comply with the
Tier 1 or Tier 2 efficiencies must comply with the continuous
monitoring for the presence of a pilot flame or combustion flame as
specified in the cross-referenced NESHAP CC or NSPS OOOOb,
respectively, as proposed. After consideration of public comment, the
following new requirements are also included in the final amendments.
The final amendments include an option to use either video surveillance
or advanced remote monitoring methods as examples of acceptable
continuous monitoring devices that may be used. The final amendments
also explicitly allow multiple or redundant monitoring devices and
require either a visual inspection of the flame or a check of output
from a video surveillance system whenever there is a discrepancy
between the monitoring devices to assess which monitoring device is
providing inaccurate readings. We are finalizing as proposed the
requirement that continuous monitoring devices must monitor for the
presence of a pilot flame or combustion flame at least once every 5
minutes. We are also including an additional provision in the final
amendments (40 CFR 98.233(n)(2)(iii)) to clarify that any screening
conducted using an alternative technology under NSPS OOOOb that detects
an unlit flare and is confirmed by a ground survey constitutes a pilot
flame inspection under subpart W, and the results of such surveys,
together with all other monitoring and inspections that determine the
flare is unlit, must be used to calculate both the time the flare was
unlit during the year and the fraction of total gas routed to the flare
during periods when it was unlit.
Third, we proposed a requirement to use a continuous parameter
monitoring system to determine either total flow volume at the inlet to
the flare or the volumes for each stream from individual sources that
is routed to the flare. Use of a continuous parameter monitoring system
would require flow determination based on direct measurement using a
flow meter if one is present or indirect calculation of flow using
other parameter monitoring systems combined with engineering
calculations, such as line pressure, line size, and burner nozzle
dimensions. After consideration of public comments, we are not
finalizing this proposed requirement and are instead finalizing
requirements that are comparable to requirements for determining flow
in the current rule. Currently, under 40 CFR 98.233(n)(1), if a
continuous flow measurement device is used on part or all of the gas
routed to the flare, then the measurement data must be used in the
calculation of emissions from the flare. For the portion of gas not
measured by a continuous flow measurement device, the reporter
currently may estimate the flow using engineering calculations based on
process knowledge, company records, and best available data. To
calculate flared emissions from individual source types, the current
rule specifies that flow from the source to the flare be determined
using simulations (for dehydrators and storage tanks) or any of the
engineering calculation options that are used to calculate flow of
vented emissions. Our intent is that methods in the final amendments
for determining flow align with the current requirements, except for
the four following additional options and clarifications. First, 40 CFR
98.233(n)(3)(i) in the final amendments provides a new option for
indirectly calculating total flow into the flare based on parameter
monitoring systems combined with engineering calculations, such as line
pressure, line size, and burner nozzle dimensions. This option is
specified in NSPS OOOOb for determining flow into a flare; we have
added it to the subpart W final amendments so that a reporter that uses
this method to comply with NSPS OOOOb can calculate emissions under
subpart W using the same data. Second, for clarity, all of the
requirements for determining flow of streams from individual sources
are either consolidated in, or cross-referenced from, 40 CFR
98.233(n)(3)(ii) rather than being dispersed throughout other sections
of the rule. Third, new options are provided in 40 CFR
98.233(n)(3)(ii)(B)(1) to use either process simulation or engineering
calculations that are specified in 40 CFR 98.233(d) for calculating
flow of vented gas streams from acid gas removal units. These options
were added so that a facility may use the same procedures for
determining flow of streams routed to flares that are also specified
for determining flow of vented streams from the same source types.
Fourth, since some of the source-specific engineering calculation
methods for calculating vented emissions calculate only the volume of
GHG constituents in the gas stream, 40 CFR 98.233(n)(3)(ii)(B)(8)
requires reporters to calculate the flow of non-GHG constituents in
those streams using engineering calculations based on best available
data and company records. This was not necessary in the proposed
revisions since they required measurement of the total flare gas, which
would include both GHG and non-GHG constituents. Finally, while
reviewing a comment that recommended adding recordkeeping
[[Page 42142]]
requirements, we realized that the proposed rule did not clearly convey
our intent that the term ``flow of gas from each source that routes gas
to the flare'' in proposed 40 CFR 98.233(n)(1)(ii) should include only
the flow that actually enters the flare. In the final rule, 40 CFR
98.233(n)(3)(ii) specifies that closed vent system leaks and bypass
volumes that are diverted from the flare should be excluded from the
calculated and reported volume of gas routed to the flare and that that
the closed vent system leaks and bypass volumes that are diverted
directly to atmosphere must be used in the calculation and reporting of
vented emissions from the applicable sources. See the comment and
response on recordkeeping requirements in section III.N.1.b. of this
preamble for a discussion of the applicable recordkeeping requirements
under the final rule and a discussion of the requirements for closed
vent system leaks and bypass volumes.
Fourth, we proposed a requirement that composition of either the
total gas stream at the inlet to the flare or for each of the streams
from individual sources that are routed to the flare be calculated
using either a continuous gas composition analyzer or by collecting
samples for compositional analysis at least once each quarter in which
the flare operated. After consideration of public comments, we are not
finalizing this proposed requirement and are instead finalizing
requirements that are comparable to requirements for calculating
composition in the current rule. For example, the final rule specifies
that if a reporter is using a continuous gas composition analyzer on
gas to the flare, then the measured data must be used in the
calculation of emissions from the flare, which is consistent with 40
CFR 98.233(n)(2) of the current rule. The final rule specifies that if
a continuous gas composition analyzer is not used on the total inlet
stream to the flare, then typically, a reporter must determine
composition of each stream routed to the flare using an option as
specified in 40 CFR 98.233(u)(2), which is also consistent with the
current rule. The final rule specifies that for hydrocarbon product
streams routed to a flare, a reporter may use a representative
composition based on process knowledge and best available data, as
specified in 40 CFR 98.233(n)(2)(iii) of the current rule. The final
rule specifies procedures for determining composition of emission
streams from sources at onshore natural gas processing facilities that
are consistent with the 40 CFR 98.233(n)(2)(ii) of the current rule,
except that samples must be collected at least annually. According to
40 CFR 98.233(u)(2)(i) and (ii) of both the current and final rule, if
a continuous gas composition analyzer is used at an onshore petroleum
and natural gas production facility or an onshore petroleum and natural
gas gathering and boosting facility, then annual average GHG mole
fractions developed from the measurement data must be used in flared
emissions calculations. Other options for determining GHG composition
in current 40 CFR 98.233(u)(2) include using results of sample
analysis, use of default values, or use of site-specific values based
on engineering estimates, depending on the industry segment. Another
current option for determining composition of streams routed to flares
from dehydrators and storage tanks is to use the results of process
simulations as specified in current 40 CFR 98.233(e)(6) and (j)(5). Our
intent is that methods in the final amendments for determining gas
composition align with the current requirements, except for the five
following additional options and requirements. First, 40 CFR
98.233(n)(4)(ii) in the final amendments provides a new option for
determining composition of the combined total stream to a flare based
on annual sampling and analysis as an alternative when a continuous gas
analyzer is not used on the total stream to the flare. Second, for
clarity, all of the requirements for determining composition of streams
from individual sources are consolidated in 40 CFR 98.233(n)(4)(iii)
rather than being dispersed throughout other sections of the rule.
Third, new source-specific options are provided in 40 CFR
98.233(n)(4)(iii)(B)(1) to use either process simulation or quarterly
sampling and analysis to determine composition of gas streams routed to
a flare from acid gas removal units. Fourth, since 40 CFR 98.233(u)(2)
requires determination of only the GHG composition, 40 CFR
98.233(n)(4)(iii)(B)(7) specifies that composition of ethane, propane,
butane, and pentanes plus (for use in equation W-20 to calculate flared
CO2 emissions) must be determined using a representative
composition based on process knowledge and best available data. Fifth,
when determining composition based on analysis of grab samples in
accordance with 40 CFR 98.233(u)(2)(i), the final amendments (40 CFR
98.233(n)(4)(iii)) require that the samples must be collected and
analyzed annually, rather than the current requirement in 40 CFR
98.233(u)(2)(i) to use ``your most recent available analysis.'' This
change aligns the sampling frequency of individual streams with the
sampling frequency specified in the final sampling option for the inlet
stream to the flare as discussed previously and is expected to improve
data quality and the accuracy of total reported emissions by
eliminating the use of outdated data.
Fifth, for clarity, we are finalizing as proposed additional
requirements in 40 CFR 98.233(n)(5) to specify how flow and composition
data must be used to calculate total emissions depending on different
scenarios a reporter could use to determine the flow and gas
composition. The final 40 CFR 98.233(n)(5)(i) specifies that if both
flow and gas composition are determined for the inlet gas to the flare,
then these data are to be used in a single application of equations W-
19 and W-20 to calculate the total emissions from the flare. If the
flow and gas composition are determined for each of the streams that
are routed to the flare, then one of the final options in 40 CFR
98.233(n)(5)(iii) requires the reporter to use each set of stream-
specific flow and annual average concentration data in equations W-19
and W-20 to calculate stream-specific flared emissions for each stream,
and then sum the results from each stream-specific calculation to
calculate the total emissions from the flare. Alternatively, 40 CFR
98.233(n)(5)(iii) allows reporters to sum the flows from each source to
calculate the total gas flow into the flare and use the source-specific
flows and source-specific annual average concentrations to determine
flow-weighted annual average concentrations of CO2 and
hydrocarbon constituents in the combined gas stream into the flare. The
calculated total gas flow and the calculated flow-weighted annual
average concentrations would then be used in a single application of
both equation W-19 and W-20 to calculate the total emissions from the
flare. If flow is determined for all of the individual source streams
while gas composition is determined for the combined stream into the
flare, then 40 CFR 98.233(n)(5)(ii) requires the reporter to sum the
individual source flows to calculate the total flow into the flare.
This summed volume and the gas composition determined for the combined
stream into the flare would be used in a single application of
equations W-19 and W-20 to calculate the total emissions from the
flare. Finally, 40 CFR 98.233(n)(5)(iv) specifies that a reporter may
not calculate flared emissions based on the determination of
[[Page 42143]]
the total volume at the inlet to the flare and gas composition for each
of the individual streams routed to the flare. This combination of
volume and gas composition determinations is not allowed because there
is no way to calculate flow-weighted average compositions of either the
inlet gas to the flare or the individual source streams.
Sixth, we are finalizing as proposed to delete the option to use a
default higher heating value (HHV) in the calculation of N2O
emissions and instead require all reporters to use either a flare-
specific HHV or individual flared gas stream-specific HHVs in the
calculation. In the existing rule, 40 CFR 98.233(n)(7) requires the use
of equation W-40 to calculate N2O emissions from flares.
This equation requires the flared gas volume, the HHV of the flared
gas, and the use of a default emission factor. For field gas or process
vent gas, the variable definition for the HHV provides that either a
site-specific or default value may be used; for other gas streams, a
site-specific HHV must be used. We are finalizing as proposed in 40 CFR
98.233(n)(8) to require the use of a flare-specific HHV when
composition of the inlet gas to the flare is measured or when flow-
weighted concentrations of the inlet gas are calculated from measured
flow and composition of each of the streams routed to the flare.
Similarly, final amendments require reporters to calculate
N2O emissions using flared gas stream-specific HHVs when
flow and composition are determined for each of the individual streams
that are routed to the flare and emissions are calculated per stream
and summed to calculate total emissions from the flare. A change from
the proposal is that the final rule also allows the direct measurement
of the HHV as an alternative to calculation of the HHV from the
composition information. This measurement can be conducted at the inlet
to the flare or measurements may be made for each stream and be used in
conjunction with the flow estimates for each stream to calculate a
weighted annual average HHV. We also finalized as proposed a new
requirement in 40 CFR 98.236(n)(9) to report the HHV(s) used to
calculate N2O emissions. This data element will improve
verification of reported N2O emissions and minimize the
amount of communication with reporters via e-GGRT. It also will be
useful for characterizing the differences in flared gas streams among
the various industry segments and basins, and it is expected to be
useful in analyses such as updates to the U.S. GHG Inventory.
Seventh, we are finalizing as proposed the changes to the emission
calculation requirements for flares that use CEMS because the existing
methodology to calculate total GHG emissions when using CEMS is
inconsistent with CAA section 136(h) as described in section II.B. of
this preamble. Currently, if a reporter operates and maintains a CEMS
to monitor emissions from a flare, existing 40 CFR 98.233(n)(8)
requires the reporter to calculate only CO2 emissions from
the flare. The final amendments revise existing 40 CFR 98.233(n)(8)
(final 40 CFR 98.233(n)(9)) to require reporters to comply with all of
the other emission calculation procedures as proposed in 40 CFR
98.233(n), with one exception. The exception is that since
CO2 emissions are measured with the CEMS, calculation of
CO2 emissions using equation W-20 is not required. We expect
that these final amendments will address a potential gap in
CH4 emissions reporting and improve the overall quality and
completeness of the emissions data collected by the GHGRP, consistent
with section II.A. of this preamble.
Eighth, we are finalizing with revisions both the removal of the
current source-specific methodologies for calculating flared emissions
(i.e., existing 40 CFR 98.233(e)(6) for dehydrators, existing 40 CFR
98.233(g)(4) for completions with hydraulic fracturing, existing 40 CFR
98.233(h)(2) for completions without hydraulic fracturing, existing 40
CFR 98.233(j)(5) for tanks, existing 40 CFR (l)(6) for well testing,
and existing 40 CFR 98.233(m)(5) for associated gas) and the addition
of a requirement that the reporter use engineering calculations and
best available data to disaggregate the calculated total emissions per
flare to the source types that routed gas to the flare (40 CFR
98.233(n)(10)). The final amendments require disaggregated emissions to
be calculated using engineering calculations and best available data as
was proposed; however, the revisions include a requirement that if
stream-specific flow and composition for a single source type is used
to calculate flared emissions then the source-specific emissions
calculated using this data must be used to calculate the disaggregated
emissions per source type. Disaggregating the total emissions per flare
to the applicable source types that route emissions to the flare will
eliminate the disconnect between the sum of source-specific flared
emissions versus the total emissions per flare that has occurred under
the current approach. This will improve the overall quality and
accuracy of total reported emissions from the flare stacks source type,
while maintaining acceptable accuracy of estimated flared emissions per
source type for use in assessing trends in control over time, policy
determinations carrying out provisions under the CAA, and in U.S. GHG
Inventory development.
Finally, we are finalizing as proposed the removal of existing 40
CFR 98.233(n)(9). Since the final amendments eliminate the source-
specific flared emissions calculation methodologies, as discussed
above, the requirement in existing 40 CFR 98.233(n)(9) to subtract
source-specific flared emissions from the total emissions per flare is
not needed to avoid double reporting of flared emissions under the
final amendments.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to the calculation methodologies for emissions
from flare stacks.
Comment: Several commenters indicated that subpart W does not
properly distinguish between combustion efficiency (CE) and destruction
efficiency (DE) (also known as destruction and removal efficiency
[DRE]). One commenter asserted that methane emission calculations must
be based on destruction efficiency, not combustion efficiency, to
account for all methane oxidized whether to CO2 or CO. One
commenter stated that the accurate method to calculate and report
CH4 and CO2 emissions is to use DE in equation W-
19 to calculate CH4 emissions and to use CE in equation W-20
to calculate CO2 emissions. This commenter also noted that
using only CE in subpart W is inconsistent with other EPA flare
regulations such as 40 CFR 63.670(r). One commenter stated that the
definition of the CE term in equation W-19 is equivalent to DE in the
literature; according to the commenter, this inconsistency will lead to
confusion for subpart W reporters because those familiar with flares
calculate emissions from DE, not from CE. Another commenter asserted
that the EPA must understand the distinction between CE and DE when
evaluating studies and literature. Two commenters noted that the EPA
should define a relationship between CE and DE. One of these commenters
suggested that DE be 1.5 percent higher than CE, as in an EPA
publication (``Parameters for Properly Designed and Operated
[[Page 42144]]
Flares'') \54\ and in regulations. The other commenter summarized the
results of two studies that measured and compared CE and DE for
numerous flares.55 56 The commenter developed a correlation
between the CE and DE data and suggested that this correlation could be
used to calculate DE from measured CE or vice versa with high accuracy.
---------------------------------------------------------------------------
\54\ Id.
\55\ Allen, D. and Torres, V. TCEQ 2010 Flare Study Final
Report. The University of Texas at Austin. The Center for Energy and
Environmental Resources. Prepared for TCEQ. August 1, 2011.
Available at https://www.tceq.texas.gov/airquality/stationary-rules/stakeholder/flare_stakeholder.html and in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
\56\ Providence Photonics, LLC. Comments on Greenhouse Gas
Reporting Rule: Revisions and Confidentiality Determinations for
Petroleum and Natural Gas Systems. Data in Exhibit 1 (CBI).
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Response: The proposal used the term combustion efficiency because
that is the term used in the existing part 98 regulations. However, we
agree with the commenters that there is a difference between
destruction efficiency and combustion efficiency, and we agree that
destruction efficiency is the value that should be used to calculate
CH4 emissions and combustion efficiency is the correct value
to use to calculate CO2 emissions. Based on consideration of
these comments, we have corrected the efficiency terms in equations W-
19 and W-20 of the final amendments so that destruction efficiency is
used in equation W-19 to calculate CH4 emissions and
combustion efficiency is used in equation W-20 to calculate
CO2 emissions.
We also agree with commenters that the default combustion
efficiencies in the three proposed tiers (40 CFR 98.233(n)(4)(i)
through (iii) of the proposal) are actually destruction efficiencies,
and we agree that a relationship between combustion efficiency and
destruction efficiency should be included in the rule. We believe the
relationship in ``Parameters for Properly Designed and Operated
Flares'' (i.e., destruction efficiency is 1.5 percent higher than
destruction efficiency over the full range of destruction efficiencies)
is the most appropriate relationship at this time. This relationship
has a history of more than 10 years acceptance by the EPA, it is used
in other regulations such as NESHAP CC, and it is simple to implement.
However, we believe the correlation equation suggested by one commenter
shows promise for future consideration, especially since it appears the
difference between combustion efficiency and destruction efficiency
increases at lower destruction efficiencies. As discussed in the
response to the following comment in this section, we are finalizing
with some modifications from proposal the three tiers, and after
consideration of these comments and the EPA's reassessment of the terms
used in the proposal, we are specifying both default destruction
efficiencies that are consistent with the proposed combustion
efficiencies and default combustion efficiencies that are 1.5 percent
less than the default destruction efficiencies. These changes will
result in more accurate emissions calculation and reporting, though we
note that the calculated CO2 emissions will be slightly
lower under the final amendments relative to emissions calculated based
on the proposed methodology.
Comment: Numerous commenters strongly opposed the proposed
revisions that would require reporters to calculate emissions from
flares using only one of three default flare combustion efficiencies
that are correlated to the type of flare monitoring that they
conduct.\57\ The commenters primary objection was that the proposed
requirement to use only a default efficiency is that it does not allow
reporters to use higher efficiencies that can be demonstrated based on
empirical data. Commenters also asserted that reporters should not be
limited to the proposed defaults because flares generally achieve
destruction efficiencies of 98 percent when operating within the
parameters of 40 CFR 60.18 and studies have shown that many flares
achieve a destruction efficiency considerably higher than 98 percent.
One commenter stated that the 95 percent emission reduction required
under NSPS OOOOa and proposed under NSPS OOOOb and EG OOOOc was
designed to allow operators to use other control options beyond flare
combustion devices.
---------------------------------------------------------------------------
\57\ Although the proposal specified only combustion
efficiencies, some commenters referred to destruction efficiencies,
consistent with their comments that are described in the preceding
comment summary. In this comment summary we refer to destruction
efficiencies when that is the term that was used by commenters. We
use the term ``efficiency'' when some commenters referred to
combustion efficiency and others referred to destruction efficiency.
---------------------------------------------------------------------------
To address their objections, the commenters stated that the EPA
should either replace or modify the proposed tiered system of default
combustion efficiencies with various alternatives. A majority of the
commenters stated that the EPA should allow reporters to use
efficiencies based on manufacturer guarantees and/or to use
efficiencies in existing federal or state rules that also apply to the
flares. A few commenters stated that reporters should be allowed to use
efficiencies consistent with the efficiencies required in federal or
state operating permits or to use state-approved efficiencies for
specific flare models that have been tested by the flare manufacturer.
Some commenters stated that the EPA should allow the use of direct
measurement of efficiencies using existing or future advanced
technologies (e.g., simplified Video Imaging Spectro-Radiometry (VISR))
once the technology has been vetted by a regulatory agency. One
commenter stated that the EPA should allow the use of efficiencies
obtained based on direct measurement using advanced direct measurement
methods that the EPA has used for inspection and compliance purposes.
Two commenters stated that reporters should be allowed to use
efficiencies based on the results of parametric monitoring. One of
these commenters described an approach based on computational fluid
dynamics data from ultrasonic flow meters that is analyzed by an
artificial intelligence technique into a numerical model to calculate
combustion efficiency. One commenter stated that reporters should be
allowed to use efficiencies obtained from performance tests for vapor
combustors, enclosed flares, and thermal oxidizers. Another commenter
noted that the proposed Tier 2 did not cross-reference the NSPS OOOOb
provision that allows a facility to determine compliance with NSPS
OOOOb based on the results of manufacturer testing of enclosed
combustion devices. Another commenter stated that reporters should be
allowed to use (OTM-52) to determine destruction efficiency or
combustion efficiency of enclosed combustion devices. To prevent
inconsistent reporting between subpart W and other EPA programs, one
commenter stated that reporters should be allowed to use a default
destruction efficiency of 98 percent for flares that are designed and
operated according to 40 CFR 60.18, and that a 98 percent destruction
efficiency also should be allowed for other flares that are operated
within New Source Review permit compliance requirements.
Response: Based on consideration of the comments, the proposed
default combustion efficiencies (finalized as destruction efficiencies
as explained in the response to the preceding comment) are being
finalized as options with some changes from the proposal. An additional
option is being finalized (40 CFR 98.233(n)(1)(iv)) that allows for
improved alignment with the NSPS program whereby an owner or operator
can use an alternative test method that
[[Page 42145]]
has been submitted to and approved by the EPA under 40 CFR 60.8(b), as
outlined in 40 CFR 60.5412b(d) or 60.5412c(d) to demonstrate a greater
combustion efficiency based on empirical data and utilize the results
to calculate flared emissions under subpart W. The submitter must
demonstrate to the satisfaction of the EPA under 40 CFR 60.8(b) that
the alternative test method, when implemented as presented in the
request for approval, including all documented monitoring protocols,
continuously demonstrates compliance with a combustion efficiency of 95
percent or greater. Under NSPS OOOOb, or a state or Federal Plan in 40
CFR part 62 implementing EG OOOOc, a submitter may demonstrate
compliance either through continuous measurement of combustion
efficiency or through continuous measurement of the net heating value
of the combustion zone and the net heating value dilution parameter (if
the flare uses perimeter assist air). Note, however, that only
alternative test methods based on continuous measurement of combustion
efficiency will be allowed under subpart W because the purpose of
allowing the alternative test method is to enable reporters to identify
specific destruction and combustion efficiencies that differ from the
defaults; the option based on continuous measurement of the net heating
values does not result in a specific combustion efficiency. Likewise,
if the submitter is using the alternative test method to document
combustion efficiencies greater than 95 percent, they would need to
provide sufficient documentation for how this was determined and the
uncertainties associated with the measurement. When the EPA approves an
alternative test method, the approval may be site-specific or it may
become broadly applicable, approved for a class of flares such that
reporters for all flares meeting the requirements outlined in the
alternative test method may use the actual demonstrated combustion
efficiency (and an assumed destruction efficiency 1.5 percent higher
than the combustion efficiency) to calculate flared emissions under
subpart W, provided they also implement inspections and monitoring that
are part of the approved alternative test method. This alternative
provides owners and operators a pathway to gain approval to directly
measure efficiency using advanced measurement technology or other
methods that may be approved for a destruction efficiency higher than
default values specified under the three tiers. The alternative also
aligns the flare emissions calculation methodology with the directives
in CAA section 136(h) that reported emissions be based on empirical
data that accurately reflect the total emissions, consistent with
section II.B. of this preamble.
We agree with the commenter that pointed out the proposed Tier 2
requirements should include a cross-reference to the applicable section
in NSPS OOOOb that specifies performance test requirements for enclosed
combustion devices in NSPS OOOOb (i.e., a subset of the total flare
population under subpart W). This oversight has been corrected in 40
CFR 98.233(n)(1)(ii)(A) and 40 CFR 98.233(n)(1)(ii)(C) of the final
amendments by including cross-references to 40 CFR 60.5413b(b) and (d)
that require facilities to either conduct testing of enclosed
combustion devices themselves or have testing conducted by the enclosed
combustion device manufacturer. When the test demonstrates a
destruction efficiency of 95 percent or greater, and monitoring
parameter values, including those that must be established during the
test, are within the specified ranges, then the reporter may use the
Tier 2 default efficiencies.
We have also evaluated the suggestion by a commenter to allow the
use of OTM-52 as an alternative to the performance testing requirements
in NSPS OOOOb. OTM-52 is a draft method that is less costly and easier
to implement than the reference method in NSPS OOOOb. It is used to
determine combustion efficiency rather than destruction efficiency. It
has not been approved as an alternative to the test method in NSPS
OOOOb and thus, it may not be used to test an enclosed combustion
device that is subject to NSPS OOOOb. Similarly, it has not been
approved as an alternative to the test method in EG OOOOc and thus, may
not be used to test an enclosed combustion device that is subject to a
state or Federal Plan in 40 CFR part 62 implementing EG OOOOc. However,
for enclosed combustion devices that are not subject to NSPS OOOOb or
state or Federal Plans in 40 CFR part 62 implementing EG OOOOc that
require 95 percent reduction in methane emissions, we believe it
provides an acceptable level of accuracy for the purposes of
calculating emissions using the Tier 2 default efficiencies when a test
results in a combustion efficiency of 93.5 percent or greater.
Therefore, OTM-52 is included in 40 CFR 98.233(n)(1)(iv) of the final
amendments as an alternative to the Tier 2 performance testing
procedures for enclosed combustion devices that are not subject to NSPS
OOOOb or a state or Federal Plan in 40 CFR part 62 implementing EG
OOOOc.
We have not included other methods suggested by the commenters for
demonstrating flare efficiencies to use in calculating emissions under
subpart W (e.g., manufacturer guarantees, presumption that operation
according to 40 CFR 60.18 ensures 98 percent destruction efficiency,
parametric monitoring, state-approved efficiencies, or efficiencies in
permits) because we have determined that they do not provide a
reasonable assurance that the stated efficiency would be continuously
met or we do not have data available at this time needed to implement
such methods and to verify the results. Specifically, with respect to
the commenter's assertion that flares operated according to 40 CFR
60.18 should be allowed to use a 98 percent destruction efficiency, we
note that the General Provisions at 40 CFR 60.18 state that the
referencing subpart will specify the monitoring requirements and that
40 CFR 60.18 on its own does not ensure a properly operating flare. In
the supplemental proposal to NSPS OOOOb,\58\ we noted that recent
studies suggest that 10 percent of flares in the Permian basin are
either unlit or are only burning a portion of the gas sent to the flare
\59\ and that the current operating and monitoring practices and
requirements for well sites and centralized production facilities are
not adequate to ensure flare control systems are operated efficiently.
Therefore, under the final NSPS OOOOb provisions, we have finalized
compliance requirements to ensure all aspects of the General Provisions
at 40 CFR 60.18 are met at all times. These provisions are cross-
referenced in subpart W to provide assurance that a 95 percent
destruction efficiency is accurate for the flare. Flares that are not
operated properly cannot be reasonably assured to have the claimed
destruction efficiency. Without assurances that the flare is being
operated properly, it is our assessment that a destruction efficiency
associated with a properly functioning flare (i.e., 95 percent or
higher) would be inappropriate and not ensure accurate total emissions
reported. Similarly, with respect to the commenter's assertion that
destruction efficiencies be based on a manufacturer's guarantee, the
[[Page 42146]]
guarantees alone would not ensure that the flares are being operated
properly and that those destruction efficiencies accurately reflect
actual operation of the flare. We expect that a 95 percent destruction
efficiency will be a reasonably accurate average destruction efficiency
for a properly operated flare, considering that there will be periods
during which the flare is unlikely to meet a higher manufacturer
claimed destruction efficiency, due to operating conditions, e.g., high
cross-winds. Therefore, at this time, we have not included additional
alternative methods or destruction efficiencies. For additional
comments and response on alternatives to the proposed destruction
efficiencies, see section 15 of the Summary of Public Comments and
Responses for 2024 Final Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems under the Greenhouse Gas
Reporting Rule, available in the docket to this rulemaking (Docket ID.
No. EPA-HQ-OAR-2023-0234).
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\58\ See 87 FR 74793 (December 6, 2023).
\59\ Permian Methane Analysis Project (PermianMAP) reporting the
results of 4 Environmental Defense Fund (EDF) surveys of over a
thousand flare stacks from February to November 2020. See https://www.permianmap.org/flaring-emissions.
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Comment: Numerous commenters claimed that the proposed 92 percent
destruction efficiency \60\ for Tier 3 was too low because the value in
the cited study \61\ included unlit flares. According to the
commenters, since emissions from unlit flares would be calculated
separately under the proposal, including them in the Tier 3 destruction
efficiency would result in double counting of the emissions.
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\60\ The proposal incorrectly stated that the 92 percent
efficiency for Tier 3 was the combustion efficiency. As discussed in
the response to a preceding comment, the 92 percent should be the
destruction efficiency. In this comment summary we refer to the
efficiency as destruction efficiency to reflect the accurate
terminology.
\61\ Plant, G., et. al. 2022. ``Inefficient and unlit natural
gas flares both emit large quantities of methane.'' Science, 377
(6614). https://doi.org/10.1126/science.abq0385. Available in the
docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------
Response: Table 1 in the Plant et al. (2022) study reported both
observed flare DREs and total effective DREs for flares in three
basins. The total effective DREs are based on both the observed flare
DREs (from lit flares) plus the percentage of unlit flares obtained
from a separate study. However, the 92 percent destruction efficiency
for Tier 3 is based on the mean observed flare DRE for the Permian
basin rounded up from 91.7 percent to 92 percent; it is not based on
the reported overall average total effective DRE of 91.1 percent. Thus,
the final Tier 3 destruction efficiency of 92 percent does not double
count emissions for unlit flares.
We have determined that the average observed destruction efficiency
of 92 percent is a reasonable combustion efficiency for subpart W
sources that are not monitoring as specified under Tier 1 or Tier 2
because the overall average in the empirical results likely included
many facilities with higher performing flares that would likely comply
with one of those tiers and thus should be excluded from the
calculation of the average for Tier 3 flares. We agree that it is
important to allow for submission of empirical data, as appropriate;
therefore, as discussed in the previous response, we have added an
option to use that allows for improved alignment with the NSPS program
whereby an owner or operator can use an alternative test method that
has been submitted to and approved by the EPA under 40 CFR 60.8(b), as
outlined in and 40 CFR 60.5412b(d) or 60.5412c(d). The final default
destruction efficiencies and alternative option align with the
directives in CAA section 136(h) that reported emissions be based on
empirical data that accurately reflect the total emissions, consistent
with section II.B. of this preamble.
Comment: Commenters stated that the rule should allow monitoring of
the presence of a pilot flame using visual observation with a video
camera, and one commenter noted that this approach would more
efficiently utilize manpower and potentially result in more timely
discovery and correction of unlit or malfunctioning flares. Commenters
asserted that subpart W should allow the use of auto-ignitors instead
of requiring continuous pilots. They noted that states such as Texas
and New Mexico allow auto-ignitors, and they pointed out that use of
such devices eliminates the need for a continuous pilot, thereby
reducing the amount of pilot and sweep gas needed to operate the flare.
One commenter requested that the EPA allow the use of the VISR device
to monitor the presence of pilot flame.
Response: We agree that the use of video cameras and advanced
remote measurement options are viable means for detecting the presence
or absence of a pilot flame, and these options have been added in 40
CFR 98.233(2)(i) of the final amendments. We have not allowed the use
of auto-ignitors as an alternative to maintaining a continuous pilot
flame in the final amendments. In response to comments on NSPS OOOOb
requesting that auto-ignitors be allowed in that rule, we explained
that there is not sufficient data currently to suggest that electronic
ignition systems on combustion devices are capable of continuously
supplying a constant source of ignition adequate to keep a flame
present on a continuous basis. Our reply to comments on NSPS OOOOb also
indicated that the EPA does not have sufficient information on the
degradation of electronic ignition systems or how to ensure these
systems maintain functionality over time. Additionally, our reply noted
that operating a flare with a continuously lit pilot adds an additional
degree of flame stability to the flare itself, and we do not have
sufficient information on whether the sporadic lighting of the
combustion device tip would lead to flame instability, and by
extension, poor combustion.62 63 We maintain these same
views and assessments in this final rulemaking regarding this
commenter's suggestion for the subpart W regulations. Thus, auto-
ignitors are not allowed in subpart W due to the uncertainty regarding
the effect they may have on the destruction efficiency and combustion
efficiency of the flare.
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\62\ Oil and Natural Gas Sector: New Source Performance
Standards and National Emission Standards for Hazardous Air
Pollutants Reviews 40 CFR parts 60 and 63 Response to Public
Comments on Proposed Rule August 23, 2011 (76 FR 52738). P. 308. in
the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
\63\ EPA's Responses to Public Comments on the EPA's Oil and
Natural Gas Sector: Emission Standards for New, Reconstructed, and
Modified Sources May 2016. P. 11-190. in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------
Comment: One commenter recommended revising the pilot flame
monitoring requirements to allow the use of multiple or redundant
monitoring devices or inspection techniques. According to the
commenter, monitoring device malfunctions are not uncommon and an
operator should have the option to confirm whether a monitoring result
is errant and not include the time as unlit if other monitoring/
inspection information demonstrates the output of the device to be
incorrect.
Response: We note that the proposed amendments did not prohibit the
use of multiple pilot flame monitoring devices, but we agree with the
commenter that it would be appropriate to explicitly state in subpart W
that this is allowed. This provision has been added in 40 CFR
98.233(n)(2)(i)(B) of the final amendments. We also included a
requirement that when there is a discrepancy in the output of multiple
devices that the operator must either visually confirm or use video
surveillance output to confirm that the flame is present as soon as
practicable after detecting the discrepancy to ensure that at least one
device is operating properly. If at least one device is confirmed to be
operating properly, then the operator may continue to rely on the
[[Page 42147]]
properly operating device(s) for monitoring the pilot. By
``discrepancy'' we mean one or more devices indicate the flare is unlit
while one or more other devices indicate it is lit. We do not mean
cases in which two or more devices provide different output values, but
all values confirm the flare is lit. For example, two thermocouples
that register different temperatures, either of which confirms the
flare is lit, does not constitute a discrepancy for this purpose under
subpart W.
Comment: Commenters opposed the proposed requirement to measure
flow using flow meters or parameter monitoring systems combined with
engineering calculations. The most commonly stated objections were that
most flow meters are inaccurate on low-pressure streams and streams
with low or intermittent flow that are common in the upstream and
midstream industry segments, and the cost to install meters would be
excessive. Commenters also noted that many flares are located at sites
that lack electrical power, SCADA systems, WiFi and cellular coverage,
and field offices. One commenter noted that process simulation is
approved for determining flow to use in calculating vented emissions,
and it seems inconsistent to disallow the same methods for determining
flow to flares. One commenter asserted that field testing shows
parametric monitoring overestimates flow volumes, and one commenter
stated that it can be difficult to calibrate flow meters on variable
flow streams.
Instead of requiring continuous measurement of flow, most of the
commenters recommended retaining the current requirements that require
use of measurement data only when a continuous flow measurement device
is used to measure total or partial flow to the flare and to allow
engineering calculations based on process knowledge, company records,
and best available data when flow is not measured using a continuous
flow measurement device. A few commenters stated that process
simulation should be allowed, particularly for streams from dehydrators
and tanks. One commenter stated that engineering calculations should be
allowed, particularly for blowdown events that are from equipment with
defined volumes and known temperatures and pressures. One commenter
recommended that the rule be revised to allow use of a remote
measurement method to measure flow rate.
Response: After consideration of these comments, we agree with the
comments that methods that are allowed for determining flow of vented
emissions should also be allowed to determine flow to a flare, that in
some cases, such as for streams to low pressure flares, modeling may
produce flow estimates for the purposes of estimating annual greenhouse
gas emissions with accuracy similar to measurements using flow meters.
We also agree with commenters that the proposal underestimated the
costs of monitoring and that remote sites may not have access to grid
electricity needed to power the meters and other measurement devices.
Based on these considerations, the final amendments specify options for
determining flow based on slightly modified versions of the proposed
continuous parameter monitoring options (40 CFR 98.233(n)(1)(i) and
(ii) as proposed) that align more closely with current requirements as
well as new options that also are more closely aligned with options in
the current rule.
The proposed option to measure flow of the total inlet stream to
the flare was finalized with two changes from proposal (40 CFR
98(n)(3)(i)). One change was to add a sentence specifying that measured
flow must be used in calculating the flared emissions if a continuous
parameter monitoring system is used. This requirement was added since
the final amendments include options other than the continuous
monitoring options, and a facility may not elect to calculate emissions
based on one of the other options if they have measured volumes. This
change is consistent with the requirements in 40 CFR 98.233(n)(1) of
the current rule. The second change was to add a requirement to use
engineering calculations based on best available data and company
records to calculate pilot gas flow to add to the total gas flow to the
flare. This requirement was added because we realized that we had
inadvertently neglected to include a requirement for determining pilot
gas flow in the proposal. This change also makes the final option
consistent with the requirement in 40 CFR 98.233(n)(1) to determine
flow for ``all of the flare gas.''
The final amendments also specify several options for determining
the flow of individual streams that are routed to the flare. The
proposed option to use a continuous parameter monitoring system was
finalized as proposed (40 CFR 98.233(n)(3)(ii)(A)), except that a
sentence was added specifying that measured flow must be used in
calculating the flared emissions if a continuous parameter monitoring
system is used. This sentence was added for the same reason noted above
for adding it to the option for using a continuous parameter monitoring
system to measure total inlet flow to the flare.
The final amendments also include new options to determine flow
using process simulations, engineering calculations, and emission
factor methods consistent with methods specified for determining vented
emissions for sources whose flared emissions are required to be
disaggregated. The applicable options are specified in separate
paragraphs for each source type for which subpart W specifies methods
for determining flow of vented emissions (40 CFR 98.233(n)(3)(ii)(B)(1)
through (7)). Additionally, for source types that are subject to flare-
specific reporting in the current rule (e.g., dehydrators, completions,
tanks, well testing, associated gas), these options are consistent with
the requirements in the current rule for determining the volume of gas
routed to flares. For other source types, including new source types
subject to reporting for the first time under these amendments (e.g.,
crankcase venting) and sources that do not have methods for calculating
vented emissions in subpart W, 40 CFR 98.233(n)(3)(ii)(B)(8) of the
final amendments specifies that flow to the flare may be calculated
using engineering calculations based on process knowledge, company
records, and best available data. Additionally, since some of the
methods for calculating vented emissions calculate only the flow of
GHGs, 40 CFR 98.233(n)(3)(ii)(B)(8) of the final amendments also
specifies that the flow of the non-GHG portion of the streams routed to
the flare also must be based on process knowledge, company records, and
best available data.
We have not included an option in the final rule to determine flow
using the VISR advanced remote sensing method suggested by one
commenter because we do not have sufficient information on the
applicability and effectiveness of the method for determining flow over
the range of conditions expected at facilities in the oil and gas
industry. The study cited in the commenter's letter evaluated the
method for a single steam-assisted flare at a research facility using
natural gas as the flared gas. It is not clear from this study how the
method would be implemented and perform when used for other types of
flares and when the flared gas includes other hydrocarbons in addition
to methane and the composition varies with time. The method also
provides flow only of the combustible constituents in the flared gas,
which means procedures for converting to total volume would need
[[Page 42148]]
to be specified in the rule so that the flow could be used to calculate
emissions using equations W-19, W-20, and W-40, or the rule would need
separate procedures for calculating emissions when using this method.
The paper summarizing the results of the study also noted that the
method is less accurate when the combustion efficiency is low. The EPA
intends to further evaluate this method as additional information
becomes available and may consider including an option based on this
method in a future rulemaking.
Comment: One commenter supported the proposed approach that
provided a choice between using a continuous gas analyzer or conducting
periodic compositional analysis. However, numerous commenters opposed
the proposed composition measurement requirements for a variety of
reasons. The most commonly cited reasons for opposition were that the
composition of produced gas is relatively stable so frequent sampling
will not significantly improve accuracy of emissions calculations and
that the requirement would add significant costs and not be cost
effective. Some commenters indicated that there would be logistical
challenges to quarterly sampling because only a limited number of labs
are capable of conducting the required analyses, and there would be
logistical challenges to the use of continuous composition analyzers
including installation of sample ports, calibration and maintenance of
the thousands of meters, and lack of infrastructure and field
connectivity. One commenter added that requiring compositional
monitoring would further exacerbate ongoing COVID-related supply chain
delays. Other commenters asserted that there are technical challenges
to collecting samples in low-pressure lines with intermittent flows,
and one commenter stated that it is difficult to calibrate composition
analyzers on such streams. One commenter stated that it is inconsistent
to require analysis of streams routed to flares when such analysis is
not required for calculating vented emissions from the same source
types. One commenter stated that sampling sour gas streams would pose a
safety risk due to the presence of high H2S concentrations. One
commenter objected to the proposed analysis requirements because they
go beyond the continuous NHV monitoring or demonstration under proposed
NSPS OOOOb and EG OOOOc. One commenter asserted that the proposed
annual sampling of purge gas, sweep gas, and auxiliary fuel would pose
undue burdens on operators for stream that will not significantly
impact emissions reported under subpart W.
Instead of requiring continuous gas composition analyzers or
periodic sampling and analysis, nearly all of the commenters stated
that the current requirements should be retained. Many of these
commenters specifically indicated that the final rule should allow the
current option to determine composition using process simulations.
Other commenters stated that the final rule should include the current
options for using engineering calculations, best available data, or
representative sampling. Two commenters suggested that the frequency of
conducting analysis of representative samples should be at least
annually. If quarterly sampling is retained in the final amendments,
two commenters requested that the rule also include a provision
allowing companies to reduce the frequency after some period of showing
that the composition is stable. One commenter stated that sales gas
composition should be allowed for pilot/assist gas. Another commenter
requested that the sampling of purge gas, sweep gas, and auxiliary fuel
be made voluntary or required only if the volume exceeds a specified
threshold.
Response: After consideration of the public comments, we agree with
the commenter that asserted methods allowed for determining composition
of vented emissions should also be allowed to determine composition of
streams routed to a flare. We also agree with commenters that the
proposal underestimated the costs of monitoring. Based on these
considerations, the final amendments include additional options for
determining composition based on process simulation and engineering
calculations as well as the continuous gas composition monitoring and
periodic sampling and analysis options that are finalized with some
changes from proposal.
The final amendments include two options for determining
composition of the total inlet stream to the flare that include some
changes from proposal (40 CFR 98.233(n)(3)(i) and (ii)) as proposed).
One option, in 40 CFR 98.233(n)(4)(i) of the final amendments,
finalizes the proposed option to use a continuous gas composition
analyzer on the total inlet stream to the flare. As in the current
rule, the final amendments specify that measured compositions must be
used in calculating emissions when a continuous gas composition
analyzer is used. The second option, to conduct quarterly sampling and
analysis of the total inlet stream to the flare, is finalized in 40 CFR
98.233(n)(4)(ii) with several changes from proposal. One change is that
the minimum sampling frequency is reduced to once per year. A second
change is the proposed requirement to calculate flow-weighted annual
averages was not finalized because the flow determinations do not
necessarily align with the composition measurements. Finally, there is
no need for the proposed requirement to calculate an annual average if
only one sample is analyzed during the year. Instead, the final
amendments require calculation of an annual average per constituent if
more than one sample is analyzed during a year. These changes will
lower costs of the final amendments relative to the proposal.
Commenters did not provide data to support their contention that the
composition of flared streams is relatively stable, and other data to
support or refute this position are also unavailable. However, we
reduced the minimum required sampling and analysis frequency for this
option from quarterly to annually for the final amendments to be
consistent with the current frequency specified in 40 CFR
98.233(u)(2)(ii) for onshore natural gas processing plants to determine
composition of feed natural gas for calculating vented emissions from
sources upstream of the demethanizer or dew point control if they do
not determine composition of feed natural gas using a continuous gas
composition analyzer. We believe this will provide acceptably accurate
data to use in calculating emissions.
The final amendments also include several options for determining
composition of individual emission streams routed to a flare. One
option, specified in 40 CFR 98.233(n)(4)(iii)(A) of the final
amendments, is to use a continuous gas composition analyzer. This
option is finalized with several changes since proposal. The proposed
option (40 CFR 98.233(n)(3)(iii) as proposed) would have required
sampling of purge gas, sweep gas, and auxiliary fuel at least annually.
This proposed requirement was not finalized as part of the final
continuous gas composition analyzer option because sampling
requirements are specified as a separate option for individual streams
as discussed below. We also did not finalize the proposed requirement
to determine flow-weighted annual average concentrations because flow
determinations are not necessarily obtained on the same time intervals
as the composition measurements. Consistent with the requirements for
continuous gas composition analyzers used on the total inlet stream to
a flare,
[[Page 42149]]
the measured mole fractions must be used to calculate annual average
concentrations for each constituent to use in calculating flared
emissions if a continuous gas composition analyzer is used.
A new option in the final amendments for determining composition of
individual streams from dehydrators, hydrocarbon liquid and produced
water storage tanks, and acid gas removal units is to use process
simulation software in the same manner that is specified for
determining composition of vented streams from these sources. These
options are specified in 40 CFR 98.233(n)(4)(iii)(B)(1) through (3) of
the final amendments. These options are included in the final
amendments so that a facility may use the same procedures for
determining composition of streams routed to flares that are also
specified for determining composition of vented streams from the same
source types. Another new option in 40 CFR 98.233(n)(4)(iii)(B)(4) of
the final rule specifies requirements for determining composition of
streams routed to flares from various emission sources at onshore
production facilities, consistent with 40 CFR 98.233(n)(2)(ii) of the
current rule. Finally, a new option in 40 CFR 98.233(n)(4)(iii)(B)(6)
of the final rule specifies procedures for determining composition of
hydrocarbon product streams, consistent with 40 CFR 98.233(n)(2)(iii)
of the current rule.
The fourth proposed option was to analyze quarterly samples of
individual streams from emission source types and to analyze annual
samples of sweep gas, purge gas, and auxiliary fuel (40 CFR
98.233(n)(3)(iv) as proposed). Based on consideration of comments, this
proposed option has not been finalized as proposed, but the concept of
conducting individual stream sampling is incorporated into the more
expansive new options in 40 CFR 98.233(n)(4)(iii)(B)(1) through (3) of
the final amendments for determining composition of streams routed to
flares from dehydrators, hydrocarbon liquid and produced water storage
tanks, and acid gas removal units. These options specify that
composition may be determined using procedures in 40 CFR 98.233(u)(2)
for the applicable industry segment, with two exceptions. The first
exception is that when use of a continuous gas analyzer is specified in
40 CFR 98.233(u)(2), it means the continuous gas analyzer requirements
specified in 40 CFR 98.233(n)(4)(iii)(A) of the final amendments. This
change will ensure consistent application of continuous gas composition
analyzer requirements to all sources in all industry segments. The
second exception is that when 40 CFR 98.233(u)(2)(i) specifies using
``your most recent available analysis'' to determine composition, the
final amendments require using annual samples. The current rule also
requires onshore petroleum and natural gas production facilities and
onshore petroleum and natural gas gathering and boosting facilities to
determine composition using the procedures in 40 CFR 98.233(u)(2)(i).
However, requiring annual sampling in the final amendments instead of
the current requirement to use the most recent available analysis will
help ensure the use of representative samples, and the requirement for
sampling annually was specified to be consistent with the annual
sampling frequency for other streams as discussed previously.
Similarly, for streams from any source type other than those identified
in 40 CFR 98.233(n)(4)(iii)(B)(1) through (4), including sweep, purge,
and auxiliary fuel, 40 CFR 98.233(n)(4)(iii)(B)(5) in the final
amendments also specify that composition may be determined using the
applicable procedures in 40 CFR 98.233(u)(2). Finally, since the
procedures in 40 CFR 98.233(u)(2) require determination of only the GHG
composition, 40 CFR 98.233(n)(4)(iii)(B)(7) in the final amendments
requires determination of representative compositions of ethane,
propane, butane, and pentanes plus based on process knowledge and best
available data, consistent with requirements in 40 CFR
98.233(n)(2)(iii) of the current rule.
Comment: One commenter indicated that operators should have the
opportunity to measure flare gas HHV directly using, for example,
continuous gas analyzers or by using a sound speed methodology from an
ultrasonic flowmeter. The commenter noted that this latter method can
provide reliable real-time measurement, is highly accurate, can be
implemented with minimum cost, and is easy to maintain. The commenter
cited a specific patent ``Online Analyzers for Flare Gas Processing'',
which describes a system that has been used successfully in the
field.\64\
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\64\ US Patent Pub. No.: US 2022/0107289 A1. April 7, 2022.
Available at: https://patentimages.storage.googleapis.com/6b/46/97/d1524f32c62da7/US20220107289A1.pdf.
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Response: The EPA agrees with the commenter that direct measurement
of the HHV should be allowed in addition to the calculation of HHV from
concentration data and the final provisions have been changed from
proposal accordingly. In 40 CFR 98.233(n)(8), the final rule specifies
that the annual average HHV may be directly measured using a
calorimeter or by using a continuous gas composition analyzer that
automatically calculates the HHV based on the measured composition. In
addition to direct measurement methods, the final rule also specifies
that annual average HHV may be calculated based on the annual average
compositions determined using continuous gas composition analyzers,
periodic sampling and analysis, or process simulation or engineering
calculations. As discussed in a previous response in this section, the
periodic sampling and analysis for gas composition must be at least
annually in the final rule as opposed to at least quarterly in the
proposed rule. Another previous response in this section provides
information regarding the addition of process simulation and
engineering calculation options for determining composition in the
final rule.
The final rule, however, does not cite the specific methodology
described by the commenter. With regard to the patent mentioned, the
EPA agrees that it appears to be an efficient method to continuously
measure the net heating value of a gas stream. However, no information
was provided regarding how this would be converted to HHV as required
by the rule.
Comment: One commenter recommended that the EPA should also require
reporters that elect to be in Tier 1 or Tier 2 to keep and maintain
records consistent with the recordkeeping requirements under the
respective NESHAP CC, NSPS OOOOb, and approved state plan requirements.
For Tier 1, the commenter recommended including the recordkeeping
requirements under 40 CFR 63.655(i)(9); for Tier 2 the commenter
recommended including the recordkeeping requirements consistent with 40
CFR 60.5420b(c)(3)(ii)(A) through (H). According to the commenter,
maintaining such records will allow EPA staff to verify additional
compliance with the respective flare requirements to ensure more
accurate emissions reporting.
Response: The EPA agrees with the commenter that additional
recordkeeping is needed to ensure that facilities that are not subject
to the NESHAP CC or NSPS OOOOb but elect to comply with the Tier 1 or
Tier 2 efficiencies are achieving the applicable efficiencies for
purposes of the subpart W calculation methodology. Thus, the EPA has
strengthened recordkeeping
[[Page 42150]]
requirements in the final rule for facilities complying with the Tier 1
or Tier 2 efficiencies to align with the recordkeeping requirements for
flares in NESHAP CC and NSPS OOOOb, respectively. Specifically, for
Tier 1, 40 CFR 98.233(n)(1)(i) requires compliance with the
recordkeeping requirements in 40 CFR 63.655(i)(2) and (3) for enclosed
combustion devices and 40 CFR 63.655(i)(9) for open flares. For Tier 2,
40 CFR 98.233(n)(1)(ii)(A), (B), and (C) require compliance with the
recordkeeping requirements in 40 CFR 60.5420b(c)(11).
For Tier 2, the commenter cited the recordkeeping requirements in
40 CFR 60.5420b(c)(3)(ii)(A) through (H) of the December 6, 2022,
Supplemental Proposal. These sections have been rearranged in the final
NSPS OOOOb making it difficult to determine exactly which recordkeeping
requirements in the final NSPS OOOOb the commenter would recommend
including in subpart W. However, some of the provisions in the sections
cited by the commenter involved records of certifications (e.g., for
closed vent systems or to document why it is infeasible to comply with
associated gas recovery requirements), records of periods of temporary
venting of associated gas, records of bypass monitoring, and closed
vent system inspection records that we have not included in the final
subpart W. Requirements to certify both closed vent system inspections
and reasons for why it is infeasible to comply with associated gas
recovery requirements and related recordkeeping requirements are not
included in this rulemaking because subpart W is an emissions reporting
rule, not an emissions control rule. Records related to associated gas
venting are not addressed in 40 CFR 98.233(n) because the methodology
for calculating vented associated gas emissions, including temporary
venting of streams that are normally flared, is specified in 40 CFR
98.233(m) of the final rule. The final rule does not require facilities
that elect to comply with the Tier 2 efficiencies to implement NSPS
OOOOb bypass device and closed vent system requirements, including
related recordkeeping requirements. These requirements are included in
NSPS OOOOb to ensure that the emission standards for emission source
types are met, but these provisions are not needed to ensure the
efficiency of the flare is met for the portion of the flow from a
source that is routed through the flare. However, if there are leaks
from a closed vent system or a bypass device diverts flow from entering
a flare, then those volumes cannot be assumed to be controlled by the
flare. Therefore, for a facility that measures or calculates flow
volumes routed to flares from individual sources (instead of measuring
the total flow at the flare inlet), 40 CFR 98.233(n)(3)(ii) in the
final rule specifies that the closed vent system leaks and bypass
volumes must be calculated based on engineering calculations, process
knowledge, and best available data and subtracted from the measured or
calculated flow volumes from the applicable sources to determine the
flow routed to the flare. The final rule also specifies that the
estimated closed vent system leaks and bypass volumes must be used in
the calculation and reporting of vented emissions from the applicable
sources. These requirements will ensure that the closed vent system
leaks and bypass emissions are properly estimated, consistent with the
directive under CAA section 136(h) to ensure that reporting under
subpart W accurately reflects total methane emissions. We have also
included a harmonizing reporting requirement in 40 CFR 98.236(n)(11) of
the final rule for reporters to indicate whether the reported volumes
for each stream from an individual source has been adjusted to account
for closed vent system leaks or bypass volumes. In the EPA's
verification process, this information is expected to help identify
facilities that should report vented emissions from sources that also
report flared emissions. Finally, the recordkeeping requirements
specific to flare design and operation in 40 CFR 60.5420b(c)(11) are
cross-referenced from 40 CFR 60.5420b(c)(3). Thus, since these are the
only NSPS OOOOb recordkeeping requirements that are included in the
final rule, we have directly cross-referenced the recordkeeping
requirements in 40 CFR 60.5420b(c)(11) from 40 CFR 98.236(n)(3)(ii) of
the final rule.
2. Reporting Requirements for Flared Emissions
a. Summary of Final Amendments
The EPA is finalizing several changes to the reporting requirements
for flares. These changes are to align reporting in 40 CFR 98.236(n)
with the final revisions to the calculation methods specified in 40 CFR
98.233(n), consistent with section II.B. of this preamble, and to
improve the verification process, obtain a better understanding of the
design and operation of flares in each of the industry segment to help
future policy determinations, and clarify ambiguous provisions.
First, the EPA is finalizing as proposed the replacement of the
source-specific flared CH4, CO2, and
N2O emissions reporting requirements currently in 40 CFR
98.236(e), (g), (h), (j), (k), (l), (m), and (n) with a requirement to
disaggregate total reported CH4, CO2, and
N2O emissions per flare to the source types that routed gas
to the flare as described in section III.N.1. of this preamble. The
total emissions per flare must be disaggregated to the source types
specified in 40 CFR 98.236(n)(19). The source types listed in 40 CFR
98.236(n)(19) include all of the source types for which flared
emissions currently must be reported, except that flared emissions from
condensate storage tanks must be included in the collective emissions
from ``other'' flared sources rather than being disaggregated
separately. Additionally, the final amendments, as proposed, require
disaggregation of flared emissions that are attributable to AGR vents
(flared emissions from NRU vents must be included in the category of
``other'' flared sources). In addition to aligning the reporting with
the final calculation methodology, reporting the disaggregated
emissions per flare rather than per facility, sub-basin, or county (as
currently required), and rather than per well-pad site, gathering and
boosting site, or facility (as is required in the final amendments for
vented emissions), will provide the EPA and other stakeholders with a
better understanding of the impact of different emission source types
on the performance of flares.
Second, we are finalizing as proposed adjustments to several of the
existing reporting elements to align with proposed changes to the
calculation methodology. For example, existing 40 CFR 98.236(n)(4)
requires reporting of the total volume of gas routed to the flare. As
described in section III.N.1. of this preamble, the final amendments
add an option for reporters to determine volume of each stream routed
to the flare. To align with this monitoring approach, 40 CFR
98.236(n)(11) in the final amendments adds a requirement to report the
volumes for each of the individual streams if the reporter elects to
determine the flow rate of the individual streams rather than the
total. Similarly, existing 40 CFR 98.236(n)(7) and (8) require
reporting of the CH4 and CO2 in the feed gas to
the flare. To align with the final option that allows determination of
gas composition at all of the source stream levels as an alternative to
determination of the composition at the flare inlet, as
[[Page 42151]]
discussed in section III.N.1. of this preamble, 40 CFR 98.236(n)(14)
and (15) in the final amendments require reporting of the annual
CH4 and CO2 mole fractions for each of the
individual streams routed to the flare if the reporter elects to
determine composition of those streams.
Further, the final 40 CFR 98.236(n)(7) requires reporters to
indicate whether flow to the flare is measured at the inlet to the
flare or determined for individual streams routed to the flare, and if
it is measured at the inlet to the flare, then the reporter must
indicate whether the volume was determined using a continuous flow
measurement device or if it was determined using monitored parameters
and engineering calculations. If the flow is determined for individual
streams routed to the flare, the reporter must indicate, for each
stream, whether the volume was determined using a continuous flow
measurement device, using monitored parameters and engineering
calculations, or other simulation or engineering calculation methods.
Similarly, the final 40 CFR 98.236(n)(8) requires reporters to indicate
whether gas composition was determined at the inlet to the flare using
a continuous gas analyzer, sampling and analysis, or if composition was
determined for the individual streams that are routed to the flare. If
the composition is determined for individual streams routed to the
flare, the reporter must indicate, for each stream, whether the
composition was determined using a continuous gas analyzer, sampling
and analysis, or other simulation or engineering calculation methods.
The final requirements in these sections have been revised from
proposal to align with the final revisions to the calculation
methodology.
Third, we are finalizing requirements in 40 CFR 98.236(n)(12)
(proposed 40 CFR 98.236(n)(13)) for destruction and combustion
efficiencies. Proposed 40 CFR 98.236(n)(13) would require reporting of
the combustion efficiency used to calculate emissions from each flare.
As discussed in section III.N.1. of this preamble, the final amendments
were revised from proposal to require use of both destruction
efficiencies and combustion efficiencies to calculate flared emissions.
Additionally, as discussed in section III.N.1. of this preamble, the
final amendments include an option to use efficiencies higher than the
defaults if the reporter implements an alternative test method that is
approved as specified in NSPS OOOOb. To align with these revisions to
the calculation methodology, 40 CFR 98.236(n)(13) in the final
amendments requires reporting of the destruction efficiency used for
each flare. Additionally, 40 CFR 98.236(n)(13) in the final amendments
requires reporting, as proposed, of a flow-weighted destruction
efficiency if the reporter calculates emissions for part of the year
using one destruction efficiency and calculates emissions for the rest
of the year using a different destruction efficiency. In a change from
the proposal, the final amendments require reporting of flow-weighted
average combustion efficiency fractions to three decimal places instead
of one decimal place; the proposed requirement was incorrect because
the efficiencies are to be reported as fractions (i.e., consistent with
the values used in equations W-19 and W-20), not percentages. These
data will help with verification of the reported emissions.
We are finalizing the addition of several new reporting elements in
40 CFR 98.236(n)(13) to align with changes to the final flare
efficiency options. If you comply with Tier 1 or Tier 2, new
requirements to report the number of days in periods of 15 or more
consecutive days when you did not conform with all cited provisions in
40 CFR 98.233(n)(1)(i) or (ii) are included in both final 40 CFR
98.236(n)(13)(i) for Tier 1 and in 40 CFR 98.236(n)(13)(ii) for Tier 2.
These reporting requirements align with the requirements in the final
Tier 1 and Tier 2 calculation methodologies to use the Tier 3
efficiencies for periods of monitoring parameter non-conformance that
exceed 15 consecutive days. For facilities that report flares using a
destruction efficiency of 95 percent (Tier 2), final 40 CFR
98.236(n)(13)(ii), as proposed, requires reporters to indicate whether
the flare is subject to NSPS OOOOb or whether the reporter is electing
to implement flare procedures that are specified in NSPS OOOOb. The
final amendments also extend this reporting requirement to whether the
reporter is subject to a state or Federal plan in 40 CFR part 62
implementing EG OOOOc or is electing to follow a state or Federal Plan
in 40 CFR part 62 implementing EG OOOOc. Another new data element in
final 40 CFR 98.236(n)(13) requires facilities with flares that are
enclosed ground level flares or enclosed elevated flares that are not
required to comply with NSPS OOOOb or state or Federal Plan in 40 CFR
part 62 implementing EG OOOOc but are electing to comply with Tier 2
efficiencies to indicate if the most recent performance test was
conducted using the method in 40 CFR 60.5413b(b) (i.e., onsite
testing), the method in 40 CFR 60.5413b(d) (i.e., manufacturer
testing), or the alternative method specified in 40 CFR
98.233(n)(1)(iv) (i.e., OTM-52). Finally, new reporting elements are
added in final 40 CFR 98.236(n)(13)(iii) that require reporters to
indicate if they are using an efficiency for an alternative test method
approved under 40 CFR 60.5412b(d) and if they are, to also report the
approved destruction efficiency and the date when the reporter started
to use the alternative test method. This information will help the EPA
verify the reported data.
Fourth, existing 40 CFR 98.236(n)(12) requires reporting of whether
a CEMS was used to measure CO2 emissions from the flare.
This reporting requirement is retained in 40 CFR 98.236(n)(20) as
proposed, along with a requirement that the CO2 mole
fraction of the gas sent to the flare should not be reported when using
CEMS because equation W-20 is not used to calculate CO2
emissions when using a CEMS.
Fifth, one objective of the current flare reporting requirements is
to obtain information on the total number of flares and their operating
characteristics. We are finalizing as proposed the addition of a few
new flare-specific reporting elements to help us better understand the
state of flaring in the industry for carrying out provisions under the
CAA and to improve data quality, such as an indication of the type of
the flare (e.g., open ground-level flare, enclosed ground-level flare,
open elevated flare, or enclosed elevated flare) in 40 CFR 98.236(n)(4)
and the type of flare assist (e.g., unassisted, air-assisted (with
indication of single-, dual-, or variable-speed fan), steam-assisted,
or pressure-assisted) in 40 CFR 98.236(n)(5). These data will help the
EPA assess the impact of design and operation on emissions and may be
useful in analyses for potential future policy decisions related to
flares under the CAA. To harmonize the final reporting requirements
with the final requirement to either continuously monitor or
periodically inspect for the presence of a pilot flame as discussed in
section III.N.1. of this preamble, we are finalizing as proposed 40 CFR
98.236(n)(6) requiring that reporters indicate for each flare whether
they continuously monitor for the presence of a pilot flame, conduct
periodic visual inspections, or both. As proposed, if periodic visual
inspections are conducted, 40 CFR 98.236(n)(6) also requires reporting
of the count of inspections conducted during the year. Since the final
rule requires a continuous pilot, we are not finalizing the proposed
requirement to report whether the inspected flare has a
[[Page 42152]]
continuous pilot or auto igniter. For a pilot flame that is monitored
continuously, the final amendments as proposed also require reporting
of the number of times the continuous monitoring devices were out of
service or otherwise inoperable for a period of more than one week.
The EPA is not finalizing the proposed requirement for facilities
in the Onshore Petroleum and Natural Gas Production industry segment,
the Onshore Petroleum and Natural Gas Gathering and Boosting industry
segment, and the Onshore Natural Gas Processing industry segment to
report an estimate of the fraction of the gas burned in the flare that
is obtained from other facilities specifically for flaring as opposed
to being generated in on-site operations. At proposal, we indicated
that this proposed data element would provide information on what
source types are generating significant emissions from miscellaneous
flared sources. However, after consideration of public comments
indicating that the fraction would be difficult to determine, we have
decided not to take final action on this requirement at this time.
Finally, because the proposed calculation methodologies for flares
would have required measurement of flow and composition rather than use
of source-specific calculation methodologies, the EPA also proposed
that source types that are flared for the entire year would not be
required to report the activity data associated with those source-
specific calculation methodologies. Instead, those sources would have
only been required to report identifying information about the unit and
indicate that emissions were routed to a flare the entire year under
the individual source type, and all other activity data related to the
flares would have been reported under 40 CFR 98.236(n). Under the final
amendments, if the flow of the gas routed to a flare is not measured
according to 40 CFR 98.233(n)(3)(i) and (n)(3)(ii)(A) and/or the
composition of the gas routed to a flare is not measured according to
40 CFR 98.233(n)(4)(i) and (ii), then the reporter must determine the
flow and composition of the gas using the calculation methods for that
source type, per final 40 CFR 98.233(n)(3)(ii)(B) and
98.233(n)(4)(iii). Because the final amendments provide multiple
methods for calculating the flow and composition of gas streams routed
to flares, the EPA is not finalizing the consolidation of all the
flare-related activity data under 40 CFR 98.236(n), as was proposed.
Instead, for the disaggregated sources listed in 40 CFR
98.233(n)(3)(ii)(B)(1) through (7), the EPA is finalizing reporting
requirements within the section for each source type that is routed to
a flare. These source-specific reporting requirements apply in addition
to the information required to be reported under 40 CFR 98.236(n) for
the flare. Specifically, for these source types with gas routed to a
flare, reporters will continue to report the required identifying
information (e.g., unit ID, well ID, well-pad ID) and then indicate at
the specified reporting level (e.g., by well or individual source type,
by well-pad site or gathering and boosting site) whether the gas was
routed to the flare for part of the year or the entire year and provide
the flare stack identifier or name as well as the unique ID for the
stream routed to the flare.
Reporters will also report whether the gas flow and composition
were determined through measurement or the source-specific
methodologies for sources listed in 40 CFR 98.233(n)(3)(ii)(B)(1)
through (7). In cases where the reporter is using source type-specific
calculation methods, it is essential that certain activity data be
reported for the source type for accurate verification of reported
emissions data and also accurate allocation of disaggregated emissions
data, if applicable. Therefore, if a source-specific methodology is
used, reporters will be required to report the same activity data for
the source type as they would if the gas were vented directly to the
atmosphere. For example, if an acid gas removal vent is routed to a
flare and the flow and composition of the gas routed to the flare is
determined using Calculation Method 4, the reporter will be required to
provide the activity data associated with Calculation Method 4 under 40
CFR 98.236(d)(2)(iv). Other examples include completions and workovers
with hydraulic fracturing, for which the reporter will be required to
indicate the calculation method used and data specific to equation W-
10A and W-10B; completions and workovers without hydraulic fracturing,
for which the reporter will be required to provide the inputs to
equations W-13A and W-13B; and associated gas flaring, for which the
reporter will be required to provide the inputs to equation W-18. These
data are essential for the verification of flared emissions and the
identification of the flare to which the emission sources are routed.
For sources that are routed to flares other than those listed in 40
CFR 98.233(n)(3)(ii)(B)(1) through (7), flow to the flares is required
to be determined using engineering calculations based on process
knowledge, company records, and best available data in accordance with
40 CFR 98.233(n)(3)(ii)(B)(8), and no additional reporting requirements
within the section for each source type are being finalized.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to the reporting requirements for flare stacks.
Comment: Commenters opposed the proposal of the requirement in
proposed 40 CFR 98.236(n)(10) to report the estimated fraction of total
volume flared that was received from another facility solely for
flaring. Commenters indicated that this information would be difficult
to determine and would not provide meaningful information. The
commenters stated that the EPA should require reporting of the
emissions from a flare stack without considering whether the gas was
received from another facility.
Response: After review of these comments, we are not taking final
action at this time on the proposed reporting requirement. In the
preamble to the proposed rule, we indicated that this proposed data
element would help the EPA understand what source types are generating
the large amounts of flared gas reported under miscellaneous flared
sources, and that if the source type also is not currently subject to
source-specific reporting of vented emissions, then a potentially large
quantity of vented emissions might go unreported. However, the proposed
data element would have only indicated whether the gas was received
from a different facility to be flared; it would not have told us what
emission source generated the gas. In addition, in this final rule, we
are finalizing the addition of numerous new emission sources under
subpart W, so the likelihood that another potentially large quantity of
vented emissions might go unreported has decreased. The EPA not taking
final action on this reporting requirement at this time does not affect
the general requirements to calculate and report total emissions from
each flare stack.
3. Definition of Flare Stack Emissions
The term ``flare stack emissions'' in 40 CFR 98.238 is currently
defined to mean ``CO2 and N2O from partial
combustion of hydrocarbon gas sent to a flare plus CH4
emissions resulting from the incomplete combustion of hydrocarbon gas
in flares.'' As noted in the 2023 Subpart W Proposal, the current
definition does not clearly convey the EPA's intent that the
CO2 that enters a flare should be reported as flare stack
emissions and it implies N2O emissions
[[Page 42153]]
only result from partial combustion of hydrocarbons in the gas routed
to the flare, which is not the case. Consistent with section II.D. of
this preamble, in order to eliminate the unintended inconsistency
between the definition and the intent that CO2 in gas routed
to the flare is to be reported as emissions from the flare, to clarify
the requirement to calculate and report total CO2 that
leaves the flare, and to clarify the source of flared N2O
emissions, we are finalizing as proposed the revision of the definition
of the term ``flare stack emissions'' in 40 CFR 98.238 to mean
CO2 in gas routed to a flare, CO2 from partial
combustion of hydrocarbons in gas routed to a flare, CH4
resulting from the incomplete combustion of hydrocarbons in gas routed
to a flare, and N2O resulting from operation of a flare. The
EPA received only supportive comments regarding the revisions to the
definition of ``flare stack emissions.'' See the document Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems
under the Greenhouse Gas Reporting Rule in Docket ID. No. EPA-HQ-OAR-
2023-0234 for these comments and the EPA's responses.
O. Compressors
Compressors are used across the petroleum and natural gas industry
to raise the pressure of and convey natural gas or CO2. The
two main types of compressors used in the industry are centrifugal
compressors and reciprocating compressors. We are finalizing several
amendments to subpart W related to compressors as proposed, finalizing
some amendments with revisions from proposal, and not finalizing other
proposed amendments.
1. Mode-Source Combination Measurement Requirements
a. Summary of Final Amendments
The EPA is finalizing several amendments related to the ``as
found'' measurement requirements to improve the quality of data
collected for compressors. First, standby-pressurized-mode was not
included as a mode for centrifugal compressors in the existing subpart
W definition of ``compressor mode'' and no compressor mode-source
combinations were defined for centrifugal compressors in standby-
pressurized-mode. While centrifugal compressors are seldom in the
standby-pressurized-mode, there have been several occasions when
reporters have indicated through the GHGRP Help Desk that a centrifugal
compressor was in this mode during the ``as found'' measurement.
Therefore, we are finalizing as proposed the revised definition of
compressor mode in 40 CFR 98.238 that includes standby-pressurized-mode
as a defined mode for centrifugal compressors. We are also finalizing
as proposed the requirement to measure volumetric emissions from the
wet seal oil degassing vent or dry seal vent, as applicable (see
discussion in the following paragraph) and the volumetric emissions
from blowdown valve leakage through the blowdown vent when the
compressor is found in standby-pressurized-mode (40 CFR
98.233(o)(1)(i)(C)), consistent with section II.A. of this preamble.
Second, dry seals on centrifugal compressors were not included in
the existing subpart W definition of ``compressor source'' and no
compressor mode-source combinations were defined for dry seals on
centrifugal compressors. While emissions from wet seal oil degassing
vents are expected to be larger than from dry seals when the dry seal
compressor is well-maintained and operating normally, dry seals still
contribute to centrifugal compressor emissions, especially if they are
poorly maintained or there are unforeseen upset conditions. Therefore,
to better characterize the emissions from dry seal centrifugal
compressors, we are finalizing the revised definition of compressor
source in 40 CFR 98.238 to include dry seal vents as one of the defined
compressor sources for centrifugal compressors. We are also finalizing
as proposed the requirement to measure volumetric emissions from the
dry seal vents in both operating-mode and in standby-pressurized-mode
(40 CFR 98.233(o)(2)(iii)), consistent with section II.B. of this
preamble. Under the final provisions, the measurement methods for the
dry seal vents are similar to those provided for reciprocating
compressor rod packing emissions and include the use of temporary or
permanent flow meters, calibrated bags, and high volume samplers. We
are finalizing as proposed that screening methods may also be used to
determine if a quantitative measurement is required. We are finalizing
as proposed the specification that acoustical screening or measurement
methods are not applicable to screening dry seal vents because
emissions from dry seal vents are not a result of through-valve
leakage. As proposed, certain requirements in 40 CFR 98.236(o) are now
applicable to the dry seal compressor source under the final rule,
including new reporting requirements in 40 CFR 98.236(o)(1)(x) to
report the number of dry seals on centrifugal compressors and in 40 CFR
98.236(o)(2)(B) to report dry seals as one of the centrifugal
compressor sources.
Third, we are finalizing as proposed the revision to 40 CFR
98.233(p)(1)(i) to require measurement of rod packing emissions for
reciprocating compressors when found in the standby-pressurized-mode
because recent studies indicate that rod packing emissions can occur
while the compressor is in this mode.\65\ The inclusion of this
compressor mode-source combination more accurately reflects compressor
emissions, consistent with section II.A. of this preamble.
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\65\ Subramanian, R. et al. ``Methane Emissions from Natural Gas
Compressor Stations in the Transmission and Storage Sector:
Measurements and Comparisons with the EPA Greenhouse Gas Reporting
Program Protocol.'' Environ. Sci. Technol. 49, 3252-3261. 2015.
Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2023-0234.
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Fourth, we are finalizing as proposed the elimination of the
requirement in 40 CFR 98.233(o) to conduct a measurement in not-
operating-depressurized-mode at least once every three years,
consistent with section II.C. of this preamble. We originally included
the requirement for compressors that were not measured in not-
operating-depressurized-mode during the ``as found'' measurements for
three consecutive years in order to obtain a sufficient amount of data
for this mode (75 FR 74458, November 30, 2010). However, based on data
collected under subpart W thus far, many compressors are in not-
operating-depressurized-mode for 30 percent of the time or more.
Therefore, facilities are able to obtain a sufficient number of
measurements in not-operating-depressurized-mode to calculate an
accurate mode-source specific emission factor without the additional
requirement. As such, the extra measurements are no longer necessary,
and the final amendments in this rule make the annual measurements true
``as found'' measurements. We are also finalizing as proposed the
removal of the reporting requirement in 40 CFR 98.236(o) to indicate if
the compressor had a scheduled depressurized shutdown during the
reporting year because that information is only collected to verify
compliance with the requirement to conduct a measurement in not-
operating-depressurized-mode at least once every three years.
Fifth, we are finalizing one additional change to the proposed 40
CFR 98.233(o)(2)(iii) to clarify the specific location where the dry
seal measurement should be conducted. Language has been added to note
that
[[Page 42154]]
the measurement should be made on the compressor side dry seal. This
change was made to prevent measurements on the outboard side dry seal,
because process gas emissions from the dry seal on the outboard side
are very low.\66\
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\66\ Reducing Emissions from Compressor Seals; Lessons Learned
from Natural Gas STAR. Available at https://www.epa.gov/sites/default/files/2017-09/documents/reducingemissionsfromcompressorseals.pdf. Available in the docket
for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to mode-source combination measurement
requirements.
Comment: All commenters supported the proposed changes to the mode-
source combination measurement requirements. In addition, one commenter
suggested a change to 40 CFR 98.233(o)(2)(iii) to clarify that the dry
seal measurement should be conducted on the compressor side.
Response: We agree with the commenter that clarity is needed to
describe where the dry seal measurement should be conducted. Thus, in
the final rule, we are adding appropriate language to 40 CFR
98.233(o)(2)(iii) to clarify that dry seal measurements should be
conducted on the compressor side dry seal. All other changes to mode-
source combination measurement requirements are being finalized as
proposed.
2. Measurement Methods
a. Summary of Final Amendments
The EPA is finalizing several amendments related to the measurement
method requirements to improve the quality of data collected for
compressors. First, we are finalizing as proposed the revisions to the
allowable methods for measuring wet seal oil degassing vents.
Previously, the only method provided in 40 CFR 98.233(o)(2)(ii) for
measuring volumetric flow from wet seal oil degassing vents was the use
of a temporary or permanent flow meter. We are finalizing the revision
to 40 CFR 98.233(o)(2)(ii) allowing the use of calibrated bags and high
volume samplers. As proposed, under the final provisions we specify
that the use of screening methods for wet seal oil degassing vent
measurement is not allowed, because wet seal oil degassing vents are
expected to always have some natural gas flow. These revisions to 40
CFR 98.233(o)(2)(ii) provide improved clarity of the wet seal oil
degassing provisions and allow an additional measurement method that
was determined to be accurate for this source, consistent with section
II.B. of this preamble.
Second, we are finalizing, with two revisions from proposal, the
removal of acoustic leak detection from the screening and measurement
methods allowed for manifolded groups of compressor sources. Acoustic
leak detection is applicable only for through-valve leakage. Therefore,
the acoustic method for screening or measurement can be applied only to
individual compressor sources associated with through-valve leakage
(i.e., blowdown valve leakage or isolation valve leakage), but it
cannot be used for screening emissions from or measurement of emissions
from a vent that contains a group of manifolded compressor sources
downstream from the individual valves or other sources that may be
manifolded together. The previous inadvertent inclusion of this method
for manifolded compressor sources was in error and we are finalizing
its removal from 40 CFR 98.233(o)(4)(ii)(D) and (E) and 40 CFR
98.233(p)(4)(ii)(D) and (E) to improve accuracy of the measurements,
consistent with section II.B. of this preamble.
The final provisions include minor changes from the proposal to add
two new paragraphs at 40 CFR 98.233(o)(4)(ii)(F) and 40 CFR
98.233(p)(4)(ii)(F) to allow the use of acoustic leak detection as a
tool for manifolded compressor sources only after screening (to
determine that there is a leak) but prior to measurement (to quantify
the leak). This revision does not negate the fact that acoustic leak
detection should only be used on through-valve leakage for screening
and measurement. This revision simply allows the use of acoustic leak
detection, according to 40 CFR 98.234(a)(5), as a tool to identify one
leaking compressor valve among a group of multiple potentially leaking
compressor valves. A screening method from 40 CFR 98.234(a)(1) through
(3) will still be required to identify that a leak is occurring in the
manifolded group of compressors, and a measurement method from 40 CFR
98.233(o)(4)(ii)(A) through (D) or 40 CFR 98.233(p)(4)(ii)(A) through
(D) will still be required to quantify the leak, once the leaking
compressor valve is identified. Acoustic leak detection will only be
allowed to determine which compressor included in the manifolded group
is leaking, in order to make proper measurement of the leak easier to
perform. We included these changes after consideration of public
comment.
Third, we are finalizing as proposed a number of clarifications to
the references to the allowed measurement methods to correct errors and
improve the clarity of the rule, consistent with section II.D. of this
preamble. These final revisions include: revising 40 CFR
98.233(o)(1)(i)(A) and (B) to reference 40 CFR 98.233(o)(2)(i) instead
of specific subparagraphs of that paragraph that may be construed to
limit the methods allowed for blowdown or isolation valve leakage
measurements; revising 40 CFR 98.233(p)(1)(i)(A), (B) and (C) to
reference 40 CFR 98.233(p)(2)(i) instead of specific subparagraphs of
that paragraph that may be construed to limit the methods allowed for
blowdown or isolation valve leakage measurements; revising 40 CFR
98.233(p)(1)(i)(A) and (C) to reference ``paragraph (p)(2)(ii) or (iii)
of this section as applicable'' instead of only ``paragraph
(p)(2)(ii)'' to clarify that measurement of rod packing emissions
without an open-ended vent line are to be made according to 40 CFR
98.233(p)(2)(iii); and revising 40 CFR 98.233(p)(2)(ii)(C) and (iii)(A)
to clarify that acoustic leak detection is not an applicable screening
method for rod packing emissions because rod packing is not through-
valve leakage.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments related to measurement methods.
Comment: One commenter suggested an edit to allow acoustic leak
detection in limited circumstances. The commenter asked that the EPA
selectively retain the use of acoustic devices for manifolded
compressors to identify the source of the leak, but not to quantify
emissions. The use of acoustic leak detection would help determine
which compressor valve should be measured downstream of the manifold,
using one of the other methods specified in 40 CFR 98.233(o)(4)(ii)(A)
through (D) or 40 CFR 98.233(p)(4)(ii)(A) through (D). Specifically,
the commenter asked that if one of the screening methods specified in
40 CFR 98.234(a)(1) through (3) identifies a leak in a manifolded group
of compressor sources, that the reporter be allowed to use acoustic
leak detection, according to 40 CFR 98.234(a)(5), to identify which
compressor valve is leaking.
Response: The EPA reviewed the comment and determined that a
limited retainment of the use of acoustic leak detection, to identify
which compressor valve in a manifolded group of
[[Page 42155]]
compressor sources is leaking, is appropriate. In this case, acoustic
leak detection is not being relied upon to identify whether there is a
leak in the first place. Instead, this revision allows the use of
acoustic leak detection as a tool to identify the source of a leak from
a group of manifolded compressors. However, acoustic leak detection
will not be allowed to be used as a screening or measurement method to
identify or quantify emissions from a manifolded group of compressors.
This revision has been included in the final provision.
Comment: One commenter asked that the rule allow flexibility to
integrate advanced technologies that become available, such as the
option of using an OGI emissions quantification system, which the
commenter noted as a technology still under development, as an accepted
technology for methane emissions quantification when the performance of
that technology is confirmed.
Response: Without specific details that are necessary to evaluate
and incorporate such methodologies, such as the performance, accuracy
or precision of the aforementioned technology, and how the
aforementioned technology can be applied specifically to compressor
emission sources, the EPA is not able to fully evaluate for potential
incorporation in this rulemaking quantitative OGI or other technologies
that are currently still under development. Therefore, at this time
such technologies are not included in the final provisions.
3. Onshore Petroleum and Natural Gas Production or Onshore Petroleum
and Natural Gas Gathering and Boosting
a. Summary of Final Amendments
As noted in the introduction to section II. of this preamble, the
EPA recently finalized NSPS OOOOb and EG OOOOc for certain oil and
natural gas sources. The final standards in NSPS OOOOb and the final
presumptive standards in EG OOOOc include emission limits for
reciprocating compressors, centrifugal compressors with wet seals, and
centrifugal compressors with dry seals that apply when the compressor
is in operating-mode or standby-pressurized-mode. The final standards
require owners or operators to conduct volumetric emissions
measurements from each reciprocating compressor rod packing or
centrifugal compressor wet or dry seal on or before 8,760 hours of
operation from startup or from the previous measurement. Similar to the
2016 amendments to subpart W specific to equipment leak surveys (81 FR
4987, January 29, 2016), the EPA is finalizing, with a revision from
proposal, the calculation methodologies in 40 CFR 98.233(o)(10) and 40
CFR 98.233(p)(10) for compressors at onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and boosting
facilities in subpart W so that data derived from centrifugal
compressor or reciprocating compressor monitoring conducted under NSPS
OOOOb or the applicable approved state plan or applicable Federal plan
in 40 CFR part 62 will be required to be used to calculate emissions
for subpart W reporting, consistent with section II.B. of this
preamble.
For compressors at onshore petroleum and natural gas production or
onshore petroleum and natural gas gathering and boosting facilities not
subject to either NSPS OOOOb or an applicable approved state plan or
applicable Federal plan in 40 CFR part 62, we are finalizing, with a
revision from proposal, the calculation methodologies in 40 CFR
98.233(o)(10) and 40 CFR 98.233(p)(10) such that reporters have the
option to calculate emissions for subpart W reporting using the same
provisions for ``as found'' measurements as other industry segments
under 40 CFR 98.233(o)(1)(i) and 40 CFR 98.233(p)(1)(i), using methods
specified in 40 CFR 98.233(o)(2) through (5) or 40 CFR 98.233(p)(2)
through (5), as applicable, based on the compressor mode (as defined in
40 CFR 98.238) in which the compressor was found at the time of
measurement, and calculating emissions as specified in 40 CFR
98.233(o)(6) through (9) or 40 CFR 98.233(p)(6) through (9), as
applicable. These revisions will allow owners and operators of onshore
petroleum and natural gas production or onshore petroleum and natural
gas gathering and boosting facilities to use facility measurement data
in their emission calculations for compressors, consistent with section
II.B. of this preamble.
The EPA is finalizing, with a revision from proposal, requirements
under subpart W in 40 CFR 98.233(o)(10) and 40 CFR 98.233(p)(10) for
compressors subject to the final standards in NSPS OOOOb or standards
in an applicable approved state plan or applicable Federal plan
codified in 40 CFR part 62, which are necessary due to the different
scope and purpose of the GHGRP subpart W provisions compared to the
final standards in NSPS OOOOb and the finalized presumptive standards
in EG OOOOc. The EPA is finalizing as proposed that reporters
conducting measurements of compressors under NSPS OOOOb or the
applicable approved state plan or applicable Federal plan in 40 CFR
part 62 must conduct measurements of all other compressor sources
required to be measured by subpart W (based on the compressor mode (as
defined in 40 CFR 98.238) in which the compressor was found at the time
of measurement) specified in 40 CFR 98.233(o)(1) or 40 CFR
98.233(p)(1), using methods specified in 40 CFR 98.233(o)(2) through
(5) or 40 CFR 98.233(p)(2) through (5), as applicable, and calculating
emissions as specified in 40 CFR 98.233(o)(6) through (9) or 40 CFR
98.233(p)(6) through (9), as applicable.
Because the time between measurements under the final standards in
NSPS OOOOb and the final presumptive standards in EG OOOOc may not
result in measurements being taken every reporting year, the EPA is
finalizing as proposed the requirement to use equation W-22 or equation
W-27, as applicable, to calculate emissions from all mode-source
combinations for any reporting year in which measurements are not
required.
As discussed at proposal, the final standards in NSPS OOOOb and the
finalized presumptive standards in EG OOOOc only require measurements
to be taken in operating-mode or standby-pressurized-mode. If no
compressor sources are measured in not-operating-depressurized-mode,
reporters would not have data to develop reporter emission factors for
that mode-source combination using equation W-23 and equation W-28. The
EPA proposed in 40 CFR 98.233(o)(10)(i)(B) and 40 CFR
98.233(p)(10)(i)(B) that reporters with compressors subject to NSPS
OOOOb or the applicable approved state plan or applicable Federal plan
in 40 CFR part 62 would be required to conduct additional measurements
of compressors in not-operating-depressurized-mode such that they can
develop an annual reporter emission factor for isolation valve leakage
in not-operating-depressurized-mode.
The main revision to the proposed amendments for compressors in the
onshore petroleum and natural gas production and onshore petroleum and
natural gas gathering and boosting industry segments is the removal of
the aforementioned requirement to conduct measurements of compressors
in not-operating-depressurized-mode on a regular basis. We received
many comments suggesting the requirement was overly burdensome and
difficult to implement. After consideration of public comment, the EPA
is not finalizing the requirement to conduct additional measurements of
compressors in not-operating-depressurized-mode. Instead, the final
[[Page 42156]]
amendments only require measurements in not-operating-depressurized
mode if the compressor is in not-operating-depressurized mode at the
time of measurement, making the annual measurements of compressors in
the Onshore Petroleum and Natural Gas Production and Onshore Petroleum
and Natural Gas Gathering and Boosting industry segments true ``as
found'' measurements.
For facilities in the Onshore Petroleum and Natural Gas Production
and Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments that do not conduct measurements, we are finalizing language
at 40 CFR 98.233(o)(10) and (p)(10) for compressors at Onshore
Petroleum and Natural Gas Production or Onshore Petroleum and Natural
Gas Gathering and Boosting facilities, consistent with section II.B. of
this preamble. The compressor emission factors for these industry
segments are specific to uncontrolled wet seal oil degassing vents on
centrifugal compressors and uncontrolled rod packing emissions for
reciprocating compressors. The language in 40 CFR 98.233(o) and (p)
clearly indicates that the provisions of 40 CFR 98.233(o)(10) and
(p)(10) do not apply for controlled compressor sources. Therefore, we
are finalizing as proposed minor revisions to 40 CFR 98.233(o)(10) and
the corresponding reporting requirements in 40 CFR 98.236(o)(5) to
clarify that the compressor count used in equation W-25A should be the
number of centrifugal compressors with atmospheric (i.e., uncontrolled)
wet seal oil degassing vents. Similarly, we are finalizing minor
revisions to 40 CFR 98.233(p)(10) and the corresponding reporting
requirements in 40 CFR 98.236(p)(5) to clarify that the compressor
count used in equation W-29D should be the number of reciprocating
compressors with atmospheric (i.e., uncontrolled) rod packing
emissions. We are also finalizing as proposed additional requirements
to report the total number of centrifugal compressors at the facility
and the number of centrifugal compressors that have wet seals to 40 CFR
98.236(o)(5) and additional requirements to report the total number of
reciprocating compressors at the facility to 40 CFR 98.236(p)(5). These
additional data provide the EPA with an improved understanding of the
total number of compressors and the number of compressors that are
controlled (i.e., routed to flares, combustion, or vapor recovery
systems) in the Onshore Petroleum and Natural Gas Production and
Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments, consistent with section II.C. of this preamble.
In addition, consistent with section II.B. of this preamble, and
after consideration of public comment, the EPA is finalizing the
proposed CH4 and CO2 population emission factors
in equation W-29E, while also allowing for adjustment of total
operating time and mole fraction of CH4 and CO2.
As discussed at proposal, the reciprocating compressor population
emission factor for CH4 is based on the average population
emission rate measured by Zimmerle et al. (2019), with a CO2
population emission factor derived by applying the ratio of the current
CO2 emission factor to the current CH4 emission
factor to the CH4 emission factor obtained from Zimmerle et
al. (2019).
After consideration of public comments and review of the proposal,
the EPA is finalizing a few additional changes related to reciprocating
compressors. First, a new equation W-29E has been added to subpart W to
calculate emissions from each reciprocating compressor at an onshore
petroleum and natural gas production facility or an onshore petroleum
and natural gas gathering and boosting facility for which 40 CFR
98.233(p)(10)(i) does not apply and for which the facility does not
elect to conduct the volumetric measurements specified in 40 CFR
98.233(p)(1), using the final emission factors and allowing for
adjustment of total operating time and mole fraction of CH4
and CO2. Second, equation W-29D has been revised to
calculate total emissions from all reciprocating compressors at an
onshore petroleum and natural gas production facility or an onshore
petroleum and natural gas gathering and boosting facility for which 40
CFR 98.233(p)(10)(i) does not apply and for which the facility does not
elect to conduct the volumetric measurements specified in 40 CFR
98.233(p)(1), as a sum of all reciprocating compressor emissions
calculated using equation W-29E.
These changes were made in response to a public comment asking to
allow adjustment of total operating time and mole fraction of
CH4 and CO2 in the calculation of emissions from
reciprocating compressors. As proposed, equation W-29D only allowed for
the use of the count of total reciprocating compressors used at either
an onshore petroleum and natural gas production facility or an onshore
petroleum and natural gas gathering and boosting facility multiplied by
the emission factor. Adjustment for total compressor operating time and
specific mole fractions of CH4 and CO2 is made on
a compressor-specific basis. Therefore, in the final rule, equation W-
29E calculates CH4 and CO2 emissions from each
reciprocating compressor at either an onshore petroleum and natural gas
production facility or an onshore petroleum and natural gas gathering
and boosting facility (allowing for adjustment to reflect actual
operating time and CH4 and CO2 mole fractions
associated with each compressor) and equation W-29D calculates total
CH4 and CO2 emissions from all reciprocating
compressors at either an onshore petroleum and natural gas production
facility or an onshore petroleum and natural gas gathering and boosting
facility using individual compressor emissions determined for each
reciprocating compressor according to equation W-29E. These revisions
allow for the incorporation of unit-specific data and are expected to
increase the accuracy of the calculated compressor emissions,
consistent with section II.B. of this preamble.
Additionally, corresponding changes were made for centrifugal
compressors. Even though this change was not requested by commenters,
the change was made for equitable treatment of both types of
compressors. First, a new equation W-25B has been added to subpart W to
calculate emissions from each centrifugal compressor at an onshore
petroleum and natural gas production facility or an onshore petroleum
and natural gas gathering and boosting facility for which 40 CFR
98.233(o)(10)(i) does not apply and for which the facility does not
elect to conduct the volumetric measurements specified in 40 CFR
98.233(o)(1), using the emission factors and allowing for adjustment of
total operating time and mole fractions of CH4 and
CO2. Second, equation W-25A has been revised (and renamed
from equation W-25) to calculate total emissions from all centrifugal
compressors at an onshore petroleum and natural gas production facility
or an onshore petroleum and natural gas gathering and boosting facility
for which 40 CFR 98.233(o)(10)(i) and (ii) do not apply, as a sum of
all centrifugal compressor emissions calculated using equation W-25B.
Paragraphs 40 CFR 98.233(o)(10)(iii) and 98.233(p)(10)(iii) were
revised and new paragraphs 40 CFR 98.233(o)(10)(iv) and
98.233(p)(10)(iv) were added to incorporate these revisions.
[[Page 42157]]
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments related to Onshore Petroleum and Natural Gas
Production or Onshore Petroleum and Natural Gas Gathering and Boosting
measurement methods.
Comment: Multiple commenters disagreed with the proposed amendments
to 40 CFR 98.233(o)(10)(i)(B) and 40 CFR 98.233(p)(10)(i)(B) to require
reporters with compressors subject to NSPS OOOOb or the applicable
approved state plan or applicable Federal plan in 40 CFR part 62 to
conduct additional measurements of compressors in not-operating-
depressurized-mode, such that they can develop an annual reporter
emission factor for isolation valve leakage in not-operating-
depressurized-mode. The proposed amendments the commenters disagreed
with would require reporters to measure emissions in not-operating-
depressurized mode from isolation valve leakage for at least one-third
of the subject compressors during any 3 consecutive calendar year
period.
According to one commenter, compressors used in production and
gathering and boosting are rarely unpressurized while remaining at a
specific location. When the compressors are no longer needed at a
specific site, the commenter stated that the compressors are shut down
and moved to another location. Another commenter noted that gathering
and boosting facilities typically have very few compressors per site
and they are generally running continuously. Not-operating-
depressurized mode is an uncommon mode, so requiring a measurement in
that mode is unnecessary and could lead to higher emissions, especially
if a compressor is shut down to meet this requirement and there is an
unexpected critical need for the compressor to be operating.
Response: After consideration of public comment, the EPA is not
finalizing the proposed changes to require compressor measurements in
not-operating-depressurized mode such that at the end of each calendar
year, reporters have taken measurements in not-operating-depressurized-
mode over the last 3 consecutive calendar years for at least one-third
of the compressors at the facility. Preemptively requiring a
measurement in not-operating-depressurized mode, especially if
compressors in the industry segments are rarely in this mode, appears
to be an unnecessary requirement. The main reason to require this
measurement is to ensure that reporters have a way to estimate
emissions in not-operating-depressurized mode when measurements are not
available (i.e., the reporter can use measurements from other years to
determine an average emission factor). If compressors in these industry
segments are rarely in this mode, an average emission factor is not
needed. Reporters who elect to conduct the volumetric emission
measurements specified in 40 CFR 98.233(o)(10)(ii) or 40 CFR
98.233(p)(10)(ii) will conduct as-found compressor measurements.
Measurements in not-operating-depressurized mode will only be required
if the compressor is in not-operating-depressurized mode at the time of
measurements. If the dataset from these reporters shows a high instance
of not-operating-depressurized mode measurements from compressors at
onshore petroleum and natural gas production and onshore petroleum and
natural gas gathering and boosting facilities than indicated by the
commenters, the EPA may reconsider this requirement in future
rulemakings.
Comment: One commenter noted that equation W-29D in 40 CFR
98.233(p) does not allow for adjustment based on gas composition. Due
to the wide variety in the composition of gas produced from different
basins and formations across the U.S., the commenter asked that the
emission factor method allow for adjustment based on CO2 and
CH4 composition reflective of each compressor. The commenter
noted that composition adjustment of Emission Factor-based calculations
is allowed under subpart W for pneumatic devices, pneumatic pumps, and
equipment leaks.
The commenter also noted that equation W-29D in 40 CFR 98.233(p)
does not allow for adjustment based on the number of hours a compressor
operates during a calendar year. The commenter noted that compressors
can be moved on and off location during a year. The commenter stated
that assuming the compressor operated for the entire year could result
in inaccurate data. The commenter noted that adjustment of operating
hours is allowed under subpart W for pneumatic devices, pneumatic
pumps, and equipment leaks and improves the accuracy of the emissions
estimated.
Response: The EPA reviewed the comments and agreed that changes to
allow adjustment of operating hours and pollutant mole fractions when
applying the CH4 and CO2 emission factors to
compressors at onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting facilities were
warranted. These types of adjustments are already allowed for pneumatic
devices, pneumatic pumps, and equipment leaks. Allowing this type of
flexibility improves the emissions calculation methodology for
compressors, consistent with section II.B. of this preamble, and also
improves the accuracy of the emissions estimated from compressors at
onshore petroleum and natural gas production and onshore petroleum and
natural gas gathering and boosting facilities.
4. Compressors Routed to Controls
The EPA is finalizing several revisions related to centrifugal and
reciprocating compressors routed to controls as described in this
section. The EPA received only minor comments regarding centrifugal and
reciprocating compressors routed to controls. See the document Summary
of Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems
under the Greenhouse Gas Reporting Rule in Docket ID. No. EPA-HQ-OAR-
2023-0234 for these comments and the EPA's responses.
Centrifugal and reciprocating compressors are the only sources for
which capture for fuel use and thermal oxidizers currently are
specifically listed as dispositions for emissions that would otherwise
be vented (see 40 CFR 98.233(o) and (p) introductory text). The EPA's
intent with the provisions is to differentiate flares, which are
combustion devices that combust waste gases without energy recovery
(per 40 CFR 98.238), from combustion devices with energy recovery,
including for fuel use. However, some thermal oxidizers combust waste
gases without energy recovery and therefore may instead meet the
subpart W definition of flare. Consistent with section II.D. of this
preamble, in order to clarify and emphasize that the EPA's intent is
generally to treat emissions routed to flares and combustion devices
other than flares consistently, we are finalizing as proposed removal
of the references to fuel use and to thermal oxidizers in 40 CFR
98.233(o) and (p) and 40 CFR 98.236(o) and (p). Also, we are finalizing
as proposed to define ``routed to combustion'' in 40 CFR 98.238 to
specify the types of non-flare combustion equipment for which reporters
would be expected to calculate emissions. In particular, for the
Onshore Petroleum and Natural Gas Production, Onshore Petroleum and
Natural Gas Gathering and Boosting, and Natural Gas Distribution
industry segments,
[[Page 42158]]
``routed to combustion'' means the combustion equipment specified in 40
CFR 98.232(c)(22), (i)(7), and (j)(12), respectively (i.e., the
combustion equipment for which emissions must be calculated per 40 CFR
98.233(z)). For all other industry segments, ``routed to combustion''
means the stationary combustion sources subject to subpart C. The final
definition of ``routed to combustion'' applies for all subpart W
emission sources for which that term appears (e.g., natural gas driven
pneumatic pumps).
5. Reporting of Compressor Activity Data
The EPA is finalizing as proposed several amendments to remove
redundancy, consistent with section II.D. of this preamble. The EPA
received only supportive comments regarding revisions to remove
reporting redundancy for centrifugal and reciprocating compressors. See
the document Summary of Public Comments and Responses for 2024 Final
Revisions and Confidentiality Determinations for Petroleum and Natural
Gas Systems under the Greenhouse Gas Reporting Rule in Docket ID. No.
EPA-HQ-OAR-2023-0234 for these comments and the EPA's responses.
We are finalizing the removal of some data elements that are
redundant between 40 CFR 98.236(o)(1) and (2) for centrifugal
compressors and between 40 CFR 98.236(p)(1) and (2) for reciprocating
compressors. Specifically, current 40 CFR 98.236(o)(1)(vi) and 40 CFR
98.236(p)(1)(viii) require reporters to indicate which individual
compressors are part of a manifolded group of compressor sources, and
current 40 CFR 98.236(o)(1)(vii) through (ix) and 40 CFR
98.236(p)(1)(ix) through (xi) require reporters to indicate whether
individual compressors have compressor sources routed to flares, vapor
recovery, or combustion. However, current 40 CFR 98.236(o)(2)(ii)(A)
and 40 CFR 98.236(p)(2)(ii)(A) require the same information for each
compressor leak or vent rather than by compressor. The information
collected for each leak or vent is more detailed and is the information
used for emissions calculations. Therefore, the EPA is finalizing the
removal of the redundant reporting requirements in existing 40 CFR
98.236(o)(1)(vi) through (ix) and existing 40 CFR 98.236(p)(1)(viii)
through (xi), consistent with section II.B. of this preamble.
P. Equipment Leak Surveys
Subpart W reporters are currently required to quantify emissions
from equipment leaks using the calculation methods in 40 CFR 98.233(q)
(equipment leak surveys) and/or 40 CFR 98.233(r) (equipment leaks by
population count). The equipment leak survey method currently uses the
count of leakers detected with one of the subpart W leak detection
methods in 40 CFR 98.234(a), subpart W leaker emission factors, and
operating time to estimate the emissions from equipment leaks. The
current leaker emission factors applicable to onshore petroleum and
natural gas production and onshore petroleum and natural gas gathering
and boosting facilities are found in existing table W-1E to subpart W.
These leaker emission factors are based on the EPA's Protocol for
Equipment Leak Emission Estimates published in 1995 (Docket ID. No.
EPA-HQ-OAR-2009-0927-0043), also available in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. The leaker emission
factors are provided for components in gas service, light crude
service, and heavy crude service that are found to be leaking via
several different screening methods. In addition to being component-
and service-specific, subpart W currently provides two different sets
of leaker emission factors: one based on leak rates for leaks
identified by Method 21 (see 40 CFR part 60, appendix A-7) using a leak
definition of 10,000 ppm and one based on leak rates for leaks
identified by Method 21 using a leak definition of 500 ppm. Currently,
the other leak screening methods provided in subpart W (OGI, infrared
laser beam illuminated instrument, and acoustic leak detection device)
use the leaker emission factors based on Method 21 data with a leak
definition of 10,000 ppm.
In this final rule, consistent with the 2023 Subpart W Proposal, we
are making several technical changes to the equipment leak survey
provisions for the equipment leak emission source. The key changes
included in this final rule are providing updated and new leaker
emission factors, revising and providing new leaker calculation
methodologies, and providing better alignment with the NSPS OOOOa and
NSPS OOOOb as well as EG OOOOc survey requirements.
1. Revisions and Addition of Default Leaker Emission Factors
a. Summary of Final Amendments
We are finalizing as proposed to amend the leaker emission factors
in existing table W-1E (final table W-2) to subpart W for onshore
petroleum and natural gas production and onshore petroleum and natural
gas gathering and boosting facilities to update the Method 21 emission
factors as well as include separate emission factors for leakers
detected with OGI, consistent with section II.B. of this preamble. We
are finalizing as proposed to revise the emission factors using study
data from Zimmerle et al. (2020) and Pacsi et al. (2019). The Zimmerle
et al. (2020) study contains hundreds of quantified leaks detected
using OGI. The Pacsi et al. (2019) study also contains hundreds of
equipment leak measurements from sites that were screened using Method
21 with a leak definition of 10,000 ppm and 500 ppm as well as OGI. We
are finalizing the use of these studies as the basis for the final
emission factors because they included recent measurements of subpart
W-specified equipment leak components from both oil and gas production
and gathering and boosting sites in geographically diverse locations.
Numerous equipment leak studies,\67\ including Pacsi et al. (2019)
have found that OGI detects fewer leaks that are on average larger in
size than those detected by EPA Method 21. Specifically, the average
leaker emission factor determined from OGI leak detection surveys is
often a factor of two or more larger than leaker emission factors
determined when using Method 21 leak detection surveys. Therefore, the
application of the same leaker emission factor to leaking components
detected with OGI and Method 21 with a leak definition of 10,000 ppm,
as is currently done in subpart W, likely understates the emissions
from leakers detected with OGI. Using the Pacsi et al. (2019) study
data, we estimate that the leaks detected by OGI are 1.63 times larger
than leaks detected by Method 21 at a
[[Page 42159]]
leak definition of 10,000 ppm and 2.81 times larger than leaks detected
by Method 21 at a leak definition of 500 ppm. As noted, the Pacsi et
al. (2019) study provides data on leaks detected by Method 21 at a leak
definition of 10,000 ppm and 500 ppm as well as OGI data, however, the
sample size of leaks screened in the Pacsi et al. (2019) study with
Method 21 is smaller than those screened with OGI, particularly when
combining the OGI data from Pacsi et al. (2019) with the Zimmerle et
al. (2020) data. The combined OGI dataset from Pacsi et al. (2019) and
Zimmerle et al. (2020) contains more than 700 measurements from leaks
detected with OGI. Emission factors using these data are derived for
each combination of well site type (e.g., gas or oil) and component
type (e.g., valve). The more than 700 measurements in the combined OGI
dataset results in an average of 44 measurements for each combination
of well site type (e.g., gas or oil) and component type (e.g., valve).
In contrast, the Pacsi et al. study has nearly 300 measurements for
leaks detected using Method 21 at a leak definition of 500 ppm and 140
measurements for leaks detected using Method 21 at a leak definition of
10,000 ppm, which results in averages of 21 measurements and 10
measurements for each combination of site type and component type,
respectively.
---------------------------------------------------------------------------
\67\See, e.g., ERG (Eastern Research Group, Inc.) and Sage (Sage
Environmental Consulting, LP). City of Fort Worth Natural Gas Air
Quality Study: Final Report. July 13, 2011, available at https://www.fortworthtexas.gov/departments/development-services/gaswells/air-quality-study/final; Allen, D.T., et al. ``Measurements of
methane emissions at natural gas production sites in the United
States.'' Proceedings of the National Academy of Sciences of the
United States of America, Vol. 110, no. 44. pp. 17768-17773, October
29, 2013, available at http://dept.ceer.utexas.edu/methane/study.
Docket ID. No. EPA-HQ-OAR-2014-0831-0006; Pacsi, A. P., et al.
``Equipment leak detection and quantification at 67 oil and gas
sites in the Western United States.'' Elem Sci Anth, 7: 29,
available at https://doi.org/10.1525/elementa.368. 2019; Zimmerle,
D., et al. ``Methane Emissions from Gathering Compressor stations in
the U.S.'' Environmental Science & Technology 2020, 54(12), 7552-
7561, available at https://doi.org/10.1021/acs.est.0c00516. The
documents are also available in the docket for this rulemaking,
Docket ID. No. EPA-HQ-OAR-2023-0234.
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For OGI, we are finalizing leaker emission factors that were
developed using the combined data from Pacsi et al. (2019) and Zimmerle
et al. (2020) by site type (i.e., gas or oil). Equipment leaks are
inherently variable; therefore, sample size is important when seeking
to derive representative equipment leak emission factors. Therefore, in
this final rule, we used the OGI data and the ratio between OGI and the
Method 21 at a leak definition of 10,000 ppm and a leak definition of
500 ppm (i.e., 1.63 and 2.81, respectively) measurements to derive the
final emission factors for Method 21 at both leak definitions. The
precise derivation of the final emission factors is discussed in more
detail in the subpart W TSD, available in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
At onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting facilities, very few
facilities report using infrared laser beam illuminated instruments or
acoustic leak detection devices to conduct equipment leak surveys for
the purposes of subpart W and there are no data available to develop
leaker emission factors specific to these methods. Based on our
understanding and our review of comments received on the 2023 Subpart W
Proposal relative to the use of these alternative methods, we expect
that their leak detection thresholds will be most similar to OGI, so
that the average emissions per leak identified by these alternative
methods will be similar to the emissions estimated using the final OGI
leaker factors. Therefore, we are finalizing as proposed that, if other
leak survey methods including illuminated laser beam or acoustic leak
devices are used to conduct leak surveys, the final OGI leaker emission
factors in final table W-2 to subpart W must be used to quantify the
emissions from the leaks identified using these other monitoring
methods.
For onshore petroleum and natural gas gathering and boosting
facilities, we note that subpart W currently specifies that all
components should be considered to be in gas service consistent with
the language in 40 CFR 98.233(q)(2)(iv); thus, under the final rule the
gas service factors from final table W-2 should be applied to the count
of equipment leak components consistent with the leak detection method
used.
For onshore petroleum and natural gas production facilities, we are
finalizing as proposed to amend 40 CFR 98.233(q)(2)(iii) to state that
onshore petroleum and natural gas production facilities must use the
appropriate default whole gas leaker emission factors consistent with
the well type (rather than the component-level service type), where
components associated with gas wells are considered to be in gas
service and components associated with oil wells are considered to be
in oil service as listed in final table W-2 to subpart W. After
consideration of comments received on the proposed rule as discussed
further in section III.P.1.b. of this preamble, we are also adding
clarifying edits in this final rule to the footnotes of final table W-
2. One of these edits removes footnote 1, which included a
specification to use the gas service emission factors for multi-phase
flow. This footnote 1 no longer applies. Consistent with the derivation
of the default leaker emission factors, the default leaker emission
factors must be applied by site type for onshore petroleum and natural
gas production facilities, while onshore petroleum and natural gas
gathering and boosting sites must use the gas service default leaker
emission factors. The edits also clarify that the default leaker
emission factors for the open-ended line (OEL) component type includes
the blowdown valve and isolation valve leaks when using the population
count emission factor approach specified in 40 CFR 98.233(o)(10)(iv) or
(p)(10)(iv).
As described previously, our analysis of measurement study data
from onshore production and gathering and boosting facilities
demonstrates that the OGI screening method finds fewer and larger leaks
in terms of emission rate than EPA Method 21 (i.e., each screening
method finds a different, but overlapping, subset of the existing
leaks). Consequently, the leaker emission factors derived using
measurement data from the OGI screening method are larger than those
derived using the measurement data from Method 21 screening method. We
expect that the leaker emission factors for other industry segments
that are based on measurements of Method 21-identified leaks may
similarly underestimate the emissions from leaking equipment when OGI
(or other alternative methods besides Method 21) are used to detect the
leaks. We are finalizing as proposed the application of the ratio
between OGI data and Method 21 at a leak definition of 10,000 ppm
identified from the Pacsi et al. (2019) study data in the onshore
production and gathering and boosting industry segments, a value of
1.63, to the leaker emission factors for the other subpart W industry
segments as a means to estimate and finalize a separate OGI emission
factor set. Analogous to the changes in final table W-2 to subpart W
for the Onshore Petroleum and Natural Gas Production and Onshore
Petroleum and Natural Gas Gathering and Boosting industry segments,
this results in the addition of final emission factor sets specific to
OGI, infrared laser beam illuminated instrument, or acoustic leak
detection device screening methods. The final emission factor sets are
included in tables W-4 and W-6 for the Onshore Natural Gas Processing,
Onshore Natural Gas Transmission Compression, Underground Natural Gas
Storage, LNG Storage, LNG Import and Export Equipment, and Natural Gas
Distribution industry segments. A detailed description of the final
emission factors is provided in the subpart W TSD, available in the
docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. After
consideration of comments, we are finalizing updated provisions to
those proposed to provide that facilities reporting to the Onshore
Natural Gas Transmission Compression or Underground Natural Gas Storage
industry segments may use the concentration of CH4 or
CO2 in the THC of the feed natural gas in lieu of the
default concentrations provided in
[[Page 42160]]
equation W-30 when quantifying equipment leak emissions using
Calculation Method 1. The use of facility-specific composition data for
the concentration of CH4 or CO2 in the THC feed
of natural gas instead of using default values is expected to increase
the accuracy of the emission estimates.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to the equipment leak survey default leaker
emission factors.
Comment: Commenters noted that there were inconsistencies with the
preamble to the 2023 Subpart W Proposal as well as proposed 40 CFR
98.233(q)(2)(iii) and (iv) and the footnote 1 to table W-2 to subpart
W, which says, ``For multi-phase flow that includes gas, use the gas
service emission factors.'' In the preamble to the 2023 Subpart W
Proposal and in the proposed regulatory text, it says that emission
factors should be applied by well site type for production facilities,
where components at gas wells are considered to be in gas service and
components at oil wells are considered to be in oil service. The
proposed rule also provided that components at gathering and boosting
sites should be considered to be in gas service. Further, commenters
requested that the EPA clarify in footnote 2 to table W-2 that if an
entity elects to use as-found measurements to estimate emissions from
isolation valve and blowdown valve leakage, that leaks detected from
these sources should be calculated pursuant to paragraph (p) or (o)
rather than paragraph (q). Finally, commenters requested that the EPA
clarify in footnote 2 to table W-2 how dry seal vents are intended to
be reported when a gathering and boosting or processing site elects to
use population emission factors for compressor venting.
Response: We agree with commenters that our intent, which is
consistent with the derivation of the default leaker emission factors,
is for production facilities to apply component-level emission factors
based on the well site type and for components at gathering and
boosting facilities to use the gas service default leaker emission
factors. The reference to footnote 1 in the context of default leaker
factors in final table W-2 to subpart W has been removed. We also agree
with the commenters that clarification is needed in footnote 2 and have
edited the footnote in the final rule to state that the OEL component
type includes the blowdown valve and isolation valve leaks when using
the population count emission factor approach specified in 40 CFR
98.233(o)(10)(iv) or (p)(10)(iv). Finally, in response to the request
for clarification regarding dry seals, we note that there is no
emission factor for dry seals in the existing rule, which is unchanged
by this final rulemaking, and thus emissions associated with dry seals
are not required to be reported.
Comment: Commenters requested that the EPA allow the use of annual
average GHG mole fraction GHGi in equations W-30 and W-32A as allowed
in equation W-1A for natural gas pneumatic devices. Commenters
explained that this would better align equipment leak calculations with
other calculations of subpart W and be consistent with the initiative
of capturing empirical data.
Response: We agree with the commenter's suggestion to allow for the
use of the actual concentration of CH4 or CO2 in
the calculation of equipment leak emissions in 40 CFR 98.233(q) and (r)
as we expect that when utilized the accuracy of the resulting emissions
will increase. Therefore, we are finalizing amendments to the variable
for the concentration of greenhouse gases, GHGi, in the definition of
the variables for equations W-30 and W-32A to provide the option of
using the existing default concentrations or the actual concentration
of methane or carbon dioxide in the THC of the feed natural gas.
Comment: Several commenters opposed the separate OGI default leaker
emission factors and noted that the derived emission factors are much
higher for this leak survey method than for EPA Method 21. Other
commenters expressed support for the separate OGI default leaker
emission factors and stated that they believe the resulting emissions
estimates will be more accurate.
Commenters opposing the separate OGI default leaker emission
factors asserted that their inclusion disincentivizes the use of OGI.
Commenters note that OGI was determined to be the best system for
emission reductions (BSER) in the NSPS OOOOb and EG OOOOc rules, yet
the proposed default leaker emission factors would penalize its use for
emissions reporting. Commenters note that there were other sources of
equipment leak data that could be considered when developing leaker
emission factors including annual leak reports from the state of
Colorado or the Environmental Partnership. Some commenters noted that
the Pacsi et al. (2019) study was limited to four geographical regions,
a single OGI camera make and model, and did not consider operator
training. Another commenter stated that the Pacsi et al. (2019) study
concluded, ``The most common EPA estimation method for greenhouse gas
emission reporting for equipment leaks, which is based on major site
equipment counts and population-average component emission factors,
would have overestimated equipment leak emissions by 22 percent to 36
percent for the sites surveyed in this study as compared to direct
measurements of leaking components because of a lower frequency of
leaking components in this work than during the field surveys conducted
more than 20 years ago to develop the current EPA factors.'' Some
commenters stated that the EPA has selectively updated certain emission
factors to inflate emissions in response to the Inflation Reduction Act
and fiscal implications for oil and gas companies. Commenters
recommended that the EPA maintain the OGI and Method 21 with a leak
definition of 10,000 ppm default leaker emission factor set currently
in the rule.
Commenters also opposed the use of the ``OGI enhancement factor,''
which was a ratio of the average leak rate size surveyed using OGI to
EPA Method 21 to provide the updated Method 21 default leaker emission
factors for onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting industry segments.
Response: The proposed default leaker emission factors for the
onshore natural gas production and onshore gathering and boosting
facilities are based on the combination of data from publicly available
and peer reviewed studies including the Pacsi et al. (2019) and
Zimmerle et al. (2020) studies. The combined OGI dataset from Pacsi et
al. (2019) and Zimmerle et al. (2020) contains more than 700
measurements from leaks detected with OGI. We derived OGI emission
factors by site type (i.e., gas or oil) directly from the combination
of these data. The Pacsi et al. (2019) dataset includes equipment leaks
surveyed with Method 21 at both leak definitions, but the sample sizes
are smaller. Thus, we derived the ratio between OGI and the Method 21
at a leak definition of 10,000 ppm and a leak definition of 500 ppm
(i.e., 1.63 and 2.81, respectively) and applied the ratio to the OGI
emission factors to derive the proposed emission factors for Method 21
at both leak definitions. The derivation of the separate emission
factor sets seeks to utilize the most robust dataset of publicly
available data to develop these separate leaker emission factors,
consistent with findings in multiple studies that the
[[Page 42161]]
average size of the leaks detected by OGI are larger than those
detected by EPA Method 21. This approach is not intended to
disincentivize any survey method and, furthermore as discussed below,
our expectation is that the approach finalized in this rulemaking will
yield similar equipment leak emission estimates regardless of the
selected method. We maintain that the separate OGI emission factors are
appropriate, accurate, and based on the best available data and we are
finalizing them, as proposed.
Commenters mentioned that thousands of equipment leaks were
reported to the state of Colorado. We have reviewed the data from the
state of Colorado that are publicly available, and agree that many more
leaks were reported statewide than are detected/measured in the Pacsi
et al. (2019) and Zimmerle et al. (2020) studies. Similarly, we have
reviewed the data from the Environmental Partnership that are publicly
available and find this it could be useful for understanding leak
incident rate for member companies. However, the publicly available
data from Colorado and the Environmental Partnership do not contain the
necessary data to derive an emission factor as provided in the Pacsi et
al. (2019) and Zimmerle et al. (2020) studies used by the EPA
including: component-level leak rates, major equipment, site level
information, survey method, quantification method, and leak rate.
Additionally, we note that some commenters appear to be
misrepresenting conclusions from the Pacsi et al. (2019) by stating
that the existing default method would overestimate the emissions by 22
to 36 percent and this does not support updated leaker emission
factors. We note that in this conclusion presented in the Pacsi et al.
(2019) study, study authors are comparing the existing population count
method results to the study results--not comparing the results of the
subpart W leaker method with the study results.
As described in this preamble, the purpose of the OGI enhancement
factor is to ensure that irrespective of the survey method, the
resulting emissions estimated using the default leaker emission factors
represent the emission inventory total as there are inherent
differences in the leaks detected when using different survey methods.
We have undertaken additional analysis to demonstrate that the final
emission factors for Method 21 at a leak definition of 500 ppm, Method
21 at a leak definition of 10,000 ppm, and the OGI emission factors and
the survey method specific undetected leak factors successfully
estimate the study emissions total. The details of this analysis are
presented in the Greenhouse Gas Reporting Rule: Technical Support for
Revisions and Confidentiality Determinations for Data Elements Under
the Greenhouse Gas Reporting Rule; Final Rule--Petroleum and Natural
Gas Systems, which is available in the docket for this rulemaking
(Docket ID No. EPA-HQ-OAR-2023-0234). In summary, the analysis uses the
Pacsi et al. (2019) activity data (i.e., number of leakers by site
type, component type, and survey method) with the final emission
factors and undetected leak factor to estimate emissions. The analysis
demonstrates that using the proposed emission factors and the
undetected leak factor yield emissions that are between 1 and 10
percent of the study total emissions for all survey methods. This
analysis supports the use of these factors, and as discussed elsewhere
in the preamble to the final rule and in the document Summary of Public
Comments and Responses for 2024 Final Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems under the
Greenhouse Gas Reporting Rule (available in Docket ID. No. EPA-HQ-OAR-
2023-0234), the use of the undetected leak factors.
Concerning comments about OGI being determined as BSER for the
NSPS, we note that BSER determinations consider technical feasibility,
cost, non-air quality health and environmental impacts, and energy
requirements. To further the programmatic goals of subpart W, we
considered the best available data by which to derive default emission
factors to ensure accuracy of the resulting emissions calculations. We
find that the purposes of the NSPS and subpart W are inherently
different, as one is a standard setting program while the other is a
reporting program. Thus, while the determination that OGI is BSER for
the NSPS may influence facilities' decision to utilize this method, it
does not have bearing on how emissions are quantified under this
reporting program.
Comment: Commenters noted that the Zimmerle et al. (2020) study
showed that emissions from compressor type components have higher leak
rates due to vibration. Commenters noted that the EPA did not
distinguish between components associated with or not with compressors
in its development of the default leaker emission factors. As a
consequence, the average proposed emission factors seem to include
compressor-related components, which would overstate emissions from the
non-compressor related components. Commenters requested that the EPA
carefully review the emission factors and consider including compressor
related components in the breakdown of the leaker factors.
Response: We agree with commenters that the average leak sizes in
the Zimmerle et al. (2020) and Pacsi et al. (2019) studies were larger
for components associated with compressor major equipment. As described
previously, the default leaker emission factors were derived by
component type (e.g., valves), site type (i.e., gas or oil), and survey
method (e.g., OGI) and as noted by commenters did not consider the
component's association with compressor or non-compressor equipment. In
order to evaluate the impact of considering the association with
compressor or non-compressor equipment in the development of default
leaker emission factors, we conducted additional analysis. The Zimmerle
et al. (2020) and Pacsi et al. (2019) studies both include attribution
of leak measurements to major equipment categories (i.e., compressor,
non-compressor, tank) or to major equipment (e.g., compressor, flare,
separator), respectively. Therefore, we have utilized this study
reported information to further disaggregate our proposed default
leaker emission factors into compressor and non-compressor emission
factor sets such that the resulting factors are by component type, site
type, survey method, and whether they are associated with a compressor
or non-compressor, as appropriate. We then applied these emission
factors to the Pacsi et al. (2019) study activity data (i.e., number of
leakers by site type, component type, survey method, and association
with compressor or non-compressor major equipment) and undetected leak
factor to estimate emissions. The analysis demonstrates that using the
compressor and non-compressor emission factors and the undetected leak
factor yield emissions that are between 3 and 14 percent lower than the
study total emissions for all survey methods. As noted in the previous
comment/response in this section of the preamble, we performed an
analogous analysis using the proposed default leaker emission factors
and found that the estimated emissions were between 1 and 10 percent of
the study total. Therefore, the use of the separate compressor and non-
compressor emission factors did not result in improved accuracy and
tends to further underestimate the emissions when compared to the use
of the proposed emission factors. The details
[[Page 42162]]
of this analysis are presented in the Greenhouse Gas Reporting Rule:
Technical Support for Revisions and Confidentiality Determinations for
Data Elements Under the Greenhouse Gas Reporting Rule; Final Rule--
Petroleum and Natural Gas Systems, which is available in the docket for
this rulemaking (Docket ID No. EPA-HQ-OAR-2023-0234). We suspect that
one reason the separate compressor and non-compressor emission factors
do not perform better than the proposed factors is due to the further
disaggregation of the leak survey and measurement data from the
underlying datasets eroding the sample size that informs the emission
factors. This means that any accuracy that may be gained by
disaggregating emission factors into compressor or non-compressor
categories is offset by the reduction in sample size for the
development of such a factor. Based on the results of this analysis, we
are finalizing the default leaker factors based on component type, site
type, and survey method only basis, as proposed.
Comment: Commenters stated that they could not determine how the
proposed default leaker emission factors for onshore petroleum and
natural gas production and onshore petroleum and natural gas gathering
and boosting had been developed. Specifically, one commenter performed
a side-by-side comparison of the default leaker emission factors in the
Zimmerle et al. (2020) and Pacsi et al. (2019) studies and those
included in the 2023 Subpart W Proposal, noting that they could not
match the values.
Response: A detailed explanation and tables were included in the
TSD for the proposed rule explaining how the emission factors were
derived. We note that the Zimmerle et al. (2020) study provided
separate emission factors for compressor and non-compressor components
and as noted in the previous response and explained in the TSD, the EPA
has combined all of the Zimmerle et al. (2020) data with the Pacsi et
al. (2019) data to develop the OGI emission factor set. We also note
that we consider the Zimmerle et al. (2020) data to be for gas sites
only, consistent with the categorization of onshore petroleum and
natural gas gathering and boosting equipment in subpart W. We used the
study reported site type (e.g., oil or gas) in the Pacsi et al. (2019)
data to determine the service type for the purposes of aggregating data
by site type when developing the default leaker emission factors. So,
there may be differences in the precise values because of the
assumptions made when combining the study data for the purposes of
developing emission factors by component and site type. However, we
find that the study published emission factors are in general agreement
with those derived by the EPA and our assumptions regarding the
aggregation of data are documented in the Greenhouse Gas Reporting
Rule: Technical Support for Revisions and Confidentiality
Determinations for Data Elements Under the Greenhouse Gas Reporting
Rule; Final Rule--Petroleum and Natural Gas Systems, which is available
in the docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2023-0234).
Comment: Commenters stated that the proposed revisions to leaker
emission factors are based on studies for OGI at onshore production and
gathering and boosting facilities and are not relevant to midstream
(e.g., transmission compression, underground storage) or downstream
(e.g., natural gas distribution) sources. Commenters added that the
creation of the OGI enhancement factor is not reasonable and is not
based on technical data supporting applicability to sources downstream
of the onshore production and gathering and boosting facilities. Some
commenters recommended that the current OGI leaker emission factors
should be retained, as applicable, since it is inappropriate to apply
an ``enhancement'' based on analysis of a small dataset from the
upstream segment that includes significant disparities in both the
operation of equipment (e.g., pressure, CH4 content) and
leak detection environment (e.g., wind conditions). Other commenters
recommended that the EPA should consider additional prospective studies
and data gathered using OGI and other leak testing methods in other
segments of the natural gas supply chain and recommended that the EPA
reconsider the OGI enhancement factors and, if appropriate, re-propose
them in the future when more data are available.
Response: As demonstrated in the record, we have long contemplated
and evaluated study data that demonstrates that there are
methodological differences that result in the average leak detected by
OGI being higher in magnitude than the leaks detected using Method 21.
During the 2016 leaker rule amendments we evaluated a number of studies
for equipment leaks in order to inform emission factor updates (see the
2016 TSD; Docket ID. No. EPA-HQ-OAR-2015-0764-0066). These studies
included:
City of Fort Worth Natural Gas Air Quality Study (ERG and
Sage, 2011);
Measurements of Methane Emissions at Natural Gas
Production Sites in the United States, Supporting Information (Allen et
al., 2013);
Methane Emissions from Natural Gas Compressor Stations in
the Transmission and Storage Sector: Measurements and Comparisons with
the EPA Greenhouse Gas Reporting Program Protocol (Subramanian et al.,
2015).
In the 2016 TSD, we identified, analyzed and discussed the overall
finding that equipment leaks detected with OGI were higher than those
detected using Method 21. For reference, a summary of our analyses and
conclusions at the time are included here:
For onshore production and gathering and boosting, we
compared the data in the 2011 Fort Worth study (ERG and Sage, 2011) and
Allen et al. (2013) studies, which are OGI-based fugitive emissions
studies and which appear to yield higher leaker emission factors than
the EPA Method 21-based data presented in the 1995 EPA Protocol (the
basis for the existing subpart W leaker emission factors for Onshore
Production and Gathering and Boosting). In order to better understand
the variability in leaker emission factors from different studies, we
conducted Monte Carlo analyses using the study data. Based on these
analyses, random samples of 30 leaking components can be expected to
yield average leaker emission factors that vary by a factor of 2 to 3
and samples of 100 leaking components can expected to yield average
leaker emission factors that vary by a factor 1.5 to 2. Although this
does not directly show that OGI-determined leaker emission factors are
necessarily different than EPA Method 21-determined leaker emission
factors, if leak rate variability were the only reason for the
differences in leaker emission factors, we would expect that the EPA
Method 21 leaker emission factors would be higher than the OGI leaker
emission factors approximately 50 percent of the time. The fact that
the OGI leaker emission factors are consistently higher than the EPA
Method 21 leaker emission factors (using a leak threshold of 10,000
ppmv) in essentially every case provides evidence that variability
alone does not fully explain the data and that OGI ``visualized'' leaks
are generally larger than leaks that have measured EPA Method 21
concentrations above 10,000 ppmv.
We also discussed seeing similar results for the Onshore
Natural Gas Transmission Compression industry segment. We compared
leaker emission factors derived from OGI-based study (Subramanian et
al., 2015) and the EPA
[[Page 42163]]
Method 21-based study (Clearstone, 2002; Clearstone 2007) conducted at
Onshore Natural Gas Transmission Compression facilities. As shown in
the 2016 TSD, not considering the data where the number of measurements
were 10 or fewer, the OGI-based leaker emission factor was larger than
the EPA Method 21 (at 10,000 ppmv) leaker emission factor for five of
the six components, and the one component (valves on compressors) where
the OGI-based measurement was smaller, the leaker emission factors are
essentially identical. Thus, these data support the conclusions drawn
from the production data. Specifically, OGI-based and EPA Method 21 (at
10,000 ppmv) leaker emission factors usually compare within the
expected range of a values considering the high variability of
individual measurements. Additionally, OGI-based leaker emission
factors are consistently larger than EPA Method 21 (at 10,000 ppmv)
leaker emission factors, suggesting that variability alone does not
explain the differences observed and that the methodological
differences in how leaks are identified are also likely to contribute
to the consistently higher OGI-based leaker emission factors.
Since the 2016 final rule, the EPA has obtained additional data
that demonstrate the same finding--that OGI detects larger leaks than
EPA Method 21. First, we note that gathering and boosting sites could
be considered similar to transmission compression sites in that they
have many compressors and associated pipeline connections. As described
in the subpart W 2023 proposed rule TSD, the Zimmerle et al. (2020)
study was performed at gathering and boosting sites where OGI surveys
were performed to detect leaks, which were then quantified. When
comparing the leaker emission factors developed using the Zimmerle et
al. (2020) study to those in the existing subpart W for Method 21 at
either leak definition, the OGI leaker emission factors are higher for
all component types. On the basis of the similarities in operating
equipment between gathering and boosting sites and transmission
compression sites and the observations of average leak sizes in the
Zimmerle et al. (2020) data as compared to Method 21, we continue to
expect that these findings apply across the supply chain.
Further, the Pacsi et al. (2019) study that compared OGI and Method
21 side-by-side at multiple production and gathering and boosting sites
supports the conclusion that OGI and Method 21 detect different
populations of leakers, and that generally OGI detects larger leaks.
Considering our past review of this issue, including reviewing data
specific to midstream industry segments, and the additional data we
have obtained since the 2016 final rule, we are promulgating, as
proposed, separate OGI emission factors for all industry segments that
are required or elect to quantify emissions using the leaker method.
2. Addition of Undetected Leak Factor for Leaker Emission Estimation
Methods
a. Summary of Final Amendments
Subpart W currently provides various screening methods for
detecting leaking components in 40 CFR 98.234(a). Each method includes
a unique instrument and associated procedure by which leaks are
detected. Variability inherently exists in each method's ability to
detect leaks, which can be attributed to reasons associated with the
instrument, leak detection procedures, the operator or site conditions.
For the 2023 Subpart W Proposal, we reviewed recent study data from
Pacsi et al. (2019) in which multiple leak detection methods, including
OGI and Method 21, were deployed alongside one another at the same
sites. This study demonstrates that there are undetected leaks for each
method. Based on the Pacsi et al. (2019) study data, OGI observes 80
percent of emissions from measured leaks, Method 21 at a leak
definition of 10,000 ppm observes 65 percent of emissions from measured
leaks, and Method 21 at leak definition of 500 ppm observes 79 percent
of emissions from measured leaks. In order to account for the quantity
of emissions that remain undetected by each screening method, we are
finalizing as proposed to provide a method specific adjustment factor,
k, for the calculation methods used to quantify emissions from
equipment leaks using the leaker method in 40 CFR 98.233(q). We are
finalizing as proposed that, if other methods including illuminated
infrared laser beam or acoustic leak detection devices are used to
conduct leak surveys, the final OGI adjustment factor, k, must be used
in the calculation to quantify the emissions from the leaks identified
using these other monitoring methods. The addition of a method specific
adjustment factor under the final rule will improve the accuracy of
emissions data, consistent with section II.B. of this preamble. Further
detail on the development of the adjustment factor for each of these
screening methods is provided in the subpart W TSD, available in the
docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to add an undetected leak factor for the leaker
emission estimation method.
Comment: Some commenters were opposed to the addition of an
undetected leak factor, while others expressed support for the addition
of this factor.
Commenters who were not in favor of the factor stated that
including this factor implies that operators are not making efforts to
comply with leak detection and repair (LDAR) federal and state
regulatory programs. Commenters also stated that instead of imposing an
undetected leak factor, the EPA should emphasize proper training
relative to the survey methods to ensure the accuracy of the survey
results. Some commenters suggested that the EPA remove the undetected
leak factor all together while others recommended that the EPA remove
the adjustment factor when direct measurement is used to quantify
emissions.
Commenters stated that leaks were detected at only five ``boosting
and gathering'' sites included in the Pacsi et al. (2019) study results
that are the basis for the undetected leak factor value and thus,
development of an undetected leak factor does not accurately represent
the entirety of the sector and does not qualify as a statistically
significant dataset of empirical data to apply to reporting facilities
in the Onshore Petroleum and Natural Gas Gathering and Boosting
industry segment.
Similarly, several commenters stated that the undetected leak
factor was developed using data from upstream facilities, which are not
representative of the operating equipment (e.g., pressure,
CH4 content) and leak detection environment (e.g., wind
conditions) in industry segments downstream of the Onshore Petroleum
and Natural Gas Production or Onshore Petroleum and Natural Gas
Gathering and Boosting industry segments. Thus, the undetected leak
factor should not be applied to emission estimates for those industry
segments until such time that sector-specific studies are conducted
that demonstrate the applicability of a such a factor to their
operations.
Some commenters stated that they could not replicate the
calculations the EPA used to estimate the undetected leak factor and
requested that the EPA provide additional information on the
derivation. These commenters also requested that the EPA test their
``k'' factors by applying to the Method 21
[[Page 42164]]
data in order to recalculate the emissions at the site level using
study data and confirm if it matches with the measured emissions.
Response: The undetected leak factor is based off the best
available data where both OGI and Method 21 detection methods were used
and the emissions directly quantified (i.e., the Pacsi et al. (2019)
study). In our review of OGI and Method 21 equipment leak studies, we
note that the performance of the survey method is more aligned with
technological and methodological differences rather than the location
of the equipment or components. As discussed in section III.P.1.b. of
this preamble, when available we have evaluated data of midstream and
downstream segments including direct comparisons of OGI and Method 21
data.
We have undertaken additional analysis regarding the use of
separate OGI emission factors and the undetected leak factor. The
details of this analysis are presented in the Greenhouse Gas Reporting
Rule: Technical Support for Revisions and Confidentiality
Determinations for Data Elements Under the Greenhouse Gas Reporting
Rule; Final Rule--Petroleum and Natural Gas Systems, which is available
in the docket for this rulemaking (Docket ID No. EPA-HQ-OAR-2023-0234).
In summary, the analysis uses the Pacsi et al. (2019) activity data
(i.e., number of leakers by site type, component type, and survey
method) with the final default leaker emission factors and undetected
leak factor to estimate emissions. The analysis demonstrates that using
the final default leaker emission factors and the undetected leak
factor yields emissions that are within 10 percent of the study total
emissions considering leaks identified across all leak survey methods.
This analysis demonstrates that the use of the undetected leak factor
is necessary to scale surveyed emissions to accurately estimate the
actual quantity of emissions in the inventory. We maintain that the use
of the undetected leak factor enhances the accuracy of the emissions
calculation such that they more accurately represent the total
emissions quantity of equipment leaks and we are finalizing the method-
specific undetected leak factors, as proposed.
We note that commenters requested that the EPA compare the
emissions that would be estimated using the final default leaker
emission factors and the undetected leak factor at the site level to
the measured value from the Pacsi et al. (2019) study. Concerning this
request, we note that the default leaker factors are average study-
derived emission factors, and thus we would not expect that the
emissions resulting from applying an average default leaker emission
factor to a single site with a handful of measurements to match.
Equipment leak emissions are highly variable and exhibit lognormal
distribution such that the emissions for a single component leak can be
an order of magnitude or more higher or lower than the average across a
large number of components. The inherent variability in the
measurements means there is more uncertainty when applying an emission
factor, which can be minimized by increasing sample size in the
underlying dataset. In this rule, we provide that surveys must be
conducted and reported at the well site or gathering site level, and
also aggregated at the facility level. Based on our analysis using the
study-level data from Pacsi et al. (2019), we expect the facility-level
aggregation of site level emission estimates to reflect the actual
emissions.
Some commenters noted that the derivation of the undetected leak
factors is unclear. We note that a detailed explanation and tables were
included in the TSD for the proposed rule. In order to increase
transparency in the record, we are providing additional details
regarding derivation in the Greenhouse Gas Reporting Rule: Technical
Support for Revisions and Confidentiality Determinations for Data
Elements Under the Greenhouse Gas Reporting Rule; Final Rule--Petroleum
and Natural Gas Systems, which is available in the docket for this
rulemaking (Docket ID No. EPA-HQ-OAR-2023-0234).
3. Addition of Method To Quantify Emissions Using Direct Measurement
a. Summary of Final Amendments
As an alternative to the final revised default leaker emission
factors, we are also finalizing as proposed in 40 CFR 98.233(q)(1) to
provide an option (provided in final 40 CFR 98.233(q)(3)) that would
allow reporters to quantify emissions from equipment leak components in
40 CFR 98.233(q) by performing direct measurement of equipment leaks
and calculating emissions using those measurement results, consistent
with section II.B. of this preamble. The final amendments would provide
that facilities with components subject to 40 CFR 98.233(q) can elect
to perform direct measurement of leaks using one of the existing
subpart W measurement methods in 40 CFR 98.234(b) through (d), such as
calibrated bagging or a high volume sampler. To use this option under
the final provisions, all leaks identified during a ``complete leak
detection survey'' must be quantified; in other words, reporters could
not use leaker emission factors for some leaks and quantify other leaks
identified during the same leak detection survey. For the Onshore
Petroleum and Natural Gas Production industry segment, final 40 CFR
98.233(q)(1) specifies that a complete leak detection survey is the
fugitive emissions monitoring of a well site using a method in 40 CFR
98.234(a) conducted to comply with NSPS OOOOa, NSPS OOOOb, or the
applicable EPA-approved state plan or the applicable Federal plan in 40
CFR part 62, or, if the reporter elected to conduct the leak detection
survey, a complete survey of all equipment on a single well-pad site.
For the Onshore Petroleum and Natural Gas Gathering and Boosting
industry segment, final 40 CFR 98.233(q)(1) specifies that a complete
leak detection survey is the fugitive emissions monitoring of a
compressor station using a method in 40 CFR 98.234(a) conducted to
comply with NSPS OOOOa, NSPS OOOOb, or the applicable EPA-approved
state plan or the applicable Federal plan in 40 CFR part 62, or, if the
reporter elected to conduct the leak detection survey, a complete
survey of all equipment at a ``gathering and boosting site'' (and we
are finalizing amendments to define this term in 40 CFR 98.238, as
described in section III.D. of this preamble). For downstream industry
segments (e.g., Onshore Natural Gas Transmission Compression), a
complete leak detection survey is facility-wide, and therefore, the
election to perform direct measurement of leaks is also required to be
facility-wide. In other words, this option allows the use of
measurement data directly when all leaks identified are quantitatively
measured. After consideration of comments, under the final rule we are
finalizing the addition of provisions for substituting measurement data
for components that require elevating the measurement personnel more
than 2 meters above the surface and a lift is unavailable at the site
or would pose immediate danger to measurement personnel performing the
direct measurement using one of the methods in 40 CFR 98.234(a). These
final provisions will allow facilities to substitute measurement data
only for components meeting these criteria with the component-specific
and service-specific default leak rate in final tables W-2, W-4, or W-
6, as applicable. We are also updating from proposal the term ``well-
pad'' in proposed 98.233(q)(1)(vii)(D) to the newly defined
[[Page 42165]]
``well-pad site'' term in the final provision (see section III.D. of
this preamble) to clarify that, for onshore production sites not
subject to NSPS OOOOb or EG OOOOc that elect to conduct leak detection
surveys, a complete leak detection survey must include all components
at a single well-pad and associated with that single well-pad. Also
after consideration of comments, for the natural gas distribution
industry segment, we are finalizing new amendments to the use of
Calculation Method 2 for facilities utilizing a multi-year survey cycle
to specify the use of volumetric emissions, rather than mass emissions,
resulting from this method to determine the meter/regulator run
population emission factor in accordance with 40 CFR
98.233(q)(viii)(A). This change will simplify the process of using the
measurement data to develop the population emission factor for
facilities using a multi-year survey cycle. Additionally, we are also
finalizing two corrections to cross-references in 40 CFR 98.233(q)(3)
and the related ``CountMR'' and ``Es,e,i'' variables in 40 CFR
98.233(r) as a result of consideration of public comments and EPA
review.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to add a method to quantify emissions from
equipment leak surveys using direct measurement.
Comment: Commenters stated that there may be situations at a
facility where direct measurement is not feasible or safe to conduct,
thus meaning the survey that did not include measurements for these
components would be considered incomplete and as a result facilities
would not be able to use the direct measurement option. Commenters
added that excluding components for which measurement is infeasible or
unsafe should not prevent reporters from conducting direct measurement
of equipment elsewhere on the facility. Commenters asserted that the
EPA's proposal disincentivizes the use of direct measurement, the most
accurate means of emission quantification. Commenters requested that
the EPA allow reporters the option to use direct measurement and/or EFs
as appropriate during a complete leak detection survey.
Response: We understand and agree with commenters that there may be
components that are difficult or unsafe to measure. We are finalizing
provisions in 40 CFR 98.233(q)(3)(i) to provide for the use of
substitute measurement data for components that require elevating the
measurement personnel more than 2 meters above the surface and a lift
is unavailable at the site or would pose immediate danger to
measurement personnel performing the direct measurement using one of
the methods in 40 CFR 98.234(a). These final provisions will allow
facilities to substitute measurement data only for components meeting
these criteria with the component-specific and service-specific default
leak rate in final tables W-2, W-4, or W-6, as applicable. The use of
substitute data will also ensure that a facility electing to use the
direct measurement option can still successfully perform a complete
leak detection survey as required by this option. The final amendments
narrowly define when data substitutions can be used to ensure the
accuracy of the estimate while accommodating feasibility and promoting
safety.
Comment: Commenters supported the option for facilities to
calculate their emissions based on the results of direct measurement.
Commenters noted that in order for natural gas distribution facilities
to use the measurement option, facilities must perform a complete leak
detection survey, which for natural gas distribution companies may take
up to 5 years depending on the length of the survey cycle. Commenters
then requested that natural gas distribution companies/utilities be
allowed to continue using their previous T-D emission factors for any
stations that have not yet been subject to direct measurements until
such time as all of that LDC's stations have gone through one full
cycle of surveying. Commenters stated that under this approach, once
the full cycle of measuring all T-Ds has been completed, the previous
emission factors would no longer be used.
Response: Under the existing subpart W provisions, natural gas
distribution companies must survey their above grade transmission
distribution transfer stations and may elect to do so over a single or
multi-year survey cycle not to exceed five years. If leaks are detected
at the above grade transmission distribution transfer stations during
these surveys, the emissions are quantified using equation W-30 with
the count of leaks, the default leaker emission factor, and the total
time the surveyed component was assumed to be leaking and operational.
The emissions from the above grade transmission distribution transfer
stations are used with equation W-31 to develop a facility-level meter/
regulator run population emission factor, which, depending on the
length of the survey cycle, is applied to the count of meter/regulator
runs at all above grade transmission distribution transfer stations
and/or the count of meter/regulator runs at above grade metering-
regulating stations. The facility-level meter/regulator run population
emission factor must be calculated annually, which for facilities
electing a multi-year survey cycle means the results of the current
calendar year leak survey and the results from prior year leak surveys
are included in the calculation of the meter/regulator run population
emission factor on a rolling basis such that a full survey cycle of
results is included.
Through this final rulemaking, natural gas distribution companies
will now have the option to either continue to use the default leaker
emission factors and equation W-30 to quantify equipment leak emissions
from their above grade transmission distribution transfer stations or
perform direct measurement of leaking components found during the
equipment leak surveys conducted at their above grade transmission
distribution transfer stations. The emissions from their above grade
transmission distribution transfer stations--whether based on
calculations using default leaker emission factors or direct
measurements--must still be used with equation W-31 to develop a
facility-level meter/regulator run population emission factor. The
facility-level meter/regulator run population emission factor must
still be applied to the count of meter/regulator runs at all above
grade transmission distribution transfer stations and/or the count of
meter/regulator runs at above grade metering-regulating stations,
depending on the length of the survey cycle, to estimate emissions from
these stations. The facility-level meter/regulator run population
emission factor must still be updated annually. For the first few years
following the effective date of the direct measurement option provided
in this final rule, for facilities that elect to survey over a multi-
year survey cycle and that elect to use the direct measurement option,
the developed facility-level meter/regulator run population emission
factor will be informed by emissions quantities at above grade
transmission distribution transfer stations that were estimated using
default leaker emission factors (i.e, the existing method) and direct
measurement (i.e, the new method). For example, if a facility elects to
survey all their stations over a 2-year survey cycle and for Year 1
they use the existing method (i.e, equipment leak surveys of their
above grade transmission distribution transfer stations, leaks
[[Page 42166]]
quantified using the default leaker emission factors) and for Year 2
they use the new method (i.e, equipment leak surveys of their above
grade transmission distribution transfer stations, leaks quantified
using direct measurement), the resulting facility-level meter/regulator
run population emission factor will be informed by emissions calculated
using the existing and new calculation methods. This is expected to be
temporary and only be an issue for no more than five years (i.e, the
maximum survey cycle length) and only for the subset of facilities that
elect a multi-year survey cycle and elect to use the direct measurement
option.
Concerning the comment that natural gas distribution companies
electing to survey over a multi-year survey cycle and electing to use
the direct measurement option should be able to use their historical
facility-level meter/regulator run population emission factors (i.e,
based on the existing method) until a survey cycle incorporating only
direct measurement data has been completed, we find that natural gas
distribution companies will obtain the necessary data by following the
direct measurement method (i.e, the volumetric emissions by component
type) to combine with the volumetric emissions from historical surveys
(i.e, the volumetric emissions calculated according to equation W-30)
for the prior year facility-level meter/regulator run population
emission factor development to continue to estimate the facility-level
meter/regulator run population emission factors in accordance with
equation W-31. Therefore, we do not see a need to provide that
historical facility-level meter/regulator run population emission
factors can be used until such time that a complete survey cycle
including only direct measurements of all stations has been completed.
Consequently, as described above we acknowledge that for a limited
period of time and limited number of facilities, this means that the
facility-level meter/regulator run population emission factors may have
a mix of emissions data calculated using the default leaker emission
factors (i.e, the existing calculation method) and direct measurements
(i.e, the new leaker measurement method).
In considering these comments, we performed a review of the
proposed procedures for utilizing the leaker measurement method for
natural gas distribution companies. We proposed in 40 CFR
98.233(q)(3)(viii)(A) that in order to determine the CO2 and
CH4 facility-level meter/regulator run population emission
factor using equation W-31, reporters were to use equation W-31 and the
mass emissions calculated in accordance with 40 CFR 98.233(q)(3)(vi).
During our review, we noted that the historical facility-level
population emission factors have been calculated on a volumetric basis
(i.e, the resulting population emission factor from equation W-31 has
units of measure of standard cubic feet of GHGi per operational hour of
all meter/regulator runs) and the provisions for estimating emissions
utilizing the facility-level meter/regulator run population emission
factors in 40 CFR 98.233(r) requires a volumetric based emission
factor. Therefore, we are finalizing amendments to 40 CFR
98.233(q)(3)(viii)(A) to instead require that for reporters electing to
use the direct measurement option and using equation W-31 to develop
their facility-level meter/regulator run population emission factor use
the sum of the volumetric emissions at standard conditions by component
type required to be surveyed calculated in accordance with 40 CFR
98.233(q)(3)(iv) rather than mass emissions as was proposed. This
simplifies the use of the direct measurement data as it does not
require conversion to mass emissions. This change also allows reporters
electing to perform a multi-year survey cycle to more easily combine
historical volumetric emission rates with direct measurements to
develop their meter/regulator run population emission factors.
4. Addition of a Method To Develop Site-Specific Component-Level Leaker
Emission Factors
a. Summary of Final Amendments
As noted in section III.P. of this preamble, facilities are
currently required to perform leak surveys to determine the number of
leaking components. The results of these surveys (i.e., the count of
leakers) are used with default emission factors to estimate the
quantity of resulting emissions. As noted in the previous section of
this preamble, the EPA is finalizing as proposed an additional option
for facilities to conduct leak surveys and perform direct measurement
to quantify the emissions from equipment leak components.
The EPA recognizes that while direct measurement is the most
accurate method for determining equipment leak emissions, it may also
be time consuming and costly. In consideration of both the advantages
of and potential burdens associated with direct measurement, the EPA is
also finalizing a method to use direct measurement from leak surveys to
develop component level emission factors based on facility-specific
leak measurement data. The facility-specific emission factors would
provide increased accuracy over the use of default emission factors,
consistent with section II.B. of this preamble, while lessening a
portion of the burden of directly measuring every leak.
We are finalizing as proposed that all facilities that elect to
follow the direct measurement provisions in proposed 40 CFR
98.233(q)(3)(i) must track the individual measurements of natural gas
flow rate by specific component type (valve, connector, etc., as
applicable for the industry segment) and leak detection method for the
development of facility-specific component-level leaker emission
factors. We are finalizing three different bins for the leak detection
methods: Method 21 using a leak definition of 500 ppm as specified in
40 CFR 98.234(a)(2)(i); Method 21 using a leak definition of 10,000 ppm
as specified in 40 CFR 98.234(a)(2)(ii); and OGI and other leak
detection methods as specified in 40 CFR 98.234(a)(1), (3), or (5). We
are finalizing as proposed that reporters must compile at least 50
individual measurements of natural gas flow rate for a specific
component type and leak detection method (e.g., gas service valves
detected by OGI) before they can develop and use the facility-specific
emission factors for the component types at the facility. Based on
consideration of comments received on the 2023 Subpart W Proposal, we
are finalizing a change from proposal to the terminology of the
emission factor from ``site-specific'' to ``facility-specific'' to
better characterize the application of the developed emission factor,
which is to be at the facility-level based on site-level measurement
data for certain industry segments. We are finalizing as proposed that
these flow rate measurements are required to be converted to standard
conditions following the procedures in 40 CFR 98.233(t). We are also
finalizing as proposed that the volumetric measurements comprised of at
least 50 measured leakers must then be summed and divided by the total
number of leak measurements for that component type and leak detection
method combination. The resulting value will be an emission factor in
units of standard cubic feet per hour-component (scf/hr-component).
This facility-specific emission factor must be used, when available, to
calculate equipment leak emissions following the procedures in 40 CFR
98.233(q)(2). Because some equipment component types are more prevalent
[[Page 42167]]
and more likely to reach 50 leak measurements than other components,
application of the calculation methodology in 40 CFR 98.233(q)(2) may
include default leaker factors for some components and facility-
specific leaker factors for other components.
We are also finalizing as proposed in 40 CFR 98.236(q) to require
that the emissions be reported at the aggregation of calculated or
measured values for the combination of component type and leak
detection method. As discussed in more detail in section III.P.1. of
this preamble, numerous studies have shown that different leak
detection methods identify different populations of leaking components;
therefore, consistent with the delineation of the default emission
factors by leak detection method, site-specific emission factors are
delineated in the same way under the final provisions.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to add a method to develop a site-specific
component-level leaker emission factor.
Comment: Commenters noted that the EPA's intent to allow for site-
level measurement data to be used to develop a representative facility-
level emission factor was clear from the discussion in the preamble to
the 2023 Subpart W Proposal, however the use of the term ``site-
specific'' in 40 CFR 98.233(q)(3) may make this intent less clear.
Therefore, commenters requested that the EPA clarify that only a
facility-wide emission factor based on direct measurement at a
representative sampling of well sites is needed.
Response: We are clarifying in the final provisions that the site-
specific emission factor approach in proposed 40 CFR 98.233(q)(4)
provides for the development of an emission factor that is applied at
the facility-level. For example, consistent with the description in the
preamble to our proposed rule, for the purposes of subpart W, an
onshore production facility may be comprised of multiple well sites.
The survey and measurement of all subject equipment leak components
using the methods in 40 CFR 98.234(a) at a well site constitutes a
complete leak detection survey of that well site. The measurements
obtained must be included in the component-specific datasets underlying
the site-specific emission factor. Once sufficient measurements are
made, the site-specific emission factor developed in accordance with
proposed 40 CFR 98.233(q)(4) may be applied to equipment leak
components at any of the well sites within the basin that comprise the
onshore production subpart W facility. In order to make this clearer,
the final terminology changes the name from the proposed ``site-
specific'' to the final ``facility-specific'' emission factor.
Comment: Commenters stated that the requirement to accumulate a
minimum of 50 leak measurements for a given component and leak
detection method combination was impractical and could take many years
of surveys. Some commenters stated that the EPA has not justified why a
minimum of 50 measurements is appropriate and reasonable. Some
commenters added that the minimum number of measurements proposed may
disincentivize measurement and penalize operators with a small number
of sites. Other commenters recommended a tiered approach whereby the
minimum number of leak measurements would be determined by the number
of well sites or gathering and boosting sites comprising the GHGRP
onshore petroleum and natural gas production and onshore petroleum and
natural gas gathering and boosting facility, respectively. Other
commenters recommended the EPA allow the development of site-specific
emission factors at the company level where owners/operators could
combine measurements from multiple GHGRP facilities together to develop
the emission factors. Some commenters also stated that the component
and survey method specific default leaker emission factors developed
using the combination of data from the Zimmerle et al. (2020) and Pacsi
et al. (2019) studies did not meet the measurement minimum the EPA
proposed for the development of site-specific emission factors.
Response: We have considered the comments received on the minimum
number of measurements (i.e., 50) required by component type and survey
method combination to meet the criteria for development of a facility-
specific emission factor as proposed in 40 CFR 98.233(q)(4). We have
performed additional analysis of the reported leaker data to assess
these comments. The details of these analyses are presented in the
Greenhouse Gas Reporting Rule: Technical Support for Revisions and
Confidentiality Determinations for Data Elements Under the Greenhouse
Gas Reporting Rule; Final Rule--Petroleum and Natural Gas Systems,
which is available in the docket for this rulemaking (Docket ID No.
EPA-HQ-OAR-2023-0234). We generally find that this approach was
provided to reduce the burden of measurement, while increasing the
accuracy of the associated emission estimate over that of using a
default leaker emission factor since it is based on sufficient
facility-specific measurements to be considered statistically
representative.
The first analysis we performed was to determine the average number
of leakers by component type and industry segment per facility-year. We
find that for components that are more commonly found in service (e.g.,
valves, connectors), a facility-specific emission factor could be
developed in 5 years or less for facilities in the onshore production,
gathering and boosting, underground storage and LNG import/export
industry segments based on the historical count of leakers per
facility-year. Conversely, we agree with commenters that for some
industry segments (e.g., processing, transmission compression, LNG
storage, NGD) and some types of components (e.g., OEL, Pump Seals), it
may take many years to accumulate sufficient measurements to develop a
facility-specific emission factor. For example, OEL and pump seals have
very low (if any) reported leakers on average per facility-year for any
of the 7 industry segments. In this case, reporters may decide that
using this method for these components may not be reasonable. However,
facilities would still be able to use the default emission factor for
these components or continue to take their own measurements to ensure
the accuracy of the reported data.
The provisions to directly measure and develop a facility-specific
emission factor is one of several options to quantify emissions from
equipment leaks. Regarding the comments to allow for the development of
company specific emission factors, we note that the equipment leak
provisions for direct measurement are based on measurements aggregated
at a facility level. If we were to include an option for facilities to
develop a company level emission factor, facilities with multiple GHGRP
facilities may not have to measure every facility to develop a company
level emission factor. We do not believe that extrapolating an emission
factor based on a select subset of facilities across all facilities
that are part of the corporate entity would be appropriate. Subpart W
allows corporate emission factors for compressors because as found
measurements are required for every compressor at all facilities in the
corporate entity, ensuring representativeness. However, in this case
measurements are not required at every facility (i.e., facilities can
elect the leaker method, the direct
[[Page 42168]]
measurement method or the population count method, as applicable) such
that the company level emission factor may not be representative of all
facilities. That is, owners may look to conduct measurements only at
newer facilities or facilities that are otherwise expected to have
lower emissions, and therefore potentially bias the corporate emission
factor. Therefore, we are not providing an option for component level
leaker emission factors to be developed at the company level and are
maintaining our proposed facility-specific emission factor method.
The second analysis we performed was to utilize the combined
Zimmerle et al. (2020) and Pacsi et al. (2019) dataset and the
resulting proposed leaker emission factors to perform a statistical
analysis. In this analysis, we sought to determine the impact of sample
size on the EF for each component. For example, for leaking connectors
detected with OGI at gas sites, the combined dataset of the Zimmerle et
al. (2020) and Pacsi et al. (2019) studies contain 217 measurements for
this component type. In this analysis, a range of sample sizes was
simulated for each component. Each sample size was simulated 10,000
times by sampling the available data with replacement, meaning no data
points were removed from the available data when developing the
distribution and, thus, could be chosen again during the simulations.
We then compared the distribution of the estimated emission factor
against the number of samples in the simulations.Galley Info End?>
Across all components, the analysis demonstrates that 90 percent of
the simulated emission factors fall within 40 percent of
the study estimated emission factor when using 50 samples; 30 percent of the study estimated emission factor when using 100
samples; and 20 percent of the study estimated emission
factor using 200 samples. Therefore, we continue to maintain that
sample size is of critical importance when developing emission factors
and a minimum of 50 measurements appears to be provide reasonable
accuracy while considering the burden and duration of survey/
measurement campaigns for this option based on this analysis.
Finally, in response to comments that we are utilizing emission
factor datasets (i.e., Pacsi/Zimmerle) that are not as robust as the
minimum requirements for developing facility-specific emission factors,
we note that we consistently strive to use up-to-date studies that
provide the necessary data to derive emission factors, but we are
limited to what is available that meets our purpose. This process is
also open to stakeholder engagement in which stakeholders can recommend
studies or provide data to better inform decisions related to emission
factor development. In this case, we combined data from multiple
studies to increase sample size and for the many of components we meet
or exceed the minimum in proposed 40 CFR 98.233(q)(4).
5. Removal of Additional Method 21 Screening Survey for Other Screening
Survey Methods
Currently, facilities using survey methods other than Method 21 to
detect equipment leaks may then screen the equipment identified as
leaking using Method 21 to determine if the leak measures greater than
10,000 parts per million by volume (ppmv) (see, e.g., 40 CFR
98.234(a)(1)). If the Method 21 screening of the leaking equipment is
less than 10,000 ppmv, then reporters currently may consider that
equipment as not leaking. In the 2016 subpart W revisions, we added a
leak detection methodology at 40 CFR 98.234(a)(6) (finalized at 40 CFR
98.234(a)(1)(ii)) for using OGI in accordance with NSPS OOOOa, which
does not include an option for additional Method 21 screening. As noted
in response to comments on the 2016 subpart W proposal regarding the
absence of this optional additional Method 21 screening when using OGI
in accordance with NSPS OOOOa, the additional screening of OGI-
identified leaking equipment using Method 21 requires additional effort
from reporters (81 FR 86500, November 30, 2016). Furthermore, as noted
previously in this section of the preamble, the average emissions of
leakers identified by OGI are greater than for leaks identified by
Method 21. Directly applying the number of OGI-identified leaks to the
subpart W leaker emission factor specific to that survey method will
provide the most accurate estimate of emissions, while selectively
screening OGI-identified leaks using Method 21 to reduce the number of
reportable leakers will yield a low bias in the reported emissions.
Additionally, this will be incongruous with the application and
supporting rationale of the monitoring method-specific adjustment
factor, k (where the k value for Method 21 with a leak definition of
10,000 ppm will need to be applied), which we are finalizing in this
action, if OGI-identified leaks could be considered non-leaks based on
subsequent Method 21 monitoring. For these reasons, we are finalizing
as proposed to require reporters to directly use the leak survey
results for the monitoring method used to conduct the complete leak
survey and are finalizing as proposed to eliminate this additional
Method 21 screening provision. These final amendments are expected to
provide more accurate emissions data, consistent with section II.B. of
this preamble. The EPA did not receive any comments regarding these
proposed amendments.
6. Amendments Related to Oil and Natural Gas Standards and Emissions
Guidelines in 40 CFR Part 60
a. Summary of Final Amendments
As noted in the introduction to section II. of this preamble, the
EPA recently finalized NSPS OOOOb and EG OOOOc for certain oil and
natural gas new and existing affected sources, respectively. Under the
final standards in NSPS OOOOb and the final presumptive standards in EG
OOOOc, owners and operators will be required to implement a fugitive
emissions monitoring and repair program for the collection of fugitive
emissions components at well site, centralized production facility and
compressor station affected sources. In addition, the final NSPS OOOOb
and EG OOOOc include a final appendix K to 40 CFR part 60, specifying
an OGI-based method for detecting leaks and fugitive emissions from all
components that is not currently provided in subpart W. The EPA also
finalized provisions in NSPS OOOOb and EG OOOOc for equipment leak
detection and repair at onshore natural gas processing facilities.
Similar to the 2016 amendments to subpart W (81 FR 4987, January 29,
2016), the EPA is finalizing amendments to revise the calculation
methodology for equipment leaks in subpart W largely as proposed so
that data derived from equipment leak and fugitive emissions monitoring
using one of the methods in 40 CFR 98.234(a) conducted under NSPS OOOOb
or the applicable approved state plan or applicable Federal plan in 40
CFR part 62 must be used to calculate emissions, consistent with
section II.B. of this preamble.
First, under these final amendments, as proposed, facilities with
certain fugitive emissions components at a well site, centralized
production facility or compressor station subject to NSPS OOOOb or an
applicable approved state plan or applicable Federal plan in 40 CFR
part 62 will be required to use the data derived from the NSPS OOOOb or
applicable 40 CFR part 62 fugitive emissions requirements along with
the subpart W equipment leak survey calculation methodology and leaker
emission factors to calculate and report
[[Page 42169]]
their GHG emissions to the GHGRP. Specifically, as proposed, the final
amendments expand the existing cross-reference to 40 CFR 60.5397a to
also include the analogous requirements in NSPS OOOOb or 40 CFR part
62. Facilities with fugitive emissions components not subject to the
standards in NSPS OOOOb or addressed by standards in a state or Federal
plan following EG OOOOc will continue to be able to elect to calculate
subpart W equipment leak emissions using the leak survey calculation
methodology and leaker emission factors (as is currently provided in 40
CFR 98.233(q)). Therefore, reporters with other fugitive emission
sources at subpart W facilities not covered by NSPS OOOOb or a state or
Federal plan in 40 CFR part 62 (e.g., sources subject to other state
regulations and sources participating in the Methane Challenge Program
or other voluntarily implemented programs) will continue to have the
opportunity to voluntarily use the proposed leak detection methods to
calculate and report their GHG emissions to the GHGRP in accordance
with the final provisions. We also note that there are facilities with
certain fugitive emissions components at a well site, centralized
production facility or compressor station that are subject to NSPS
OOOOb, but are not required to monitor these fugitive emission
components using the survey methods in 40 CFR 98.234(a) (e.g., single
wellhead only site, which is required to survey using AVO). For these
facilities, we are finalizing the option in 40 CFR 98.233(q)(1)(iv) for
facilities to elect to conduct equipment leak surveys at these sites in
accordance with the methods in 40 CFR 98.234(a) in lieu of calculating
emissions from these sites in accordance with 40 CFR 98.233(r). To
facilitate these final provisions, we are also finalizing
clarifications in 40 CFR 98.233(q)(1)(vii)(B) and (C) that fugitive
emissions monitoring conducted using one of the methods in 40 CFR
98.234(a) to comply with NSPS OOOOb or an applicable approved state
plan or applicable Federal plan in 40 CFR part 62, respectively, is
considered a ``complete leak detection survey,'' so that onshore
petroleum and natural gas production and onshore petroleum and natural
gas gathering and boosting facilities will be able to comply with the
requirement to use NSPS OOOOb or 40 CFR part 62 fugitive emission
surveys directly for their subpart W reports. We are also finalizing an
amendment to move the specification that fugitive emissions monitoring
conducted to comply with NSPS OOOOa is considered a ``complete leak
detection survey'' from existing 40 CFR 98.233(q)(2)(i) to 40 CFR
98.233(q)(1)(vii)(A) so that all the provisions regarding what
constitutes a ``complete leak detection survey'' are together. In a
corresponding amendment, we are also finalizing an expansion of the
current reporting requirement in existing 40 CFR 98.236(q)(1)(iii)
(final 40 CFR 98.236(q)(1)(iv)) to require reporters to indicate if any
of the surveys of well sites, centralized production facilities or
compressor stations used in calculating emissions under 40 CFR
98.233(q) were conducted to comply with the fugitive emissions
standards in NSPS OOOOb or an applicable approved state plan or
applicable Federal plan in 40 CFR part 62.\68\
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\68\ We are similarly finalizing as proposed a revision to the
existing reporting requirement in subpart W related to NSPS OOOOa,
such that reporters would report whether any of the surveys of well
sites or compressor stations used in calculating emissions under 40
CFR 98.233(q) were conducted to comply with the fugitive emissions
standards in NSPS OOOOa (rather than simply reporting whether the
facility has well sites or compressor stations subject to the
fugitive emissions standards in NSPS OOOOa).
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Second, we are finalizing as proposed revisions to 40 CFR 98.234(a)
to clarify and consolidate the requirements for OGI and Method 21 in 40
CFR 98.234(a)(1) and (2), respectively. In the 2016 amendments to
subpart W (81 FR 4987, January 29, 2016), the EPA added 40 CFR
98.234(a)(6) and (7) to provide OGI and Method 21 as specified in NSPS
OOOOa as leak detection survey methods. Specifically, the EPA is
finalizing the amendments to move 40 CFR 98.234(a)(1) and 40 CFR
98.234(a)(6) to 40 CFR 98.234(a)(1)(i) and 40 CFR 98.234(a)(1)(ii),
respectively, which will consolidate the OGI-based methods in 40 CFR
98.234(a)(1). Similarly, the EPA is finalizing revisions to 40 CFR
98.234(a)(2) such that 40 CFR 98.234(a)(2)(i) is Method 21 with a leak
definition of 10,000 ppm and 40 CFR 98.234(a)(2)(ii) is Method 21 with
a leak definition of 500 ppm. This final amendment will effectively
move 40 CFR 98.234(a)(7) to 40 CFR 98.234(a)(2)(ii). We are also
finalizing that the references to ``components listed in Sec. 98.232''
will be replaced with a more specific reference to 40 CFR 98.233(q)(1).
The references to specific provisions in 40 CFR 60.5397a in 40 CFR
98.234(a)(6) and (7) will be moved to 40 CFR 98.234(a)(1)(ii) and 40
CFR 98.234(a)(2), as applicable.
In March 2024, the EPA finalized in NSPS OOOOb and EG OOOOc that
owners and operators of natural gas processing facilities will detect
leaks using an OGI-based monitoring method following the final appendix
K to 40 CFR part 60 (89 FR 16820). We are finalizing as proposed
amendments to include that same method in subpart W at 40 CFR
98.234(a)(1)(iii) to ensure that reporters of those facilities will be
able to comply with the subpart W requirement to use data derived from
the NSPS OOOOb or 40 CFR part 62 fugitive emissions requirements for
purposes of calculating emissions from equipment leaks. In addition, as
part of the final NSPS OOOOb and EG OOOOc, the EPA finalized an
alternative periodic screening approach for fugitive emissions from
well sites, centralized production facilities and compressor stations
under 40 CFR 60.5398b(b) that will allow the use of advanced
technologies approved under 40 CFR 60.5398b(d) to detect large
equipment leaks. Under the NSPS OOOOb and EG OOOOc final rule, if
emissions are detected using an approved advanced technology,
facilities will be required to conduct monitoring using OGI or Method
21 to identify and repair specific leaking equipment. Additionally,
under the NSPS OOOOb and EG OOOOc final rule, even if no emissions are
identified during a periodic screening survey, some facilities using
these advanced technologies will still be required to conduct annual
fugitive emissions monitoring using OGI. The EPA's intent in this final
rule for subpart W is that the results of those NSPS OOOOb and 40 CFR
part 62 OGI or Method 21 surveys will be used for purposes of
calculating emissions for subpart W, as OGI and Method 21 are capable
of identifying leaks from individual components and they are included
in the leak detection methods provided in subpart W. Thus, after
further consideration, including consideration of comments we received
on the 2023 Subpart W Proposal, we are finalizing new amendments that
will require the reporting of fugitive emissions monitoring survey
results conducted to comply with the alternative periodic screening
approach in the NSPS OOOOb, including annual affected facility-level
OGI surveys pursuant to 40 CFR 60.5398b(b)(4) and affected facility-
level ground based monitoring surveys pursuant to 40 CFR
60.5398b(b)(5)(ii).
Third, we are finalizing as proposed subpart W requirements for
onshore natural gas processing facilities consistent with certain
requirements for equipment leaks in the final NSPS OOOOb or EG OOOOc.
Currently, onshore natural gas processing facilities
[[Page 42170]]
must conduct at least one complete survey of all the components listed
in 40 CFR 98.232(d)(7) each year, and each complete survey must be
considered when calculating emissions according to 40 CFR 98.233(q)(2).
Under the equipment leak detection and repair program included in the
final NSPS OOOOb and the EG OOOOc presumptive standards, owners and
operators must conduct bimonthly (i.e., once every other month) OGI
monitoring in accordance with 40 CFR part 60, appendix K to detect
equipment 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 closed
vent systems in accordance with 40 CFR 60.5400b and 60.5400c,
respectively. 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) in accordance with 40 CFR 60.5401b and
60.5401c, respectively. 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. For the
alternative approach provided in NSPS OOOOb and EG OOOOc using EPA
Method 21, different component types may be monitored on different
frequencies, so all equipment at the facility is not always monitored
at the same time. According to the current requirements in 40 CFR
98.233(q), surveys that do not include all of the applicable equipment
at the facility are not considered complete surveys and are not used
for purposes of calculating emissions. Therefore, we are finalizing in
40 CFR 98.233(q)(1)(vii)(F) that onshore natural gas processing
facilities subject to NSPS OOOOb or an applicable approved state plan
or the applicable Federal plan in 40 CFR part 62 must use the data
derived from each equipment leak survey conducted as required by NSPS
OOOOb or the relevant subpart of 40 CFR part 62 along with the subpart
W equipment leak survey calculation methodology and leaker emission
factors to calculate and report GHG emissions to the GHGRP, even if a
survey required for compliance with NSPS OOOOb or 40 CFR part 62 does
not include all the component types listed in 40 CFR 98.232(d)(7).
Under this final amendment, onshore natural gas processing facility
reporters will still have to meet the subpart W requirement to conduct
at least one complete survey of all applicable equipment at the
facility per year, so if there were components listed in 40 CFR
98.232(d)(7) not included in any NSPS OOOOb or 40 CFR part 62-required
surveys conducted during the year, reporters subject to NSPS OOOOb or
40 CFR part 62 will need to either add those components to one of their
required surveys, making that a complete survey for purposes of subpart
W, or conduct a separate complete survey for purposes of subpart W.
We are also finalizing as proposed to add leaker emission factors
for all survey methods for ``other'' components that would be required
to be monitored under NSPS OOOOb or an approved state plan or
applicable Federal plan in 40 CFR part 62 or that reporters elect to
survey that are not currently included in subpart W. These final THC
leaker emission factors for the ``other'' component type are of the
same value as the THC leaker emission factors for the ``other''
component type for the Onshore Natural Gas Transmission Compression and
the Underground Natural Gas Storage industry segments (existing table
W-3A and table W-4A to subpart W, respectively, final table W-4 to
subpart W). For more information on the derivation of the original
emission factors, see the 2010 subpart W TSD,\69\ and for more
information on the derivation of the ``other'' component type emission
factor proposed to be applied to these types of leaks at facilities in
the Onshore Natural Gas Processing industry segment, see the TSD for
the 2016 amendments to subpart W.\70\ In a corresponding amendment, we
are also finalizing as proposed the expansion of the reporting
requirement in existing 40 CFR 98.236(q)(1)(iii) (finalized 40 CFR
98.236(q)(1)(iv)) to require onshore natural gas processing reporters
to indicate if any of the surveys used in calculating emissions under
40 CFR 98.233(q) were conducted to comply with the equipment leak
standards in NSPS OOOOb or an applicable approved state plan or the
applicable Federal plan in 40 CFR part 62.
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\69\ Greenhouse Gas Emissions Reporting from the Petroleum and
Natural Gas Systems Industry: Background Technical Support. November
2010. Docket ID. No. EPA-HQ-OAR-2009-0923-3610; also available in
the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
\70\ Greenhouse Gas Reporting Rule: Technical Support for Leak
Detection Methodology Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems. November 1, 2016. Docket ID.
No. EPA-HQ-OAR-2015-0764-0066; also available in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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After consideration of comments received on the 2023 Subpart W
Proposal, we are finalizing new amendments to cross reference the
alternative standards (i.e., use of EPA Method 21), in addition to the
emission standard (i.e., bimonthly OGI surveys), for fugitive emission
sources in NSPS OOOOb for natural gas processing plants to ensure that
all surveys conducted for the NSPS OOOOb are included in subpart W.
Additionally, in response to comments on the 2023 Subpart W Proposal,
we are codifying a regulatory cross refence that provides an exemption
to survey equipment leak components that are considered
``inaccessible'' for natural gas processing plants in 40 CFR
98.233(q)(vii)(F). This exemption only applies to components that are
``inaccessible'' as provided in 40 CFR 60.5401b(h)(3) and
60.5401c(h)(3) for facilities using the EPA Method 21 leak survey
method. In the existing subpart W rule, the term ``inaccessible'' is
used in 40 CFR 98.234(a)(1), (2), (6) and (7) to refer to equipment
leak components that require monitoring personnel to be elevated more
than 2 meters off the surface. As stated in the existing rule text,
these components are not exempt from monitoring rather they must be
monitored using OGI if EPA Method 21 cannot be used to monitor the
inaccessible equipment leaks. During rearrangement of the rule text in
the 2023 Subpart W Proposal, this language was proposed to be moved and
consolidated at 40 CFR 98.234(a). In the NSPS OOOOb and EG OOOOc, the
term ``difficult-to-monitor'' is used to characterize components that
require monitoring personnel to be elevated more than 2 meters off the
surface. In response to comments and in order to be consistent with the
terminology in the NSPS OOOOb and EG OOOOc, we are revising the term in
the final rule from ``inaccessible'' to ``difficult-to-monitor'' in 40
CFR 98.234(a). We are also making the same revision to change the term
``inaccessible'' to ``difficult-to-monitor'' in 40 CFR
98.233(q)(1)(vii)(F) of the final rule for consistency in the use of
the term.
Finally, in our review of subpart W equipment leak requirements for
onshore natural gas processing facilities, we found that the leak
definition for the Method 21-based requirements for processing plants
in NSPS OOOOa (as well as final NSPS OOOOb and EG OOOOc presumptive
standards) is not consistent with the leak definition in the Method 21
option in the current 40 CFR 98.234(a)(2), which is the only Method 21-
based method available to onshore natural gas processing facilities
under subpart W. Based on this review, and to complement the final
addition of
[[Page 42171]]
default leaker emission factors for survey methods other than Method 21
(as described previously in this preamble), we are finalizing as
proposed several additions to the equipment leak survey requirements
for the Onshore Natural Gas Processing industry segment, beyond those
amendments already described related to the final NSPS OOOOb and EG
OOOOc presumptive standards. First, we are finalizing default leaker
emission factors for Method 21 at a leak definition of 500 ppm in final
table W-4 to subpart W. As with the final ``other'' component type
leaker emission factors, these final leaker emission factors (i.e.,
valve, connector, open-ended line, pressure relief valve and meter) are
of the same value as the THC leaker emission factors for the Onshore
Natural Gas Transmission Compression and the Underground Natural Gas
Storage industry segments (existing table W-3A and table W-4A,
respectively). For more information on the derivation of those emission
factors, see the TSD for the 2016 amendments to subpart W.\71\ In
addition, we are finalizing to add 40 CFR 98.233(q)(1)(v) to indicate
that onshore natural gas processing facilities not subject to NSPS
OOOOb or an approved state plan or the applicable Federal plan in 40
CFR part 62 may use any method specified in 40 CFR 98.234(a), including
Method 21 with a leak definition of 500 ppm and OGI following the
provisions of appendix K to 40 CFR part 60. This final amendment will
ensure that equipment leak surveys conducted using any of the approved
methods in subpart W would be available for purposes of calculating
emissions, not just those surveys conducted using one of the methods
currently provided in 40 CFR 98.234(a)(1) through (5).
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\71\ Greenhouse Gas Reporting Rule: Technical Support for Leak
Detection Methodology Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems. November 1, 2016. Docket ID.
No. EPA-HQ-OAR-2015-0764-0066; also available in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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b. Summary of Comments and Responses
Comment: Commenters expressed support for allowing the results of
monitoring surveys conducted in accordance with the NSPS OOOOb and 40
CFR part 62 state plans. Commenters stated that the EPA should,
however, allow the use of the results of all monitoring surveys
conducted for the NSPS OOOOb and 40 CFR part 62 state plans for
reporting, including follow-up surveys.
Response: We are finalizing, with some changes consistent with the
proposal to reflect the NSPS OOOOb and EG OOOOc final rules, that the
results of monitoring surveys for fugitive emissions components
affected facilities conducted under the NSPS OOOOb and EG OOOOc will be
required to be reported to subpart W.
NSPS OOOOb and EG OOOOc in 40 CFR 60.5397b and 60.5397c,
respectively, provide the emission standards for fugitive emissions
components affected and designated facilities, which include initial
and subsequent monitoring surveys using AVO, OGI or Method 21 with a
leak definition of 500 ppm depending on site type (e.g., single
wellhead only well sites, multi-wellhead only well sites).
We are finalizing, as proposed, the provisions that facilities must
report the results of equipment leak surveys conducted to comply with
40 CFR 60.5397b and 60.5397c of the NSPS OOOOb and EG OOOOc,
respectively, as long as they were conducted using one of the leak
survey methods included in subpart W at 40 CFR 98.234(a) (i.e., OGI or
Method 21) and constitute a complete leak survey as specified in 40 CFR
98.233(q)(1)(vii).
40 CFR 60.5398b(b) and 60.5398c(b) of the NSPS OOOOb and EG OOOOc,
respectively, provide the option to demonstrate compliance with the
alternative standards for fugitive emissions components affected and
designated facilities using periodic screening. Under those provisions,
the periodic screening can be performed using advanced technologies
that are approved under 40 CFR 60.5398b(d). Under those provisions, the
frequency of periodic screening is determined based on the minimum
aggregate detection threshold of the method used to conduct the
periodic screenings and site type. Some NSPS OOOOb affected facilities
and EG OOOOc designated facilities are required to perform an affected
facility-level OGI survey independent of the results of the periodic
screening, including the following:
Well sites and centralized production facilities that
contain certain major production and processing equipment, and
compressor stations: Bimonthly Screening and <=10 kg/hr technology
detection threshold;
Well sites or centralized production facilities that
contain certain major production and processing equipment, and
compressor stations: Monthly Screening and <=15 kg/hr technology
detection threshold;
Single wellhead only well sites, small well sites, and
multi-wellhead only well sites: Triannual and <=10 kg/hr technology
detection threshold; and
Single wellhead only well sites, small well sites, and
multi-wellhead only well sites: Quarterly Screening and <=15 kg/hr
technology detection threshold.
Additionally, under those provisions any periodic screening result
with a confirmed detection of emissions found with the approved
advanced technology requires a ground-level follow-up survey using OGI
or Method 21 with a leak definition of 500 ppm. Depending on the
spatial resolution of the approved advanced technology, the follow-up
monitoring survey is required at the affected facility level, area-
level or component-level. In order to ensure that monitoring surveys
conducted in accordance with 40 CFR 60.5398b(b) and 60.5398c(b) of the
NSPS OOOOb and EG OOOOc, respectively, which constitute a complete leak
detection survey and were conducted using one of the methods in 40 CFR
98.234(a) are also required to be reported to subpart W, we are adding
provisions to include these survey results in the final rule. These
provisions specifically include the annual OGI surveys required in 40
CFR 60.5398b(b)(4) and 60.5398c(b)(4) as well as the facility-level
follow-up monitoring surveys conducted in accordance with 40 CFR
60.5398b(b)(5)(ii) or 60.5398c(b)(5)(ii). The area or component-level
monitoring surveys conducted in accordance with 40 CFR 60.5398b(b) and
60.5398c(b) of the NSPS OOOOb and EG OOOOc, respectively, are not
considered complete leak detection surveys for purposes of subpart W
reporting because the surveys only cover a subset of equipment leak
components at each site. The partiality of these area or component-
level surveys may not provide representative emissions coverage of each
well-pad site or gathering and boosting site. Therefore, we are not
allowing inclusion of the NSPS OOOOb and EG OOOOc area or component-
level monitoring survey results in the final rule requirements for
subpart W. However, we note that reporters may elect to conduct site-
level surveys while on site to conduct NSPS OOOOb and EG OOOOc area or
component-level surveys, and reporting and use the results of these
site-level surveys would then be included in the final rule
requirements for reporting under subpart W in accordance with the
provisions of 98.233(q)(1)(vii)(D) and (E).
Comment: For natural gas processing facilities, commenters
recommended that references to 40 CFR 60.5400b should also include a
reference to the
[[Page 42172]]
alternate equipment leak standards in 40 CFR 60.5401b to clarify that
both OGI surveys conducted according to Appendix K and Method 21
surveys with a 500 ppmv leak definition should be used in emission
calculations. Additionally, specifically for natural gas processing
facilities, commenters stated that the inaccessible component exemption
in 40 CFR 98.234(a) should be retained under Subpart W. Commenters
stated that, for onshore gas processing, the term ``Inaccessible'' has
a long-standing meaning under NSPS, which historically is limited to
connectors that are monitored using Method 21 with specific criteria
that extends well beyond the 2-meter clause noted in 40 CFR 98.234(a).
Commenters stated that this exemption is directly linked to the safety
of personnel or the technical use of monitoring equipment. Commenters
stated that, specifically, connectors that are ``buried'' or that are
``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)'' should not require
additional leak detection provisions under subpart W.
Response: Concerning the comment about cross-referencing the NSPS
OOOOb alternative standard for natural gas processing plants, we
updated the cross references in the subpart W final rule to the NSPS
OOOOb to include 40 CFR 60.5401b for natural gas processing in 40 CFR
98.232(d)(7), 98.233(q)(1)(v), 98.233(q)(1)(vii)(F), and
98.236(q)(1)(iv)(D). These revisions add clarity to the subpart W
equipment leak provisions.
Concerning the comments on the inaccessible component exemption, we
note that this language is not new, it was moved from 40 CFR
98.234(a)(2) to proposed 40 CFR 98.234(a) during reorganization of the
rule at proposal. Additionally, as described in the preamble to our
2023 proposed rule, our intent is to align requirements between subpart
W and the NSPS OOOOb and EG OOOOc, as appropriate. As noted by the
commenter, the term ``inaccessible'' in the NSPS OOOOb and the EG OOOOc
is limited to connectors and the term is only found in the context of
complying with the alternative standard in 40 CFR 60.5401b(h)(3) and
60.5401c(h)(3), respectively. The NSPS OOOOb and EG OOOOc provide an
exemption from the monitoring, leak repair, recordkeeping and reporting
requirements for ``inaccessible'' connectors. Consistent with this
exemption in the NSPS OOOOb and EG OOOOc, we are providing the same
exemption for ``inaccessible'' components in 40 CFR
98.233(q)(1)(vii)(F) for onshore natural gas processing facilities. The
term ``difficult-to-monitor,'' however, is included in the NSPS OOOOb
and EG OOOOc specifically when using EPA Method 21 screening method and
is characterized in the NSPS OOOOb and EG OOOOc as being for components
that would require elevating the monitoring personnel more than 2
meters above a support surface. Therefore, we agree with commenters
that we intended the term ``inaccessible'' to have the same meaning as
the term ``difficult-to-monitor'' as provided in the NSPS OOOOb and EG
OOOOc and we are therefore replacing the term ``inaccessible'' with the
term ``difficult-to-monitor'' in 40 CFR 98.233(q)(1)(vii)(F) and
98.234(a).
Comment: Commenters encouraged the EPA to promote the use of
alternative technologies for leak detection. Several commenters stated
that the EPA should allow the use of technologies approved under the
NSPS OOOOb and 40 CFR part 62 state plans advanced technology framework
for quantification of equipment leak emissions under subpart W and/or
develop a subpart W-specific framework for approval of alternate
technologies for equipment leak emissions quantification.
Response: The EPA acknowledges comments requesting that the Agency
promote the use of alternative technologies to detect leaks. The EPA is
doing so to the extent it is appropriate in the context of subpart W in
certain aspects of this final rulemaking. The EPA is aware of various
technologies including fixed sensor monitors, UAVs or drones, aircraft,
and satellites currently in use and deployed for various oil and gas
survey purposes, as well as those in development. The EPA does not
dispute the availability and capabilities of these newer developing
technologies as alternative and supplements to standard leak detection
technologies. However, as the commenters also indicate, there are
several ongoing remote sensing activities to improve the understanding
of how such advanced detection technologies work, and there is still
much to learn on how data from remote sensing can be applied for
emissions quantification. As discussed in the preamble to the final
rule, we are not finalizing a framework for the adoption of advanced
survey or measurement methane technology analogous to the performance-
based technology approval process included in the NSPS OOOOb at 40 CFR
60.5398b(d).
Under the ``Standards of Performance for Crude Oil and Natural Gas
Facilities for which Construction, Modification or Reconstruction
Commenced After December 6, 2022,'' published on March 8, 2024 (89 FR
16820), the EPA finalized provisions to allow entities seeking to
utilize the alternative compliance options under 40 CFR 60.5398b(b)
(periodic screening alternative) and 60.5398b(c) (continuous monitoring
alternative), in lieu of complying with the fugitive emissions
standards under 40 CFR 60.5397b. In order to use the alternative
compliance options of 40 CFR 60.5398b(b) and (c), entities must meet
certain qualifications and must use advanced methane detection
technology that has been approved by the EPA. In the final NSPS OOOOb
at 40 CFR 60.5398b(d), the EPA provided specific detailed provisions
that entities seeking to use technologies other than AVO, OGI and
Method 21 must provide to the Agency in order to apply for specific
alternative test method approval.
The final alternative test method provisions under NSPS OOOOb were
specifically developed for the use of the advanced methane detection
technology in lieu of the required fugitive emissions monitoring
methods in the rule, and implements specific criteria for the review,
evaluation, and potential use of advanced methane detection technology
specifically for use in periodic screening, continuous monitoring, and/
or super-emitter detection. The adoption of an alternative technology
pathway under final NSPS for the oil and natural gas sector was
primarily aimed at detecting fugitive emissions from well sites,
centralized production facilities and compressor stations and to repair
those confirmed detections as quickly as possible. Agency approved
alternative technologies would be permitted to be used under NSPS OOOOb
and EG OOOOc to find and identify leaks and repair confirmed detected
sources of emissions.
As described above, the focus of NSPS OOOOb and EG OOOOc is to find
and repair leaks as quickly as possible in order to minimize emissions,
and there is no requirement to quantify emissions. The EPA lacks
specific information at this time in order to establish an alternative
technology framework for subpart W analogous to that finalized for the
NSPS OOOOb for fugitive emissions that the Agency believes would be
appropriate to quantify and report emissions under subpart W. In
[[Page 42173]]
order to quantify emissions from leaks identified using one of the
alternative periodic screening approaches in the finalized NSPS OOOOb,
we would need to have data collected using these screening methods
compared to data collected with OGI or EPA Method 21 (or other
appropriate data to quantitatively assess how the detected and
quantified emissions compare to total actual emissions from equipment
leaks) in order to develop appropriate leaker factors. As discussed in
the preamble in section III.P.1. of this preamble, different screening
approaches for leak detection result in the identification of different
subsets of total leaks at a facility, due to the limitations of each
screening approach. In order to develop accurate leaker factors or
allow direct quantification of leak emission rates, the EPA would need
data to understand the population of both detected and undetected leaks
specific to the screening approach and associated detection limit.
For these reasons and based on the additional discussion on this
topic in section II.B. of this preamble, the EPA believes that a
notice-and-comment rulemaking would be necessary to properly and
adequately consider the adoption of the alternative technology
framework in NSPS OOOOb that would be applicable and appropriate for
subpart W purposes. In advance of such a rulemaking, the EPA intends to
solicit input on the use of advanced measurement data and methods in
subpart W through a white paper, workshop or request for information.
7. Exemption for Components in Vacuum Service
Through correspondence with the EPA via e-GGRT, some reporters have
stated that certain equipment leak components at their facility are in
vacuum service. These reporters indicated that there are no fugitive
emissions expected from components in vacuum service. After
consideration of these comments and in order to be consistent with
other EPA equipment leak regulatory programs (e.g., 40 CFR part 60,
subpart VVa), we have determined that we agree with commenters. For
these reasons, we are finalizing as proposed an exemption in the
introductory paragraphs of 40 CFR 98.233(q) and (r) for leak components
in vacuum service from the requirement to estimate and report emissions
from these components. We are also finalizing as proposed a definition
in 40 CFR 98.238 for the term ``in vacuum service.'' We are finalizing
as proposed to require the reporting of the count of equipment in
vacuum service to enable verification of the reported data (i.e.,
ability to confirm that all equipment for which emissions are expected
has been accounted for and an indication that other equipment has been
confirmed to meet the proposed definition of ``in vacuum service'').
The EPA received only supportive comments regarding these amendments.
See the document Summary of Public Comments and Responses for 2024
Final Revisions and Confidentiality Determinations for Petroleum and
Natural Gas Systems under the Greenhouse Gas Reporting Rule in Docket
ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's
responses.
Q. Equipment Leaks by Population Count
As noted in section III.P. of this preamble, subpart W reporters
are currently required to quantify emissions from equipment leaks using
the calculation methods in 40 CFR 98.233(q) (equipment leak surveys)
and/or 40 CFR 98.233(r) (equipment leaks by population count),
depending upon the industry segment. The equipment leaks by population
count method uses the count of equipment components, subpart W emission
factors (e.g., existing table W-1A to subpart W for the Onshore
Petroleum and Natural Gas Production industry segment), and operating
time to estimate emissions from equipment leaks. For the Onshore
Petroleum and Natural Gas Production and Onshore Petroleum and Natural
Gas Gathering and Boosting industry segments, the count of equipment
components currently may be determined by counting each component
individually for each facility (Component Count Method 2) or the count
of equipment components may be estimated using the count of major
equipment and subpart W default average component counts for major
equipment (Component Count Method 1) in existing tables W-1B and W-1C,
as applicable. Reporters in other industry segments currently must
count each applicable component at the facility.
We are finalizing, as proposed, several amendments to the
calculation methodology provisions of 40 CFR 98.233(r) and the
reporting requirements in 40 CFR 98.236(r) to improve the quality of
the data collected, consistent with sections II.B. and II.C. of this
preamble. Consistent with the 2023 Subpart W Proposal, the key changes
included in this final rule are providing updated population count
emission factors based on recent peer reviewed studies for: major
equipment at Onshore Petroleum and Natural Gas Production and Onshore
Petroleum and Natural Gas Gathering and Boosting facilities; below
grade stations, pipeline mains, and pipeline services at natural gas
distribution facilities; and gathering pipelines at Onshore Petroleum
and Natural Gas Gathering and Boosting facilities.
1. Onshore Petroleum and Natural Gas Production and Onshore Petroleum
and Natural Gas Gathering and Boosting Population Count Method
The EPA is finalizing several revisions related to equipment leaks
by population count for equipment at onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and boosting
facilities as described in this section. The EPA received only minor
comments regarding these revisions. See the document Summary of Public
Comments and Responses for 2024 Final Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems under the
Greenhouse Gas Reporting Rule in Docket ID. No. EPA-HQ-OAR-2023-0234
for these comments and the EPA's responses.
The existing population emission factors for the Onshore Petroleum
and Natural Gas Production and Onshore Petroleum and Natural Gas
Gathering and Boosting industry segments are found in existing table W-
1A to subpart W. The gas service population emission factors are based
on the 1996 GRI/EPA study Methane Emissions from the Natural Gas
Industry, Volume 8: Equipment Leaks (available in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234). The oil service
population emission factors are based on the API's Emission Factors for
Oil and Gas Production Operations, Publication 4615, published in 1995.
As noted previously in this section, when estimating emissions
using the population count method, onshore petroleum and natural gas
production facilities and onshore petroleum and natural gas gathering
and boosting facilities currently under the existing provisions have
the option to use actual component counts (i.e., Component Count Method
2) or to estimate their component counts using the count of major
equipment (e.g., wellhead) and default component counts per major
equipment (e.g., valves per wellhead) included in existing tables W-1B
and W-1C of subpart W (i.e., Component Count Method 1). In reviewing
subpart W data, we find that the vast majority (greater than 95
percent) of onshore production and natural gas gathering and boosting
facilities use Component
[[Page 42174]]
Count Method 1 to estimate the count of components.
In the years that have followed the adoption of these emission
factors into subpart W, there have been numerous studies regarding
emissions from equipment leaks at onshore production and gathering and
boosting facilities. Based on our review of these studies, our
assessment is that they support revision of the population count method
and corresponding emission factors for onshore petroleum and natural
gas production and onshore petroleum and natural gas gathering and
boosting facilities, and we are finalizing as proposed amendments to
this population count method and corresponding emission factors after
consideration of these more recent study data, consistent with section
II.B. of this preamble. These final amendments include new population
emission factors that are on a per major equipment basis rather than a
per component basis. As mentioned previously, the vast majority of
reporters estimate the component counts using Component Count Method 1.
By providing emission factors on a major equipment basis instead of by
component, we will eliminate the step to estimate the number of
components. All facilities will be able to count the actual number of
major equipment and consistently apply the same emission factor to
calculate emissions. This will reduce reporter burden and reduce the
number of errors in the calculation of emissions, as we find that
numerous facilities incorrectly estimate the number of components using
Component Count Method 1 while providing consistently estimated
emission results.
In comparing the recent study data for the 2023 Subpart W proposal
and this final rule, we concluded that the Rutherford et al. (2021)
study represents the most robust sample size of approximately 3,700
measurements for developing population emission factors by major
equipment. The larger sample size is likely more representative of
varying degrees of leak detection and repair programs (i.e., not only
facilities conducting frequent surveys), which can impact the number of
leaks found during surveys (i.e., if more frequent surveys are being
conducted and leaks are being repaired in a timely manner, then each
survey likely finds less leaks). The Rutherford et al. (2021) study
also employs a bootstrap resampling statistical approach \72\ that
allows for the inclusion of infrequent large equipment leaks in the
development of the emission factors, improving the representation of
the inherent variability of equipment leaks in the developed emission
factors. Therefore, we are finalizing as proposed major equipment
emission factors developed using Rutherford et al. (2021) to provide
population emission factors by major equipment and site type (i.e.,
natural gas system or petroleum system). The final emission factors
were taken from Supplementary Tables 3 and 4 of Rutherford et al.
(2021). The average emission factors presented in these study tables
were converted from units of kilograms per day to standard cubic feet
of whole gas per hour for cumulative equipment component leaks from
different types of major equipment including wellheads, separators,
heaters, meters including headers, compressors, dehydrators and tanks.
The major equipment indicating venting emissions (e.g., tanks--
unintentional vents) or emissions from other sources also covered by
subpart W (e.g., liquids unloading, flaring, pumps) are not included in
the final equipment leak population emission factors. Consistent with
current requirements related to meters/piping at existing 40 CFR
98.233(r)(2)(i)(A), we are finalizing in 40 CFR 98.233(r)(2) that one
meters/piping equipment should be included per well-pad for onshore
petroleum and natural gas production operations and the count of meters
in the facility should be used for this equipment category at onshore
petroleum and natural gas gathering and boosting facilities. As a
consequence of the broader scope of equipment surveyed in the study
data that inform Rutherford et al. (2021), the final emission factors
in final table W-1 to subpart W include more pieces of major equipment
than are currently included in table W-1B and W-1C to subpart W. A
complete description of the derivation of the final emission factors is
discussed in more detail in the subpart W TSD, available in the docket
for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234. The final
major equipment emission factors will replace the current component-
based emission factors in the existing table W-1A. We are also
finalizing removal, as proposed, of tables W-1B, W-1C, and W-1D since
they will no longer be needed for the population count method for these
industry segments. We are finalizing amendments, as proposed, to the
reporting requirements for the use of the population count method to
align with the reporting of major equipment counts consistent with the
final emission factors in 40 CFR 98.236(r).
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\72\ Bootstrapping is a type of resampling where a known dataset
is repeatedly drawn from, with replacement, to generate a sample
distribution.
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2. Natural Gas Distribution Emission Factors
The EPA is finalizing several revisions related to equipment leaks
by population count for equipment at natural gas distribution
facilities as described in this section. The EPA received only minor
comments regarding these revisions. See the document Summary of Public
Comments and Responses for 2024 Final Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems under the
Greenhouse Gas Reporting Rule in Docket ID. No. EPA-HQ-OAR-2023-0234
for these comments and the EPA's responses.
Natural gas distribution companies currently under the existing
provisions quantify the emissions from equipment leaks from pipeline
mains and services, below grade transmission distribution transfer
stations, and below grade metering-regulating stations following the
procedures in 40 CFR 98.233(r). This method uses the count of
equipment, subpart W population emission factors in existing table W-7
(final table W-5) to subpart W, and operating time to estimate
emissions. The population emission factors for distribution mains and
services in existing table W-7 (final table W-5) are based on
information from the 1996 GRI/EPA study.\73\ Specifically for plastic
mains, additional data are sourced from a 2005 ICF analysis.\74\ The
population emission factors for distribution mains are published per
mile of main by pipeline material and emission factors for distribution
services are published per service by pipeline material. The population
emission factors for below grade stations in existing table W-7 (final
table W-5) are based on information from the 1996 GRI/EPA study.\75\
The population emission
[[Page 42175]]
factors for below grade transmission-distribution transfer stations and
below grade metering-regulating stations are currently specified in the
existing table W-7 per station by three inlet pressure categories (>300
pounds per square inch gauge (psig), 100-300 psig, <100 psig).
---------------------------------------------------------------------------
\73\ GRI/EPA. Methane Emissions from the Natural Gas Industry,
Volume 9: Underground Pipelines. Prepared for Gas Research Institute
and U.S. Environmental Protection Agency National Risk Management
Research Laboratory by L.M. Campbell, M.V. Campbell, and D.L.
Epperson, Radian International LLC. GRI-94/0257.2b, EPA-600/R-96-
080i. June 1996. Available in the docket for this rulemaking, Docket
ID. No. EPA-HQ-OAR-2023-0234.
\74\ ICF. Fugitive Emissions from Plastic Pipe, Memorandum from
H. Mallya and Z. Schaffer, ICF Consulting to L. Hanle and E.
Scheehle, EPA. June 30, 2005. Available in the docket for this
rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
\75\ GRI/EPA. Methane Emissions from the Natural Gas Industry,
Volume 10: Metering and Pressure Regulating Stations in Natural Gas
Transmission and Distribution. Prepared for Gas Research Institute
and U.S. Environmental Protection Agency National Risk Management
Research Laboratory by L.M. Campbell and B.E. Stapper, Radian
International LLC. GRI-94/0257.27, EPA-600/R-96-080j. June 1996.
Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------
In this rulemaking, the EPA is finalizing as proposed to update the
population emission factors in existing table W-7 (final table W-5) to
subpart W using the results of studies and information that were not
available when the rule was finalized in 2010. Notably, the EPA
reviewed recent studies and updated the emission factors for several
natural gas distribution sources, including pipeline mains and services
and below grade stations, for the 2016 U.S. GHG Inventory.\76\ The
majority of the U.S. GHG Inventory updates were based on data published
by Lamb et al. in 2015.\77\ Since the time that the 2016 U.S. GHG
Inventory updates were made, additional studies for pipeline
distribution mains have been published and reviewed by the EPA
including Weller et al. in 2020.\78\ Our assessment of the studies
published since subpart W was finalized supports revising the emission
factors for pipelines in the Natural Gas Distribution industry segment
of subpart W.
---------------------------------------------------------------------------
\76\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2014: Revisions to Natural Gas Distribution Emissions.
April 2016. Available at https://www.epa.gov/sites/production/files/2016-08/documents/final_revision_ng_distribution_emissions_2016-04-14.pdf and in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2023-0234.
\77\ Lamb, B.K. et al. ``Direct Measurements Show Decreasing
Methane Emissions from Natural Gas Local Distribution Systems in the
United States.'' Environ. Sci. Technol. 2015, 49, 5161-5169.
Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2023-0234.
\78\ Weller, Z.D.; Hamburg, S.P.; and Von Fischer, J.C. 2020.
``A National Estimate of Methane Leakage from Pipeline Mains in
Natural Gas Local Distribution Systems.'' Environ. Sci. Technol.
2020, 54(1), 8958. Available in the docket for this rulemaking,
Docket ID. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------
The population emission factors for distribution mains and services
are a function of the average measured leak rate (in standard cubic
feet per hour) and the frequency of annual leaks observed (leaks/mile-
year or leaks/service-year) by pipeline material (e.g., protected
steel, plastic). The Lamb et al. and Weller et al. studies utilized
different approaches for quantifying leak rates and determining the
pipeline material-specific frequency of annual leaks. The Lamb et al.
study quantified leaks from distribution mains and services using a
high volume sampling method and some downwind tracer measurements and
estimated the frequency of leaks by pipeline material using company
records and Department of Transportation (DOT) repaired leak records
from six local distribution companies (LDCs). This methodology was
consistent with the 1996 GRI/EPA study. The Weller et al. study
quantified leaks from only distribution mains using the Advanced Mobile
Leak Detection (AMLD) technique, which involved mobile surveying using
high sensitivity instruments and algorithms that predicted the leak
location and size, attributed leaks to the pipeline material using
geographic information system (GIS) data, and estimated the frequency
of leaks using modeling.
In the 2022 proposed rule, we proposed to revise the pipeline main
equipment leak emission factors using a combination of data from Lamb
et al. (2015) and Weller et al. (2020). We sought comment on the
approach of combining data from these two studies. We received numerous
comments regarding the classification of pipeline materials and
respective quantified leaks in the Weller et al. (2020) study. As
discussed in more detail below, we agreed with commenters on the 2022
proposed rule that the categorization of pipeline leaks by material
type likely resulted in inaccuracies specifically for the unprotected
and protected steel pipeline material types. Therefore, in this
rulemaking, we are finalizing as proposed in the 2023 Subpart W
Proposal revisions of the equipment leak pipeline main emission factors
using more recent study data from the Lamb et al. (2015) study.
In subpart W, there are currently four categories of pipeline
mains: unprotected steel, protected steel, plastic, and cast iron. The
steel categories are differentiated by the presence of cathodic
protection, and, as evidenced by the 1996 GRI/EPA study and Lamb et al.
study data, unprotected steel pipelines are considered to be more leak
prone than cathodically protected steel pipelines. In the Weller et al.
study, the categories of pipeline mains include bare (unprotected)
steel, coated (protected) steel, cast iron, and plastic. We note that
steel pipelines can be protected by cathodic protection and/or coating,
and in the Weller et al. study, cathodically unprotected yet coated
steel pipeline mains appear to have been grouped with cathodically
protected steel pipeline mains. Using the unprotected and protected
steel classifications in the Weller et al. study would thus result in
emission factors for protected steel that are higher than for
unprotected steel, which would conflict with other study data (e.g.,
1996 GRI/EPA, Lamb et al.) as well as voluntary emissions reductions
programs (e.g., EPA Natural Gas STAR). The pipeline categories in the
Weller et al. study do not provide the necessary differentiation to be
used to properly update the emission factors for unprotected (i.e., not
cathodically protected) steel and cathodically protected steel pipeline
mains. For more information on the review and analysis of the Lamb et
al. and Weller et al. studies, see the subpart W TSD, available in the
docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
In consideration of our review and analysis of recent study data
relative to natural gas pipeline mains and services, and consistent
with the emission factors used in the 2016 U.S. GHG Inventory, we are
finalizing as proposed in the 2023 Subpart W Proposal to provide
emission factors for distribution pipeline mains and services based on
the Lamb et al. study leak rates and the 1996 GRI/EPA study leak
incidence data. For more information on the derivation of the final
emission factors, see the subpart W TSD, available in the docket for
this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234).
For below grade stations, the 2016 U.S. GHG Inventory also began
applying a new emission factor from the data published by Lamb et al.
to the count of stations to estimate emissions from these sources. In
order to assess the appropriateness of incorporating this revision into
the subpart W requirements for below grade stations (i.e., replacing
the set of below grade emission factors by station type and inlet
pressure with one single emission factor), the EPA performed an
analysis of the reported subpart W data for below grade stations
compared to data from the recent studies (see the subpart W TSD,
available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-
2023-0234). We found that the subpart W reported station count combined
with the current subpart W emission factors yields an average emission
factor similar to the U.S. GHG Inventory emission factor; as such,
using either set of emission factors would yield approximately the same
emissions results for the GHGRP.
Therefore, we are finalizing as proposed to amend the emission
factors for below grade transmission-distribution transfer stations and
below grade metering-regulating stations in existing table W-7 (final
table W-5) to
[[Page 42176]]
subpart W to a single emission factor without regard to inlet pressure.
We are also finalizing as proposed to amend the corresponding section
header in existing table W-7 (final table W-5) for below grade station
emission factors and the references to existing table W-7 (proposed
table W-5) in 40 CFR 98.233(r)(6)(i) to clarify the emission factor
that should be applied to both types of below grade stations (i.e.,
transmission-distribution transfer and metering-regulating). This final
amendment will impact the reporting requirements in 40 CFR 98.236(r) as
well, as it will consolidate six emission source types to two emission
source types (below grade transmission-distribution transfer stations
and below grade metering-regulating stations, without differentiating
between inlet pressures) for purposes of reporting under 40 CFR
98.236(r)(1). Consistent with section II.B. of this preamble, this
final amendment will improve the data quality through use of more
recent emission factors and would be consistent with changes made to
the U.S. GHG Inventory. It will also result in reporting of fewer data
elements, consistent with section II.C. of this preamble.
3. Gathering Pipeline Emission Factors
a. Summary of Final Amendments
Facilities in the Onshore Petroleum and Natural Gas Gathering and
Boosting industry segment currently under existing provisions quantify
the emissions from equipment leaks from gathering pipelines following
the procedures in 40 CFR 98.233(r). This method uses the count of
equipment, subpart W population emission factors in existing table W-1A
to subpart W, and operating time to estimate emissions. The population
emission factors for gathering pipelines in existing table W-1A are
based on leak rates from natural gas distribution companies and
gathering pipeline-specific activity data as provided in the 1996 GRI/
EPA study.\79\ The population emission factors for gathering pipelines
are published per mile by pipeline material.
---------------------------------------------------------------------------
\79\ GRI/EPA. Methane Emissions from the Natural Gas Industry,
Volume 9: Underground Pipelines. Prepared for Gas Research Institute
and U.S. Environmental Protection Agency National Risk Management
Research Laboratory by L.M. Campbell, M.V. Campbell, and D.L.
Epperson, Radian International LLC. GRI-94/0257.2b, EPA-600/R-96-
080i. June 1996. Available in the docket for this rulemaking, Docket
ID. No. EPA-HQ-OAR-2023-0234.
---------------------------------------------------------------------------
As noted in section III.Q.2. of this preamble, the EPA is
finalizing as proposed the update to the natural gas distribution
population emission factors in existing table W-7 (final table W-5) to
subpart W using the results of studies and information that were not
available when the rule was originally finalized. In particular, the
EPA is finalizing as proposed the update to the leak rate portion of
the emission factor based on data published by Lamb et al. in 2015.\80\
The EPA has reviewed the recent studies published for Onshore petroleum
and natural gas gathering and boosting facilities including the Yu et
al. study in the 2023 Subpart W Proposal, as well as additional studies
identified in public comments, and concluded that there is currently
insufficient data to update the existing emission factors with
nationally representative population emission factors for gathering
pipelines that are based on collection of data from gathering pipelines
rather than distribution pipelines. Therefore, consistent with the
updates to the emission factors for distribution mains, and consistent
with section II.B. of this preamble, we are finalizing as proposed the
update to the gathering pipeline population emission factors in
proposed table W-1 to use the leak rates from Lamb et al. (2015). We
did not propose and are not finalizing updates to the activity data
(leaks per mile of pipeline) portion of the emission factors, as the
information in the 1996 GRI/EPA study continues to be the best
available data specific to gathering pipelines. For more information as
well as responses to comments we received on the updates to the
gathering pipeline population emission factors, see section 12 of the
subpart W TSD and section 18.3 of the Summary of Public Comments and
Responses for 2024 Final Revisions and Confidentiality Determinations
for Petroleum and Natural Gas Systems under the Greenhouse Gas
Reporting Rule, available in the docket for this rulemaking (Docket ID.
No. EPA-HQ-OAR-2023-0234).
---------------------------------------------------------------------------
\80\ Lamb, B.K. et al. ``Direct Measurements Show Decreasing
Methane Emissions from Natural Gas Local Distribution Systems in the
United States.'' Environ. Sci. Technol. 2015, 49, 5161-5169.
Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2023-0234.
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b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments for gathering pipelines.
Comment: Commenters asked that the EPA provide operators with the
option to use monitoring and measurement surveys to quantify gathering
pipeline leak emissions.
Response: See the EPA's response to comments in section III.C.1.b.
of this preamble requesting that the EPA allow a leaker emission factor
approach and/or direct measurement of transmission pipeline leak
emissions, which is also applicable to gathering pipelines and
responsive to this comment.
R. Offshore Production
1. Summary of Final Amendments
Currently, subpart W requires offshore production facilities to
report emissions consistent with the methods published by the U.S.
Department of Interior, Bureau of Ocean Energy Management (BOEM). Since
subpart W was first promulgated, there have been a number of updates to
the BOEM requirements and how BOEM implements the requirements (e.g.,
the development of their Outer Continental Shelf Air Quality System
(OCS AQS)\81\), and the EPA is finalizing amendments to subpart W to
reflect those changes. Specifically, the EPA is finalizing as proposed
the update of the outdated acronym ``BOEMRE'' to the current acronym
``BOEM'' in 40 CFR 98.232(b), 40 CFR 98.233(s), and 40 CFR 98.236(s);
the update of the cross references to the BOEM requirements from ``30
CFR 250.302 through 304'' to ``30 CFR 550.302 through 304'' in 40 CFR
98.232(b), 40 CFR 98.233(s), and the introductory paragraph of 40 CFR
98.234; and the removal of the outdated references to ``GOADS'' from 40
CFR 98.233(s). The EPA is also finalizing as proposed the adjustments
of some of the language in 40 CFR 98.232(b) and 40 CFR 98.233(s) to
more accurately reflect the current BOEM program and requirements
(e.g., adjusting the number of years between BOEM data collection
efforts from 4 to 3 years, referring to a published emissions inventory
rather than an emissions study).
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\81\ For more information on this system and the emissions
inventories collected by the system, see https://www.boem.gov/environment/environmental-studies/ocs-emissions-inventories.
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Emissions data are collected by BOEM every few years. In years that
coincide with a year in which BOEM collects data, offshore production
facilities that report emissions inventory data to BOEM report the same
annual emissions to subpart W as calculated and reported to BOEM
(existing 40 CFR 98.233(s)(1)) and facilities that do not report
emissions inventory data to BOEM must use the most recent monitoring
and calculation methods published by BOEM (existing 40 CFR
98.233(s)(2)). In the intervening years, reporters currently are
required to adjust emissions based on the operating time
[[Page 42177]]
for the facility in the current reporting year relative to the
operating time in the most recent BOEM data submission or BOEM
emissions study publication year. The EPA finalizing revisions to these
calculation methods based on consideration of public comments. The EPA
is finalizing a requirement in 40 CFR 98.233(s)(1)(i) that if the
BOEM's emissions reporting system is available and the facility has the
data needed to use BOEM's emissions reporting system, reporters must
calculate emissions using the most recent monitoring and calculation
methods published by BOEM referenced in 30 CFR 550.302 through 304
(currently implemented through the OCS AQS). This includes years in
which offshore production facilities are required to report emissions
inventory data to BOEM as well as intervening years. In the final
amendments, the current adjustment using operating hours in years that
do not overlap with the most recent published BOEM emissions inventory
or BOEM data submission, as app'icable, will only be allowed if the
BOEM's emissions reporting system is not available or if the facility
'oes not have the data needed to use BOEM's emissions reporting system
(which may be the case in years in which offshore production facilities
are not required to report emissions inventory data to BOEM). The EPA
is finalizing parallel requirements in 40 CFR 98.233(s)(2)(i) for
facilities that do not report to BOEM's emissions inventory except that
these requirements refer only to the calculation methods published by
BOEM referenced in 30 CFR 550.302 through 304 because these facilities
do not currently have access to the OCS AQS system. The 2023 Subpart W
Proposal would have maintained the method of adjusting emissions using
operating hours as the primary method and provided use of BOEM's
monitoring and calculation methods as an alternative, but this final
amendment will further improve data quality through the use of more
empirical data, consistent with section II.B. of this preamble. The EPA
is also amending 40 CFR 98.233(s)(3) to clarify the requirement that
offshore production reporters must calculate emissions using BOEM's
methods at least once every 3 years. The current rule provides
provisions for delays in BOEM's data collection effort beyond 4 years,
and the EPA is revising that language to specify requirements for
calculation if BOEM's emissions reporting system is unavailable for
more than 3 consecutive years, consistent with the updated language in
40 CFR 98.233(s)(1)(i) and (s)(2)(i).
The EPA is also finalizing changes to the reporting requirements in
40 CFR 98.236. First, to improve the verification of the emissions
reported by offshore production facilities to the GHGRP by establishing
a definitive crosswalk between the data submitted to BOEM's Outer
Continental Shelf Emissions Inventory and the GHGRP, the EPA is
finalizing as proposed the requirement that offshore production
facilities report the BOEM Facility ID(s) that constitute the GHGRP
facility. Having a definitive point of reference between the two
datasets will allow the EPA to better verify the emissions reported to
the GHGRP. Second, for years in which a reporter does calculate
emissions by adjusting emissions using a ratio of operating hours, the
EPA is finalizing as proposed the requirement to report the facility's
operating hours in the current year in 40 CFR 98.236(s)(2)(ii). The EPA
is finalizing the other proposed data element, 40 CFR 98.236(s)(2)(i),
with slight wording changes from proposal that reflect the final
calculation methods described in the previous paragraph. Specifically,
the reporter will report the facility's operating hours for the most
recent year in which emissions were calculated according to either 40
CFR 98.233(s)(1)(ii) or 40 CFR 98.233(s)(2)(ii). This information will
improve verification, consistent with section II.C. of this preamble.
For clarification, the EPA is also finalizing a change from proposal to
update 40 CFR 98.232(b) to state that offshore platforms do not need to
report emissions from portable equipment, in place of the existing
language that offshore platforms do not need to report portable
emissions.
2. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments for offshore production emissions.
Comment: Commenters suggested that instead of allowing reporters to
calculate their emissions each year using BOEM's methods as an
alternative to the current requirement to adjust emissions based on
operating hours, the EPA should require offshore production facilities
to calculate their emissions each year using BOEM's methods. While
commenters expressed concern that BOEM's methods are not well-
documented and currently rely mostly on emission factors, they did note
that BOEM is working to incorporate additional information such as top-
down data into their calculation methods, and requiring reporters to
use those methods every year would at least ensure that updates to
BOEM's methods are incorporated into subpart W as soon as possible.
Commenters also stated that requiring use of BOEM's methods every year
instead of allowing that as an option would prevent reporters from
choosing the option that they predict would result in less emissions.
Response: The EPA has considered these comments and reviewed
additional information available about BOEM's OCS AQS. We agree that
directing reporters to use BOEM methods to calculate emissions every
year as the primary calculation method is consistent with the
directives in CAA section 136(h), including ensuring accuracy in total
emissions reported for each reporting year. The final amendments to 40
CFR 98.233(s)(1)(i) and (s)(2)(i) require reporters to use BOEM's
emission inventory system or calculation methods published by BOEM
referenced in 30 CFR 550.302 through 304 to calculate emissions for any
year in which the system is available and they have collected the
necessary data to do so, including years in which facilities report
emissions directly to BOEM. The final revisions allow adjustments made
based on operating time as an alternative method to adjust emissions;
however, the EPA is finalizing revisions to 40 CFR 98.233(s)(3) to
require that facilities calculate emissions based on BOEM's calculation
methods at least every 3 years.
Comment: One commenter requested that the EPA add ``fugitive
sources'' after ``equipment leaks'' in 40 CFR 98.232(b) for consistency
with the BOEM's descriptions of emission source types.
Response: The EPA has reviewed BOEM's documentation and agrees that
BOEM uses the term ``fugitives'' to refer to leaks from equipment
components (generally referred to as ``equipment leaks'' in subpart W).
The EPA has added the parenthetical ``(i.e., fugitives)'' to both 40
CFR 98.232(b) and 40 CFR 98.233(s) introductory text.
S. Combustion Equipment
1. Calculation Methodology Applicability, Higher Heating Value, and
Other Calculation Methodology Clarifications
a. Summary of Final Amendments
All facilities reporting under subpart W except those in the
Onshore Natural Gas Transmission Pipeline industry segment must include
combustion emissions in their annual report. Facilities in the Onshore
Petroleum and
[[Page 42178]]
Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and
Boosting, and Natural Gas Distribution industry segments calculate
emissions in accordance with the provisions in 40 CFR 98.233(z) and
report combustion emissions per 40 CFR 98.236(z). Reporters in the
other industry segments calculate and report combustion emissions under
subpart C (General Stationary Fuel Combustion Sources). Subpart W
refers reporters in these segments to the calculation methodologies in
subpart C to determine combustion emissions for certain fuels.
The EPA is finalizing several amendments for the industry segments
that report combustion equipment emissions under subpart W to improve
the accuracy of the emissions calculated and therefore the quality of
data collected, consistent with section II.B. of this preamble. First,
we are finalizing as proposed the move of the existing provisions for
fuels that do not meet the specifications to use subpart C
methodologies from 40 CFR 98.233(z)(2) to a new paragraph 40 CFR
98.233(z)(3). Second, we are finalizing as proposed the move of the
language in 40 CFR 98.233(z)(1)(ii) to 40 CFR 98.233(z)(5), and we are
finalizing the proposed wording changes to highlight that this
paragraph refers only to the requirement to report combustion emissions
under subpart W. We are also finalizing as proposed the addition of a
reference to this new paragraph 40 CFR 98.233(z)(5) in both 40 CFR
98.233(z)(1)(ii) and 98.233(z)(2)(ii). Third, the EPA is revising 40
CFR 98.233(z)(1) as proposed to remove the references to field gas and
process vent gas and include only the characteristics for the fuels
that can use subpart C methodologies. The EPA is also finalizing as
proposed conforming edits to existing 40 CFR 98.233(z)(2) (final 40 CFR
98.233(z)(3)) for consistency. Fourth, as proposed, the EPA is
finalizing the revision to the language in existing 40 CFR
98.233(z)(2)(ii) (final 40 CFR 98.233(z)(3)(ii)(B)) to allow the use of
engineering estimates based on best available data to determine the
concentration of each constituent in the flow of gas to the unit, which
would allow reporters to use the best information available to
determine the gas composition while maintaining the option for
reporters to use 40 CFR 98.233(u)(2) if they do not have other stream-
specific information. Fifth, we are finalizing as proposed the
amendment of the definition of the variable for the HHV in equation W-
40 in 40 CFR 98.233(z)(3)(ii) to require the use of a site-specific
value.
As explained in the 2023 Subpart W Proposal, the EPA proposed
several revisions to address stakeholder requests to expand the ability
to use subpart C calculation methodologies to additional fuel types and
to improve the accuracy of the emissions calculated and therefore the
quality of data collected, consistent with section II.B. of this
preamble. Specifically, the EPA proposed to specify in a new paragraph
in 40 CFR 98.233(z)(2) that subpart C methodologies Tier 2, Tier 3, or
Tier 4 may be used to calculate emissions from the combustion of a fuel
that meets the definition of ``natural gas'' in 40 CFR 98.238 if it has
a minimum HHV of 950 Btu/scf, a maximum CO2 content of 1 percent by
volume, and a minimum CH4 content of 85 percent by volume.
We also requested comment on whether additional specification criteria
should be included (e.g., a maximum HHV). After consideration of public
comment, we updated our analysis of fuel compositions and our re-
analysis of the data showed that maintaining the minimum HHV at 950
Btu/scf, limiting the maximum HHV to 1,100 Btu/scf, and decreasing the
minimum CH4 content to 70 percent by volume resulted in a
data set for which emissions under both subpart C (Tier 2) and subpart
W were more consistently similar than the proposed parameters of
maximum CO2 content of 1 percent by volume and a minimum
CH4 content of 85 percent by volume. Therefore, we are
finalizing in 40 CFR 98.233(z)(2) that subpart C methodologies Tier 2,
Tier 3 or Tier 4 may be used to calculate emissions from the combustion
of a fuel that meets the definition of ``natural gas'' in 40 CFR 98.238
if it has a minimum HHV of 950 Btu/scf, a maximum HHV of 1,100 Btu/scf,
and a minimum CH4 content of 70 percent by volume.
Finally, we are finalizing two amendments to provide clarity and
improve understanding of the final rule, consistent with section II.D.
of this preamble. We are finalizing as proposed the amendments to 40
CFR 98.233(z)(1)(ii) and existing 40 CFR 98.233(z)(2) (final 40 CFR
98.233(z)(3)(ii)) and finalizing analogous language in 40 CFR
98.233(z)(2)(ii) to clarify that emissions may be calculated for either
each individual unit or groups of combustion units combusting the same
fuel. In addition, based on consideration of public comments and for
consistency with other paragraphs for specific emission source types,
we are amending the name of 40 CFR 98.233(z) and 40 CFR 98.236(z) to
remove the specific industry segment names and refer just to combustion
equipment.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to calculation methodology applicability, HHV,
and other calculation methodology clarifications (not including
revisions related to methane slip).
Comment: Commenters requested that the EPA define ``pipeline
quality natural gas.'' Commenters also asserted that the composition
requirements in proposed 40 CFR 98.233(z)(2)(i)(B) and (C) were not
justified and limited the combustion devices that would be able to use
the combustion methodologies in subpart C, which would in turn limit
the combustion devices that would be able to use performance test data
or manufacturer provided data to calculate emissions that include
methane slip.
Response: The EPA reviewed the comments, including the various
suggested definitions of ``pipeline quality natural gas,'' and reviewed
the analysis supporting the proposed compositions in 40 CFR
98.233(z)(2)(i)(B) and (C). First, the commenters varied in their
suggested definitions, identifying two different definitions of
``pipeline quality natural gas'' from EPA regulations and also
suggesting other provisions that they asserted are considered accepted
or understood definitions of ``pipeline quality natural gas.'' These
variations support the EPA's assertion from the 2023 Subpart W proposal
that pipeline quality specifications vary across the U.S. depending on
the requirements of the pipeline used to transport the gas. Therefore,
the EPA is not finalizing a definition of ``pipeline quality natural
gas'' for subpart W.
However, most of the specifications for pipeline quality natural
gas did include a maximum HHV and a minimum CH4 content of
70 percent, which was lower than the proposed minimum CH4
content of 85 percent. The EPA did not propose to include a maximum
higher heating value in 40 CFR 98.233(z)(2)(i), but the EPA did request
comment on additional parameters that should be considered. When
reviewing the data to assess the effect of the HHV, the EPA concluded
that maintaining the minimum HHV at 950 Btu/scf, limiting the maximum
HHV to 1,100 Btu/scf, and decreasing the minimum CH4 content
to 70 percent by volume resulted in a data set for which emissions
under both subpart C (Tier 2) and subpart W were more consistently
[[Page 42179]]
similar than the proposed parameters of maximum CO2 content
of 1 percent by volume and a minimum CH4 content of 85
percent by volume. The constituents other than CH4 and
CO2 in the natural gas stream include compounds that have no
heating value, such as hydrogen and nitrogen, as well as non-methane
hydrocarbons and NGLs (e.g., ethane, propane, butane). The more NGLs in
the stream, the more the emissions under the subpart C (Tier 2)
calculations differ from the subpart W calculations, and limiting the
maximum HHV reduces the number of streams with high quantities of NGLs
that could use subpart C (Tier 2) methods without needing to restrict
the CO2 content. For more information on our revised fuel
composition analysis for the final rule and the comparison of emissions
using various composition thresholds, see the final subpart W TSD,
available in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-
2023-0234).
As a result of this analysis, we are finalizing in 40 CFR
98.233(z)(2) that subpart C methodologies Tier 2 or higher may be used
for fuel meeting the definition of ``natural gas'' in 40 CFR 98.238 if
it has a minimum HHV of 950 Btu/scf, a maximum HHV of 1,100 Btu/scf,
and a minimum CH4 content of 70 percent by volume. These
specifications may in many cases be the same as the specifications for
pipeline quality natural gas, but including these specifications in a
separate paragraph of 40 CFR 98.233(z) maintains the flexibility to use
subpart C methods both in cases where a local definition of pipeline
quality natural gas might not be exactly the same as these
specifications (e.g., might have a slightly larger maximum heat
content) and in cases where a local definition of pipeline quality
natural gas is more restrictive than these specifications.
Revisions to the proposed provisions for combustion slip are
addressed in section III.S.2. of this preamble.
Comment: One commenter suggested that the EPA should update the
name of 40 CFR 93.233(z) and remove the references to the Onshore
Petroleum and Natural Gas Production, Onshore Petroleum and Natural Gas
Gathering and Boosting, and Natural Gas Distribution industry segments
because the proposed provisions for combustion slip apply to all
industry segments that must report combustion emissions.
Response: The EPA has reviewed this comment and is amending the
name of 40 CFR 98.233(z) and 40 CFR 98.236(z) to remove the references
to specific industry segments. The lists in 40 CFR 98.232 define which
emission sources must be included in reports for each industry segment,
so it is unnecessary and duplicative to include industry segment names
in the emission source type paragraph names. This final amendment is
also consistent with other changes to emission source type names, such
as hydrocarbon liquids and produced water storage tanks in 40 CFR
98.233(j). The EPA notes that 40 CFR 98.232, specifically 40 CFR
98.232(c)(22), (i)(7), and (j)(12), continues to specify the industry
segments that must calculate emissions according to 40 CFR 98.233(z)
and report emissions under 40 CFR 98.236(z); this name change does not
mean that additional industry segments will report combustion equipment
emissions under 40 CFR 98.236(z) than under the existing requirements.
The EPA is finalizing amendments to subpart C to implement revisions to
account for methane slip from combustion devices in industry segments
that report combustion emissions under subpart C, as described in
section III.S.2. of this preamble. While those amendments cross-
reference 40 CFR 98.233(z)(4), that does not make the combustion
devices in industry segments that report combustion emissions under
subpart C subject to 40 CFR 98.233(z) in its entirety, nor do cross-
references to subpart C from 40 CFR 98.233(z)(1) and (2) make
combustion equipment in the Onshore Petroleum and Natural Gas
Production, Onshore Petroleum and Natural Gas Gathering and Boosting,
and Natural Gas Distribution industry segments subject to subpart C.
2. Methane Slip From Internal Combustion Equipment
a. Summary of Final Amendments
The authors of several recent studies have examined combustion
emissions at Onshore Petroleum and Natural Gas Gathering and Boosting
facilities and have demonstrated that a significant portion of
emissions can result from unburned CH4 entrained in the
exhaust of natural gas compressor engines (also referred to as
``combustion slip'' or ``methane slip''). These studies contend that
emissions from natural gas compressor engines included in the GHGRP are
significantly underestimated because they do not accurately account for
combustion slip. The EPA performed a review of each of these studies
and the U.S. GHG Inventory to determine whether and how combustion slip
emissions have been incorporated into published data and how the
incorporation of combustion slip would affect the emissions from the
petroleum and natural gas system sector reported to the GHGRP (see the
subpart W TSD, available in the docket for this rulemaking, Docket ID.
No. EPA-HQ-OAR-2023-0234).
Consistent with section II.A. of this preamble, we are revising the
methodologies for determining combustion emissions from RICE and GT to
account for combustion slip. For the three subpart W industry segments
reporting combustion emissions under subpart W (Onshore Petroleum and
Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and
Boosting, and Natural Gas Distribution), we are finalizing as proposed
that RICE and GT units combusting natural gas that calculate emissions
using the subpart C calculation methodologies per 40 CFR 98.233(z)(1)
and 98.233(z)(2) have three options in 40 CFR 98.233(z)(4) to quantify
emissions from combustion slip, including direct measurement using a
performance test, the use of OEM data, or the use of default emission
factors. For facilities that conduct a performance test to calculate
combustion slip under 40 CFR 98.233(z)(4)(i), the performance test must
be completed in accordance with one of the test methods in 40 CFR
98.234(i), which include EPA Methods 18 and 320 as well as an alternate
method, ASTM D6348-12 (Reapproved 2020), Standard Test Method for
Determination of Gaseous Compounds by Extractive Direct Interface
Fourier Transform Infrared (FTIR) Spectroscopy, Approved December 1,
2020. After consideration of public comments, we are finalizing Method
25A with nonmethane cutter as described in 40 CFR 1065.265 (as
specified in table 2 of 40 CFR part 60, subpart JJJJ) as an additional
test method for use in performance testing. The results of the
performance test must be used to develop an emission factor for use in
the CH4 emissions calculation. If a facility is required
(for compliance with other EPA regulations) or elects to conduct a
performance test for any reason (e.g., to demonstrate compliance with
permit conditions, assess equipment performance), they must use the
results of the performance test to calculate methane slip emissions.
When multiple performance tests are completed in the same reporting
year, the arithmetic average of all emission factors for the
corresponding performance tests must be used in CH4
emissions calculation. For facilities that did not conduct a
performance test for any reason and elect to use OEM data, which may
include manufacturer specification sheets, emissions
[[Page 42180]]
certification data, or other manufacturer data providing expected
emission rates from the RICE or GT, we are finalizing as proposed that
the reporter use the OEM data to develop an emission factor for use in
their emissions calculations for CH4. For facilities that
did not conduct a performance test for any reason and elect to the use
the final default emission factors, which the EPA developed using data
from Zimmerle et al. (2019), we are requiring the reporter to select
the appropriate emission factor by equipment type (e.g., 2-stroke lean-
burn, 4-stroke lean-burn, 4-stroke rich-burn, or GT) in new table W-7
rather than the emission factors in table C-2 for use in their
emissions calculations for CH4.
We proposed not to allow performance testing for facilities
operating RICE and GT units combusting fuels that fall under 40 CFR
98.233(z)(3) due to variability in fuel composition. Stakeholders
provided quarterly compressor station gas composition for units
combusting fuels that fall under all categories described in 40 CFR
98.233. In general, we observed fuel compositions that fell under 40
CFR 98.233(z)(3) did not significantly vary more than fuels that fell
under 40 CFR 98.233(z)(2), therefore we are adding performance testing
as another option under 40 CFR 98.233(z)(3)(ii)(C) to determine
CH4 emissions. Previously, for fuels under 40 CFR
98.233(z)(3), CH4 emissions could only be determined using a
default equipment-specific combustion efficiency, provided in equations
W-39A and W-39B and combined with fuel composition to calculate
emissions. The second option being added for fuels under 40 CFR
98.233(z)(3) is based on direct measurement using a performance test in
accordance with one of the test methods in 40 CFR 98.234(i), the same
as the first option provided for natural gas that meets the
specifications in either 40 CFR 98.233(z)(1) or (z)(2).
We expect that the records necessary to confirm the value for the
development of an emission factor based on the results of a performance
test or OEM data are already required to be maintained by the facility
per 40 CFR 98.237; thus, no new recordkeeping provisions relative to
the combustion slip amendments are being finalized. The EPA is
finalizing a new reporting requirement in 40 CFR 98.236(z)(2)
specifically for RICE and GT that combust natural gas that meets the
criteria of 40 CFR 98.233(z)(1) or (2) or a fuel meeting the
specifications of 40 CFR 98.233(z)(3) to specify the equipment type of
reported internal combustion units, the method used to estimate the
CH4 emission factor, and the value of the emission factor to
facilitate verification of the reported emissions. This amendment
requires the reporting of CH4 emissions from natural gas-
fired internal combustion engine and GT units, that are grouped for
reporting, must share the same equipment type (e.g., 4-stroke rich
burn), fuel type, and method for determining the CH4
emission factor, which will allow the EPA to adequately verify the
data.
Additionally, we are finalizing as proposed that RICE or GT units
in subpart W industry segments (i.e., Onshore Petroleum and Natural Gas
Production, Onshore Petroleum and Natural Gas Gathering and Boosting,
and Natural Gas Distribution) that estimate and report their combustion
emissions to subpart C and currently use either equation C-8, C-8a, C-
8b, C-9, C-9a, or C-10 in 40 CFR 98.33(c), as it corresponds to the
Tier methodology selected to estimate their CO2 emissions,
are required to use one of the options in 40 CFR 98.233(z)(4) to
develop a CH4 emission factor for use in these equations to
estimate CH4 emissions. Specifically, we are finalizing as
proposed the revision to the ``EF'' term in each of the equations in 40
CFR 98.33(c) (i.e., equations C-8, C-8a, C-8b, C-9a, C-9b, and C-10) to
reference the options for developing a CH4 emission factor
in 40 CFR 98.233(z)(4) for natural gas-fired RICE or GT. We are also
finalizing as proposed a footnote to table C-2 that specifies that for
reporters subject to subpart W, the default CH4 emission
factor in table C-2 for natural gas may only be used for natural gas-
fired combustion units that are not RICE or GT.
Finally, we are finalizing as proposed to amend 40 CFR 98.36(b),
(c)(1), and (c)(3) specifically for RICE or GT at facilities that are
subject to subpart W. These provisions currently provide the
requirements for reporting by emission unit, by aggregation of units or
by common pipe configurations. Under the new amendments, we are
requiring reporters that report emissions in accordance with 40 CFR
98.36(b), (c)(1), or (c)(3) to provide the equipment type (e.g., 2-
stroke lean burn RICE), the method used to determine the CH4
emission factor and the average value of the CH4 emission
factor. This change will ensure that sufficient data in the overall
aggregation of units or common pipe (i.e., multiple units combusting
natural gas) is reported such that we can perform review of the
supplied emission factor data and perform verification on the
corresponding emissions. Overall, these amendments to the subpart C
reporting requirements are analogous to and consistent with what is
being required for RICE or GT for facilities that report combustion
emissions under subpart W.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to methane slip.
Comment: Many commenters agreed methane slip should be extended to
all RICE and GTs regardless of application for all subpart W industry
segments that currently report combustion emissions in subpart C or W.
They acknowledged providing three methods for quantifying slip (default
emission factors, direct measurement, and OEM data) for RICE and GT
using natural gas outlined in 40 CFR 98.233(z)(1) and (2) increased the
accuracy of reported emissions. Several commenters agreed that fuel
types covered in proposed 40 CFR 98.233(z)(3) are too variable in
composition and emission factors would not be representative of real
operating conditions, so these fuel types should be limited to only
using default combustion efficiency values. In contrast, multiple
commenters suggested that the EPA allow reporters to use performance
tests to develop emission factors regardless of fuel type or be able to
demonstrate limited fuel variability in fuels not covered in 40 CFR
98.233(z)(1) and (2). Some commenters suggested if the operator
voluntarily performs an annual performance test or performance tests
required under other federal standards (NSPS Subpart JJJJ or NSPS
Subpart KKKK), these results should be allowed to determine combustion
slip instead of the proposed one-time performance test. Some commenters
stated that, additionally, not allowing performance tests for all RICE
and GT, regardless of the composition of the natural gas combusted,
will disincentive operators from deploying new emerging technology
meant to reduce emissions from this source category. Multiple
commenters asked for clarification about the requirements for
performance testing and if it was a one-time test or another required
frequency.
Response: The EPA acknowledges the commenters' support for
including combustion slip from RICE or GT irrespective of their use to
drive a compressor or the industry segment in which they operate. We
agree developing emission factors from direct measurement and using OEM
data for these engines and turbines will help to increase the accuracy
of the reported emissions. The EPA did not propose to
[[Page 42181]]
allow the use of performance testing to RICE or GTs that combust fuels
described in 40 CFR 98.233(z)(3) due to the suspected high variability
in the fuel composition. However, stakeholders provided quarterly
compressor station gas composition data for units combusting fuels that
fall under all categories described in 40 CFR 98.233(z). In general, we
observed fuel compositions that fell under 40 CFR 98.233(z)(3) did not
significantly vary more than fuels that fell under 40 CFR 98.233(z)(2);
therefore, for facilities operating RICE and GT units combusting fuels
that fall under 40 CFR 98.233(z)(3), we are adding performance testing
as another option to determine CH4 emissions. We are
finalizing an amendment to further extend the use of performance
testing to fuels that do not meet the natural gas specifications in 40
CFR 98.233(z)(1) or (2), as described in 40 CFR 98.233(z)(3). If a
facility combusting a fuel as described in 40 CFR 98.233(z)(3)(i)
elects to conduct a performance test in accordance with 40 CFR
98.233(z)(4)(i) for any reason (i.e., assess equipment performance,
provide data to meet company emission reduction goals, demonstrate
compliance with permits or regulations), the result of this performance
test would be required to be used to develop an emission factor and
used in equation W-40 of 40 CFR 98.234(z)(3)(ii)(G) to estimate
CH4 emissions, consistent with the approach proposed and
finalized for 40 CFR 98.233(z)(2). Additionally, when multiple
performance tests are completed in the same reporting year, the
arithmetic average of all emission factors for the corresponding
performance tests must be used in CH4 emissions calculation.
A facility that has not performed a performance test for any reason
must calculate their methane emissions as provided in 40 CFR
98.234(z)(3)(ii)(D) using equipment specific default combustion factors
with equation W-39B. We did not include a performance testing frequency
for fuels subject to 40 CFR 98.233(z)(3) because of their low
compositional variability, which is consistent with what we proposed
and are finalizing for fuels subject to 40 CFR 98.233(z)(1) or (2). By
further extending the use of direct measurement, reporters have both a
measurement and default option for additional fuels used in RICE and
GTs, consistent with directives in CAA section 136 and will help
incentivize the deployment of new technology meant to reduce emissions.
For more information on our evaluation, see the subpart W TSD,
available in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-
2023-0234).
Comment: Multiple commenters suggested adding additional test
methods for use in performance testing to measure CH4
concentrations. Some of the commenters recommended adding Method 25A
with nonmethane cutter as described in 40 CFR 1065.265 (as specified in
table 2 of 40 CFR part 60, subpart JJJJ). Commenters noted the
nonmethane cutter test method would allow for continuity in testing
procedures currently in place and allowed by both the EPA and state
agencies. Commenters stated that, additionally, this method would
decrease the burden related to operators having to perform multiple
tests to comply with different requirements of subpart W and better
align with tests conducted for NSPS JJJJ and NSPS ZZZZ. One commenter
recommended adding ASTM 6348-03, Standard Test Method for Determination
of Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy or portable fuel meters and thermodynamic
software to determine true horsepower to determine emission factors of
methane. The commenter suggested performance testing allows operators
to diagnose engine problems, that normally go undetected, resulting in
cleaner burning engines with improved performance.
Response: The addition of performance testing for all natural gas
fuels combusted in RICE and GT will improve the accuracy for
CH4 emission reporting in the GHGRP and align with the
directives in CAA section 136. To further increase flexibility and
alignment with other regulatory requirements, the EPA reviewed and is
adding Method 25A with Nonmethane cutter as described in 40 CFR
1065.265 to the approved testing methodologies listed in final 40 CFR
98.234(i). The EPA does not agree with including ASTM 6348-03, as it
has been superseded by a more recent version. Instead, the alternate
method ASTM 6348-12 (Reapproved 2020) is being finalized as an approved
testing methodology in 40 CFR 98.234(i). This method is the most
current version for the ``Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy.'' Additionally, the EPA does not agree
with allowing thermodynamic software to determine horsepower and
subsequently back calculating the CH4 emission factor. The
use of thermodynamic software in this way is useful for diagnosing
engine problems but has not been studied for its accuracy for
determining CH4 emissions. The EPA may add additional
methods to 40 CFR 98.234(i) in future amendments through a rulemaking
process.
3. Location of Reporting Requirements for Combustion Equipment
As noted in section III.S.1. of this preamble, facilities in the
Onshore Petroleum and Natural Gas Production, Onshore Petroleum and
Natural Gas Gathering and Boosting, and Natural Gas Distribution
industry segments must calculate combustion emissions in accordance
with 40 CFR 98.233(z) and report emissions under existing subpart W.
Facilities in the remaining industry segments (i.e., Offshore Petroleum
and Natural Gas Production, Onshore Natural Gas Processing, Onshore
Natural Gas Transmission Compression, Underground Natural Gas Storage,
LNG Storage, and LNG Import and Export Equipment) are required to
calculate combustion emissions in accordance with the provisions of 40
CFR 98.33 and report emissions under subpart C.
In the 2023 Subpart W Proposal, the EPA requested comment on
amending subpart W to specify that all industry segments would be
required to report their combustion emissions, including
CH4, under subpart W to more accurately reflect the total
CH4 emissions from such facilities within the emissions
reported under subpart W. The EPA received comments supporting the
reporting of all combustion emissions under subpart W but also received
comments suggesting that the EPA instead should require reporting of
all combustion emissions under subpart C, including combustion
emissions from the Onshore Petroleum and Natural Gas Production,
Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural
Gas Distribution industry segments that are currently reported under
subpart W. The EPA evaluated the comments and has decided not to take
final action on any of the requested changes to 40 CFR 98.232 regarding
which industry segments must report combustion emissions under subpart
W.
Section 136(h) of the CAA specifies that the EPA shall ``revise the
requirements of subpart W . . . to ensure the reporting under such
subpart . . . accurately reflect[s] the total methane emissions and
waste emissions from the applicable facilities.'' Sections 136(c) and
(e) of the CAA specify that the waste emissions charge provisions apply
to emissions reported pursuant to subpart W, and CAA section 136(d)
indicates that the term ``applicable facility'' means a facility within
an
[[Page 42182]]
affected industry segment, as defined in subpart W. At the time that
Congress drafted CAA section 136, the existing reporting structure in
which combustion emissions are reported under subpart C for some
industry segments and subpart W for other industry segments was already
established. Under CAA section 136(d), the nine affected industry
segments are categorized into four groups, and a waste emissions
threshold is applied to each of the four. Congress was aware of this
reporting struXXXndustryen it enacted CAA section 136 and established
the industry segment-specific thresholds. The EPA finds no indication
in the text of CAA section 136 suggesting that the thresholds should be
applied to an alternative to the existing reporting structure regarding
combustion emissions under subpart W.
T. Leak Detection and Measurement Methods
1. Acoustic Leak Detection
For emission source types for which measurements are required,
subpart W specifies the methods that may be used to make those
measurements in 40 CFR 98.234(a). To improve the quality of the data
when an acoustic leak detection device is used, consistent with section
II.B. of this preamble, we are finalizing as proposed two revisions to
the acoustic measurement requirements in 40 CFR 98.234(a)(5). First,
for stethoscope type acoustic leak detection devices (i.e., those
designed to detect through-valve leakage when put in contact with the
valve body and that provide an audible leak signal but do not calculate
a leak rate), we are finalizing as proposed that a leak is detected if
an audible leak signal is observed or registered by the device. Second,
we are finalizing as proposed that if a leak is detected using a
stethoscope type device, then that leak must be measured using one of
the quantification methods specified in 40 CFR 98.234(b) through (d)
and that leak measurement must be reported regardless of the volumetric
flow rate measured. These revisions will improve the accuracy of
emissions reported for compressors and transmission tanks when an
acoustic leak detection device is used. The EPA received only
supportive comments regarding the revisions for acoustic leak detection
devices. See the document Summary of Public Comments and Responses for
2024 Final Revisions and Confidentiality Determinations for Petroleum
and Natural Gas Systems under the Greenhouse Gas Reporting Rule in
Docket ID. No. EPA-HQ-OAR-2023-0234 for these comments and the EPA's
responses.
2. High Volume Samplers
a. Summary of Final Amendments
We are finalizing as proposed two revisions to the high volume
sampler methods to improve the quality of the data when high volume
samplers are used for flow measurements, consistent with section II.B.
of this preamble. First, we are adding detail to 40 CFR 98.234(d)(3) to
clarify the calculation methods associated with high volume sampler
measurements. Generally, high volume samplers measure CH4
flow, not whole gas flow. However, the current calculation methods in
40 CFR 98.234(d)(3) treat the measurement as a whole gas measurement.
Therefore, we are clarifying the calculation methods needed if the high
volume sampler outputs CH4 flow in either a mass flow or
volumetric flow basis. Specifically, we are finalizing as proposed
methods to determine natural gas (whole gas) flows based on measured
CH4 flows.
Second, we are finalizing as proposed to add a paragraph at 40 CFR
98.234(d)(5) to clarify how to assess the capacity limits of a high
volume sampler. Currently, 40 CFR 98.234(d) simply states to ``Use a
high volume sampler to measure emissions within the capacity of the
instrument''; there is no other information provided to clarify what
``within the capacity of the instrument'' means or how it is
determined. Considering actual sampling rates, gas collection
efficiencies near the sampling rates, and reported CH4
quantitation limits relative to maximum sampling rates, we determined
that whole gas flow rates exceeding 70 percent of the device's maximum
rated sampling rate is an indication that the device will not
accurately quantify the volumetric emissions, which we deem to exceed
the capacity of the device. Therefore, we are finalizing as proposed
the specification that CH4 flows above the manufacturer's
CH4 flow quantitation limit or total volumetric flows
exceeding 70 percent of the manufacturer's maximum sampling rate
indicate that the flow is beyond the capacity of the instrument and
that flow meters or calibrated bags must be used to quantify the flow
rate. However, after consideration of public comment, we are providing
an allowance for reporters that use OGI to ensure that there is 100
percent capture of the leak emissions during the entire high volume
sampling period to be able to use the measured flow rate even where it
exceeds 70 percent of the manufacturer's maximum sampling rate. If
emissions are observed escaping capture from the high volume sampler
when using OGI to ensure capture, then that measurement is considered
invalid (i.e., considered to be exceeding the quantitation capacity of
the device) even if the measured flow rate is less than 70 percent of
the sampling rate. For more information on our review, see the subpart
W TSD, available in the docket for this rulemaking (Docket ID. No. EPA-
HQ-OAR-2023-0234).
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments for high flow samplers.
Comment: One commenter noted that because a high volume analyzer
captures the emissions, OGI can be used to ensure that the high volume
analyzer is collecting all of the emissions in its vicinity. The
commenter stated that the EPA should clarify that an operator using OGI
to ensure that a high volume analyzer is capturing all emissions may
rely on the manufacturer's information on capacity limitations when
reporting emissions.
Response: We agree with the commenter that OGI can be used to
ensure that there is 100 percent capture of the leak emissions during
the entire high volume sampling period, but we also note that OGI
observations may also be used to indicate that 100 percent capture is
not achieved. We have revised 40 CFR 98.234(d)(5) to specify that if
100 percent capture is documented throughout the measurement period by
OGI, then the measured flow rate above the 70 percent maximum sampling
rate provision can be used. However, if any emissions are observed
escaping capture of the high volume sampler during a measurement
period, then that measurement is considered invalid (i.e., considered
to be exceeding the quantitation capacity of the device) even if the
measured flow rate is less than 70 percent of the sampling rate because
the high volume sampler did not capture 100 percent of the emissions
during that measurement period. We selected 70 percent of the
manufacturer's maximum sampling rate as a reasonable proxy for
efficient capture, but actual sampling rates may be lower depending on
the battery power. Also, capture efficiency may be impacted by how the
emissions are released from the leak source. We did not require OGI
observations, but we agree that OGI observations provide an empirical
means by which to assess capture efficiency and are preferred to
[[Page 42183]]
and override the 70 percent maximum sampling rate criteria when OGI
observations are used.
U. Industry Segment-Specific Throughput Quantity Reporting
1. Throughput Information for the Future Implementation of the Waste
Emissions Charge
a. Summary of Final Amendments
As noted in section I.E. of this preamble, CAA section 136(f)
specifies segment-specific thresholds (Waste Emissions Thresholds) for
segments subject to the WEC. For the Onshore Petroleum and Natural Gas
Production and Offshore Petroleum and Natural Gas Production industry
segments, the Waste Emissions Threshold is specified in CAA section
136(f)(1) as, ``(A) 0.20 percent of the natural gas sent to sale from
such facility;'' or ``(B) 10 metric tons of methane per million barrels
of oil sent to sale from such facility, if such facility sent no
natural gas to sale.'' For the Onshore Petroleum and Natural Gas
Gathering and Boosting, Onshore Natural Gas Processing, Onshore Natural
Gas Transmission Compression, LNG Storage, LNG Import and Export
Equipment, and Onshore Natural Gas Transmission Pipeline industry
segments, the Waste Emissions Threshold is defined in CAA section
136(f)(2) and (3) as a percentage of ``natural gas sent to sale from or
through such facility,'' with the percentages specified varying by
segment.
To align the subpart W reporting elements with text used in CAA
section 136 and enable verification of throughput-related reporting
elements, consistent with section II.C. of this preamble, the EPA is
finalizing as proposed to add a combination of new reporting elements
and amendments to existing segment-specific throughput reporting
requirements in 40 CFR 98.236(aa).
The EPA is finalizing as proposed to add the word ``natural'' in
front of ``gas'' at each occurrence where it is used in the throughput
reporting elements in subpart W that are being revised to align with
CAA section 136. We note that the CAA section 136 text uses the term
``oil'' and we are clarifying in this preamble that for the purposes of
the waste emissions charge the term ``oil'' in CAA section 136 has the
same meaning as ``crude oil'' as used in subpart W (which is used in
the throughput reporting elements in subpart W and defined in subpart A
of part 98).
The EPA is finalizing as proposed revisions to ensure that the
verbiage of ``sent to sales'' or ``through the facility'' is reflected
in the reporting elements, as applicable. The EPA is also finalizing as
proposed in 40 CFR 98.236(aa) that the quantities sent to sales or
through the facility be measured, as it is reasonable to expect that
the quantities of these products are already closely tracked by
reporters. The EPA expects that gas and hydrocarbon liquids are
typically sold by the cubic foot or barrel, respectively, so
measurements are important for owners and operators to determine the
correct sales prices. Similarly, it is important to track quantities
sent through the facility for a variety of reasons, such as ensuring
that processes at the facility are optimized or meeting contractual
obligations for transferring gas or hydrocarbon liquids to another
owner or operator.
Subpart W currently requires onshore natural gas processing
facilities to report the quantity of natural gas received at the gas
processing plant in existing 40 CFR 98.236(aa)(3)(i); however, the rule
does not currently specify whether the volume is all natural gas that
enters the facility--including natural gas that passes through the
facility without being processed further (i.e., ``pass-through
volumes'')--or just natural gas received for processing. As discussed
in section III.U.4. of this preamble, to maintain consistency with
subpart NN and reduce burden for fractionators, the EPA is finalizing
revisions to 40 CFR 98.236(aa)(3)(i) as proposed to specify that the
subpart W quantity of gas received is the gas received for processing
and is also finalizing as proposed to specify that fractionators do not
have to report a quantity under 40 CFR 98.236(aa)(3)(i) if they report
under subpart NN.
However, to be consistent with CAA section 136(f)(2), the
throughput should include all volumes of natural gas that pass through
the facility or are sent to sales. Therefore, considering the
amendments to 40 CFR 98.236(aa)(3)(i) and guidance that has been
historically provided for 40 CFR 98.236(aa)(3)(ii) (as explained in the
preamble to the 2023 Subpart W Proposal), a new reporting element for
natural gas processing throughput is needed to fully capture all
volumes through the facility (i.e., those that are processed and those
that pass through the facility which are not processed). As such, we
are finalizing the new reporting element for the Onshore Natural Gas
Processing industry segment in 40 CFR 98.236(aa)(3)(ix) as proposed to
capture all natural gas that is processed and/or passed through the
facility, consistent with the text in CAA section 136 (i.e., ``natural
gas sent to sale from or through facilities'').
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed general amendments to throughput information for the
future implementation of the waste emissions charge.
Comment: One commenter stated that the EPA must expand the
allowable methods to measure hydrocarbon liquid throughputs. The
commenter stated that liquid throughputs are not commonly measured with
flow meters but are instead usually determined by truck loading
tickets, so the requirement to use a flow meter to determine quantities
sent to sale or through the facility is not workable for hydrocarbon
liquids.
Response: In assessing these commenters' assertion, the EPA
reviewed available information about available flow meters to
independently verify the commenters' claim and found that hydrocarbon
liquids may be measured with meters such as ultrasonic and turbine flow
meters. Ultrasonic flow measurement technology has been recognized in
Chapter 5.8 of the API document, Manual of Petroleum Measurement
Standards.\82\ These meters ``infer the volumetric throughput by
measuring the velocity over the flow area.'' \83\ However, temperature
is necessary to consider for crude oils as this can significantly
change a meter's performance due to change in viscosity. The viscosity
of each product needs to be specified over the operating temperature
range. Further, we recognize that ultrasonic flow meters are Reynolds
Number dependent and may be affected by the relationship between
velocity and viscosity as well as by entrained solids, water, gas, and
wax.\84\ Additionally, turbine flow meters may be used to ``indicate
flow rate and measure total throughput of a liquid line.'' \85\
Manufacturers of turbine flow
[[Page 42184]]
meters state, ``Typical fluids and gases measured with turbine meters
include hydrocarbons, chemicals, water, cryogenic liquids, air, natural
gas, and industrial gases.'' \86\ Therefore, the EPA is finalizing the
requirements to determine throughput quantities that are sent to sale
or through the facility using a flow meter that meets the requirements
of 40 CFR 98.234(b).
---------------------------------------------------------------------------
\82\ API. Manual of Petroleum Measurement Standards, Chapter
5.8: Measurement of Liquid Hydrocarbons by Ultrasonic Flow Meters
Using Transit Time Technology. ANSI/API MPMS Ch. 5.8-2011. 2nd
Edition, November 2011 (Errata 1 dated February 2014).
\83\ Kalivoda, R. Flowmeter Application Considerations: Knowing
the Limits of Ultrasonics for Crude Oil Measurement. September 26,
2010. Available at https://www.piprocessinstrumentation.com/home/article/15554208/flowmeter-application-considerations, last accessed
April 12, 2024. Available in the docket for this rulemaking, Docket
ID. No. EPA-HQ-OAR-2023-0234.
\84\ Id.
\85\ Cameron. Technical Specifications: NUFLO Liquid Turbine
Flow Meters. 2013. https://www.anythingflows.com/es/wp-content/uploads/2016/05/nuflo-liquid-turbine-flow-meters_fpd.pdf. Available
in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-
0234.
\86\ Hoffer Flow Controls, ``Turbine Flow Meters.'' https://hofferflow.com/turbine-flow-meters, last accessed April 12, 2024.
Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2023-0234.
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2. Throughput Information for the Future Implementation of the Waste
Emissions Charge for Onshore Petroleum and Natural Gas Production and
Offshore Petroleum and Natural Gas Production
a. Summary of Final Amendments
For the Onshore Petroleum and Natural Gas Production and Offshore
Petroleum and Natural Gas Production industry segments, the current
requirements for reporting throughputs of crude oil are combined with
volumes of condensate. The EPA proposed to separate of these reporting
elements into two distinct reporting elements in both 40 CFR
98.236(aa)(1)(i) and 98.236(aa)(2) based on a preliminary determination
that these volumes will need to be reported separately in order to
align with the CAA section 136(f) oil threshold for production
facilities, when applicable. However, after further consideration and
review of public comments, the EPA is not taking final action on that
proposed revision. The existing definitions of ``sales oil'' and
``crude oil'' in subpart A both include condensate, and there is no
indication that the phrase ``oil sent to sale'' as used in CAA section
136(f)(1) should be defined differently than the definitions subpart A.
For consistency with CAA section 136, the EPA is finalizing as
proposed to use the phrase ``sent to sale'' in 40 CFR
98.236(aa)(1)(i)(B) and (C) and 40 CFR 98.236(aa)(2)(i) and (ii)
instead of ``for sale,'' the phrase used in some of the existing data
elements. This amendment is for consistency in language rather than any
expected difference in the volumes to be reported or the interpretation
of the terms, as the existing term was intended to have the same
meaning.
Specifically for the Offshore Petroleum and Natural Gas Production
industry segment, the existing throughput requirements are for ``gas
handled'' and ``oil and condensate handled'' at the platform, which
includes production volumes as well as volumes transferred via pipeline
from another location. In order to provide consistency with the
language in CAA section 136 across both production industry segments
and help the EPA implement CAA section 136, the EPA is finalizing as
proposed the revision of the reporting elements in 40 CFR 98.236(aa)(2)
for the Offshore Petroleum and Natural Gas Production industry segment
so they are analogous to those in Onshore Petroleum and Natural Gas
Production.
The EPA is also finalizing additional throughput data elements to
provide separate, well-level reporting of throughputs associated with
wells in the Onshore Petroleum and Natural Gas Production and Offshore
Petroleum and Natural Gas Production industry segments that are
permanently shut-in and plugged. These data elements are anticipated to
be necessary for the implementation of the associated exemption in CAA
section 136(f)(7). Specifically, in the 2024 WEC Proposal, the EPA
proposed that these data elements would be used as equation inputs for
the purposes of calculating emissions attributable to a permanent shut-
in and plugged well for wells in the Onshore Petroleum and Natural Gas
Production industry segment in reporting year 2024 and for wells in the
Offshore Petroleum and Natural Gas Production in any reporting year.
First, the EPA is finalizing as proposed to revise the phrase
``permanently taken out of production (i.e., plugged and abandoned)''
in proposed 40 CFR 98.236(aa)(1)(ii)(D) and (H) to read ``permanently
shut-in and plugged'' for consistency with the language used in CAA
section 136. This amendment is for consistency in language rather than
any expected difference in the wells to be reported or the
interpretation of the terms. Second, the EPA is finalizing as proposed
to require reporting of the quantities of natural gas and crude oil
produced that is sent to sale during the reporting year for each well
that is permanently shut-in and plugged. However, as discussed earlier
in this section, the EPA is not taking final action on the proposed
revision to require separate reporting for crude oil and condensate, so
the final amendments require reporting of natural gas in 40 CFR
98.236(aa)(1)(iii)(C) and 40 CFR 98.236(aa)(2)(iii) and crude oil
(including condensate) in 40 CFR 98.236(aa)(1)(iii)(D) and 40 CFR
98.236(aa)(2)(iv) for the Onshore Petroleum and Natural Gas Production
industry segment and the Offshore Petroleum and Natural Gas Production
industry segment, respectively.
Based on consideration of public comments, as well as the recent
2024 WEC Proposal, the EPA is not taking final action at this time on
the proposed revision to require each Onshore Petroleum and Natural Gas
Production well-pad with a well that was permanently shut-in and
plugged to report the total quantities of natural gas, crude oil, and
condensate produced that is sent to sale in the reporting year for the
wells on that well-pad. The EPA proposed these data elements
anticipating that they may be necessary for the exemption in CAA
section 136(f)(7) for wells that are permanently shut-in and plugged.
However, the 2024 WEC Proposal does not use these data elements for the
purposes of determining the quantity of emissions that may be exempted
for a well that was permanently shut-in and plugged.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to throughput information for the future
implementation of the waste emissions charge for the Onshore Petroleum
and Natural Gas Production and Offshore Petroleum and Natural Gas
Production industry segments.
Comment: Commenters disagreed with the EPA's proposal to require
separate reporting of crude oil and condensate and explained that oil
and condensate are often sold as one combined volume. Commenters
explained that for offshore production facilities in particular, oil
and condensate produced is sent onshore via single combined pipelines.
Commenters stated that subpart A defines ``sales oil'' as produced
crude oil or condensate measured at the production lease automatic
custody transfer meter or custody transfer tank gauge and do not
measure oil or condensate separately. One commenter stated that the IRA
does not differentiate between oil, condensate, and natural gas.
Response: After further review of the requirements in CAA section
136, we agree that it is not necessary for condensate to be reported
separately from crude oil. Section 136(f)(1) of the CAA uses the phrase
``barrels of oil sent to sale,'' and there is no indication that ``oil
sent to sale'' should be defined differently than the term ``sales
oil'' that already exists in subpart A. As the commenters noted, the
definition of ``sales oil'' includes condensate, and the definition of
``crude oil'' in subpart A also includes condensate. Therefore, the
[[Page 42185]]
EPA agrees that the amendment to use the term ``sent to sale'' in 40
CFR 98.236(aa)(1)(i)(C), 40 CFR 98.236(aa)(1)(iii)(D), and 40 CFR
98.236(aa)(2)(ii) and (iv) should address concerns with consistency
with CAA section 136.
Comment: Commenters stated the proposal to require each Onshore
Petroleum and Natural Gas Production well-pad with a well that was
permanently shut-in and plugged to report the total quantities of
natural gas, crude oil, and condensate produced that is sent to sale in
the reporting year for the wells on that well-pad would result in
duplicative reporting and is unnecessary.
Response: At the time of proposal, the EPA anticipated that these
data elements may be useful in the future evaluation of the associated
exemptions in CAA section 136(f)(7). However, the proposed provisions
for the exemption for permanently shut-in and plugged wells in the 2024
WEC Proposal do not use the total quantities of natural gas and crude
oil sent to sale in the reporting year for the wells on that well-pad.
Therefore, we are not finalizing the requirement for reporting of
throughput for each well-pad with a well that was permanently shut-in
and plugged at this time.
3. Throughput Information for the Future Implementation of the Waste
Emissions Charge for Onshore Petroleum and Natural Gas Gathering and
Boosting
a. Summary of Final Amendments
To be consistent with the EPA's original intent for the throughput
volumes for the Onshore Petroleum and Natural Gas Gathering and
Boosting industry segment, the EPA is finalizing amendments to 40 CFR
98.236(aa)(10)(ii) and (iv) with changes from proposal. We proposed to
clarify that the downstream endpoints listed in the current reporting
elements are examples of potential destinations. Based on consideration
of public comment and further review of the language and background
documentation, the EPA is instead revising 40 CFR 98.236(aa)(10)(ii)
and (iv) to specify that the reported quantities should be the natural
gas or hydrocarbon liquids, respectively, transported from the facility
(rather than specifying that the reported quantities should be the
natural gas or hydrocarbon liquids, respectively, transported to
downstream operations such as one of those endpoints, as proposed).
However, some gas may flow back upstream, for use at an onshore
petroleum and natural gas facility. Section 136(f)(2) of the CAA
indicates that the WEC should be based on the ``natural gas sent to
sale from or through such facility'' but does not specify that the gas
must be sent from the facility to a downstream endpoint. As a result of
these amendments, the reported quantities must include all natural gas
and hydrocarbon liquids transported from the facility (i.e.,
transported to another basin, transported to another gathering system
owner or operator, or transported outside of the Onshore Petroleum and
Natural Gas Gathering and Boosting industry segment).
In addition to reviewing the reported throughputs, we also reviewed
the definitions in subpart W associated with the industry segment and
the facility, specifically the definitions for ``gathering and boosting
system'' and ``gathering and boosting system owner or operator'' in 40
CFR 98.238. We are finalizing as proposed to amend the definition of
``gathering and boosting system'' and ``gathering and boosting owner or
operator'' in 40 CFR 98.238 to specify that these systems may receive
natural gas and/or petroleum from one or more other onshore petroleum
and natural gas gathering and boosting systems in addition to
production facilities. We are also finalizing additional amendments to
clarify that the downstream endpoints listed in the current provisions
are examples of potential destinations. Specifically, we are revising
the definition of ``gathering and boosting system owner or operator''
in 40 CFR 98.238 and the description of the industry segment in
98.230(a)(9) to add the phrase ``a downstream endpoint, typically''
before the list of the types of facilities that may receive the
petroleum and/or natural gas.
b. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed amendments to throughput information for the future
implementation of the waste emissions charge for the Onshore Petroleum
and Natural Gas Gathering and Boosting industry segment.
Comment: Commenters supported the EPA's proposed changes to the
gathering and boosting throughput reporting requirements but noted that
the term ``downstream endpoint'' is too narrow because gas sometimes
exits the gathering system to an ``upstream'' location, such as back to
upstream producers for various uses. Commenters also requested that the
EPA specify that Onshore Petroleum and Natural Gas Gathering and
Boosting industry segment reporters should account for gas that flows
through multiple compressor stations (``sites'') in series within the
same basin by revising the list of examples of downstream endpoints to
include ``another gathering and boosting site or facility.''
Response: The EPA agrees with the commenters' statement that
``downstream endpoint'' is too narrow and that it would be more
accurate for facilities to report all natural gas and hydrocarbon
liquids transported from the facility regardless of destination,
including quantities that are transported to another basin, quantities
that are transported to another gathering system owner or operator, and
quantities that are transported to a facility in a different industry
segment or source category. In response to this comment, the EPA is
finalizing amendments to 40 CFR 98.236(aa)(10)(ii) to specify that the
natural gas is transported ``from the facility,'' regardless of whether
the endpoint is downstream of the facility.
However, the EPA disagrees with the commenters' request to report
the total throughput reported as the quantity transported from each
gathering and boosting site where that quantity is transported to a
site that is part of the same facility with respect to onshore
petroleum and natural gas gathering and boosting. This would allow
reporters to count flows multiple times and significantly increase the
throughput volumes for gathering and boosting facilities. Congress
established methane waste emissions thresholds for gathering and
boosting facilities under CAA section 136 with reference to the
existing subpart W facility definitions. The EPA proposed revisions to
the throughput requirements that would align with the requirements of
CAA section 136. The EPA generally proposed to maintain the existing
approach to facility throughputs, with limited revisions to ensure that
all throughput transported from the facility is included and to align
with the terminology used in CAA section 136.
4. Onshore Natural Gas Processing and Natural Gas Distribution
Throughputs Also Reported Under Subpart NN
For the reasons stated in the preamble to the 2023 Subpart W
Proposal, the EPA is finalizing as proposed the elimination of
duplicative elements from subpart W for facilities that report to
subpart NN and two other data elements for natural gas distribution
companies, consistent with section II.C. of this preamble. The EPA
received only supportive comments regarding the removal of these data
elements from subpart W. See the document Summary
[[Page 42186]]
of Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems
under the Greenhouse Gas Reporting Rule in Docket ID. No. EPA-HQ-OAR-
2023-0234 for these comments and the EPA's responses.
Onshore Natural Gas Processing plants are required to report seven
facility-level throughput-related items under subpart W, as specified
in existing 40 CFR 98.236(aa)(3). These seven data reporting elements
include: quantities of natural gas received and processed gas leaving
the gas processing plant, cumulative quantities of NGLs received and
leaving the gas processing plant, the average mole fractions of CH4 and
CO2 in the natural gas received, and an indication of whether the
facility fractionates NGLs. The EPA is finalizing several reporting
requirements in 40 CFR 98.236(aa)(3) as proposed for Onshore Natural
Gas Processing plants that both fractionate NGLs and also report as a
supplier under subpart NN. First, to clarify which facilities have data
overlap between subparts W and NN, the EPA is adding a reporting
element for natural gas processing plants at 40 CFR 98.236(aa)(3)(viii)
to indicate whether they report as a supplier under subpart NN. We note
that the final wording for this new data element is slightly changed
from proposal to clarify that the facility report must include subpart
NN data under the same e-GGRT identification number and the same
calendar year as the Onshore Natural Gas Processing plant. Some
facilities may not report under both subparts ever year, or some owners
or operators may choose to report subpart NN data using a different e-
GGRT identification number, and the language of the final data element
clarifies how a reporter should respond to the data element. Next, the
EPA is finalizing as proposed to specify in 40 CFR 98.236(aa)(3)
introductory text that facilities that indicate that they both
fractionate NGLs and report as a supplier under subpart NN under the
same e-GGRT identification number and for the same calendar year would
no longer be required to report the quantities of natural gas received
or NGLs received or leaving the gas processing plant as specified in 40
CFR 98.236(aa)(3)(i), (iii) and (iv); this data will continue to be
reported under subpart NN as specified in 40 CFR 98.406(a)(3),
98.406(a)(1) and (2), 98.406(a)(4)(i) and (ii), respectively, thus,
maintaining the ability to verify associated emissions reported under
subpart W. See table 2 of this preamble for more information.
These facilities will be required to continue reporting the data
elements specified in 40 CFR 98.236(aa)(3)(ii) and (v) through (viii),
as these reporting elements do not overlap with subpart NN reporting
elements. Natural gas processing plants that do not fractionate or that
fractionate but do not report as a supplier under subpart NN will
continue to report all of the reporting elements for natural gas
processing plants as specified in 40 CFR 98.236(aa)(3).
Natural Gas Distribution companies are also required to report
seven throughput volumes under subpart W, as specified in existing 40
CFR 98.236(aa)(9). These seven data reporting elements include: the
quantity of gas received at all custody transfer stations; the quantity
of natural gas withdrawn from in-system storage; the quantity of gas
added to in-system storage; the quantity of gas delivered to end users;
the quantity of gas transferred to third parties; the quantity of gas
consumed by the LDC for operational purposes; and the quantity of gas
stolen. The EPA is finalizing the removal of the duplicative reporting
elements for throughput for LDCs in 40 CFR 98.236(aa)(9)(i) through
(iv), as proposed. See table 3 of this preamble for more information.
Finally, the EPA is finalizing as proposed to remove the reporting
elements for the volume of natural gas used for operational purposes
and natural gas stolen specified in 40 CFR 98.236(aa)(9)(vi) and (vii).
As a result of removing all of the 40 CFR 98.236(aa)(9) data elements
for the reasons explained in this section of this preamble, the EPA is
reserving paragraph 40 CFR 98.236(aa)(9).
Table 2 of this preamble shows all the duplicative data elements
that the EPA is removing from subpart W for facilities that also report
to subpart NN.
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5. Onshore Natural Gas Transmission Pipeline Throughputs
Similar to Natural Gas Distribution facilities, Onshore Natural Gas
Transmission Pipeline facilities are currently required to report five
throughput volumes under subpart W, as specified in existing 40 CFR
98.236(aa)(11). These five data reporting elements include: the
quantity of natural gas received at all custody transfer stations; the
quantity of natural gas withdrawn from in-system storage; the quantity
of gas added to in-system storage; the quantity of gas transferred to
third parties; and the quantity of gas consumed by the transmission
pipeline facility for operational purposes. For the reasons stated in
the preamble to the 2023 Subpart W Proposal, the EPA is finalizing as
proposed to amend 40 CFR 98.236(aa)(11)(ii) and (iii) to replace the
term ``in-system'' with clarifying language that specifies withdrawals/
additions of natural gas from storage are referring to Underground
Natural Gas Storage and LNG Storage facilities that are owned and
operated by the onshore natural gas transmission pipeline owner or
operator that do not report under subpart W as direct emitters
themselves. These amendments are expected to improve data quality
consistent with section II.D. of this preamble. The EPA received only
supportive comments regarding these amendments. See the document
Summary of Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems
under the Greenhouse Gas Reporting Rule in Docket ID. No. EPA-HQ-OAR-
2023-0234 for these comments and the EPA's responses.
V. Other Final Minor Revisions or Clarifications
See table 3 of this preamble for the miscellaneous minor technical
corrections not previously described in this preamble that we are
finalizing throughout subpart W, consistent with section II.D. of this
preamble.
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IV. Effective Date of the Final Amendments
The EPA is finalizing the effective date of the amendments with
some updates from proposal, that will phase in the final amendments.
The effective dates listed in the DATES section of this preamble
reflect when the amendments will be published in the CFR. As described
in more detail in section IV.A. of this preamble, we are finalizing
that the majority of the final amendments will become effective on
January 1, 2025, as proposed, and that reporters will implement all but
a few of those changes beginning with reports prepared for RY2025 and
submitted by March 31, 2026. The submission date for RY2025 reports is
over a year after the finalization of this rule, thus providing a
reasonable period for reporters to adjust to any final amendments that
require a change to data collection, calculation methods, or reporting.
The requirements that will become effective on January 1, 2025, and
must be implemented beginning with reports prepared for RY2024 and
submitted by March 31, 2025 are reporting requirements that do not
require additional data collection or calculations. In addition, as
described in more detail in section IV.B. of this preamble, the EPA is
finalizing that certain optional additional calculation methods and
other provisions that allow owners and operators of applicable
facilities to submit empirical emissions data, consistent with CAA
section 136(h), will become effective on July 15, 2024. This earlier
effective date will allow reporters the option to elect to use those
methods for RY2024. Specific information regarding what provisions are
allowed or required each year is provided in sections IV.A. and IV.B.
of this preamble.
We are also finalizing that the CBI determinations for new and
substantially revised data elements discussed in section V. of this
preamble become effective on the same date that the new data element or
final revisions to existing data elements become effective. The
exception is one circumstance, discussed in detail in section V. of
this preamble, where the final determination covers data included in
annual GHG reports submitted for prior years. In all cases, as
proposed, the final determination for the data that the EPA has already
received for these prior years or receives going forward for any
reporting year would become effective on January 1, 2025.
A. Amendments That Are Effective on January 1, 2025
Table 4 of this preamble lists the affected subparts, the final
revisions that are effective on January 1, 2025, and the RY report in
which those changes will first be reflected. January 1, 2025, is the
effective date, which is the date that the CFR regulatory text is
revised to reflect those changes. However, the report in which that
amendment will first be reflected is either RY2024 or RY2025, depending
upon the substance of that change (i.e., what that change requires the
reporter to do to comply with it).
Changes with effective date January 1, 2025, that must be reflected
starting with the RY2024 report are those that require no changes to be
made by reporters during the reporting year and thus provide reporters
a reasonable time to adjust to these certain final amendments prior to
submission of the RY2024 report. These are also reporting elements
necessary for implementation of WEC. Specifically, the final reporting
of the quantities of natural gas and crude oil produced that is sent to
sale in the calendar year for each well permanently shut-in and plugged
(40 CFR 98.236(aa)(1)(iii)(C) and (D) and 40 CFR 98.236(aa)(2)(iii) and
(iv)) become effective on January 1, 2025 and reporters must, as
applicable, include that information in their reports prepared for
RY2024 and submitted March 31, 2025.
Changes with effective date January 1, 2025 that must be reflected
starting with the RY2025 reports include requirements to begin
reporting emissions for new emission sources, both those that are being
added to subpart W for the first time in this final rule (e.g., other
large release events, crankcase venting) and those that expand the
applicability of reporting for emission source types in subpart W to
additional industry segments, as described in section III.C.1. of this
preamble, as well as requirements to begin accounting for additional
emission points from existing emission source types (e.g., methane slip
from combustion equipment). They also include changes that affect
monitoring or data collection requirements, such as requirements for
certain simulation inputs for AGRs, dehydrators, and atmospheric
storage tanks to be based on measurement, and changes to required
calculation methodologies, such as determination of the flow rate and
composition of gas routed to a flare if continuous monitors are not
present.
[[Page 42193]]
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B. Amendments That Are Effective July 15, 2024
Table 5 of this preamble lists the final amendments that are
effective July 15, 2024, all of which may be reflected in the RY2024
report for the first time if elected by the reporter. These amendments
include optional additional calculation methods and other provisions
that allow owners and operators of applicable facilities to submit
empirical emissions data, consistent with CAA section 136(h). This
earlier effective date will allow reporters the option to elect to use
those methods for RY2024. The amendments to calculation methodologies
that are effective July 15, 2024 for various emission source types
specify that reporters may use data collected anytime during the
calendar year for any of the applicable calculation methods, provided
that the data were collected in accordance with and meet the criteria
of the applicable paragraphs. For example, if a reporter installed a
continuous flow meter that is capable of meeting the requirements of 40
CFR 98.234(b) on the natural gas supply line dedicated to any one or
combination of natural gas pneumatic devices prior to January 1, 2024,
the reporter may use Calculation Method 1 for natural gas pneumatic
devices for all of RY2024, not just the period between July 15, 2024
and December 31, 2024.
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V. Final Confidentiality and Reporting Determinations for Certain Data
Reporting Elements
This section provides a summary of the EPA's final confidentiality
determinations and emission data designations for new and substantially
revised data elements included in these final amendments, certain
existing part 98 data elements for which no determination has been
previously established, certain existing part 98 data elements for
which the EPA is amending or clarifying the existing confidentiality
determination, and the EPA's final reporting determinations for inputs
to equations included in the final amendments. This section also
identifies any changes to the proposed confidentiality determinations,
emissions data designations, or reporting determinations in the final
rule. Finally, this section summarizes the major comments and responses
related to the proposed confidentiality determinations, emission data
designations, and reporting determinations for these data elements.
A. EPA's Approach To Assess Data Elements
In the 2023 Subpart W Proposal, the EPA proposed to assess data
elements for eligibility of confidential treatment using a revised
approach, in response to Food Marketing Institute v. Argus Leader
Media, 139 S. Ct. 2356 (2019) (hereafter referred to as Argus
Leader).\87\ The EPA proposed that the Argus Leader decision did not
affect our approach to designating data elements as ``inputs to
emission equations'' or our previous approach for designating new and
revised reporting requirements as ``emission data.'' We proposed to
continue identifying new and revised reporting elements that qualify as
``emission data'' (i.e., data necessary to determine the identity,
amount, frequency, or concentration of the emission emitted by the
reporting facilities) by evaluating the data for assignment to one of
the four data categories designated by the 2011 Final CBI Rule (76 FR
30782, May 26, 2011) to meet the CAA definition of ``emission data'' in
40 CFR 2.301(a)(2)(i) (hereafter referred to as ``emission data
categories''). Refer to section II.B. of the July 7, 2010 proposal (75
FR 39094) for descriptions of each of these data categories and the
EPA's rationale for designating each data category as ``emission
data.'' For data elements designated as ``inputs to emission
equations,'' the EPA maintained the two subcategories, data elements
entered into e-GGRT's Inputs Verification Tool (IVT) and those directly
reported to the EPA. Refer to section V.C. of the preamble to the 2023
Subpart W Proposal for further discussion of ``inputs to emission
equations.''
---------------------------------------------------------------------------
\87\ Available in the docket for this rulemaking (Docket ID. No.
EPA-HQ-OAR-2023-0234).
---------------------------------------------------------------------------
In the 2023 Subpart W Proposal, for new or revised data elements
that the EPA did not propose to designate as ``emission data'' or
``inputs to emission equations,'' the EPA proposed a revised approach
for assessing data confidentiality. We proposed to assess each
individual reporting element according to the new Argus Leader
standard. So, we evaluated each data element individually to determine
whether the information is customarily and actually treated as private
by the reporter and proposed a confidentiality determination based on
that evaluation.
The EPA received several comments on its proposed approach in the
2023 Subpart W Proposal. The commenters' concerns and the EPA's
responses thereto are provided in the document Summary of Public
Comments and Responses for 2024 Final Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems under the
Greenhouse Gas Reporting Rule in Docket ID. No. EPA-HQ-OAR-2023-0234.
Following consideration of the comments received, the EPA is not
revising this approach and is continuing to assess data elements for
confidentiality determinations as described in the 2023 Subpart W
Proposal. We are also finalizing the specific confidentiality
determinations and reporting determinations as
[[Page 42200]]
described in sections V.B. and V.C. of this preamble.
B. Final Confidentiality Determinations and Emissions Data Designations
1. Final Confidentiality Determinations for New and Revised Data
Elements
The EPA is making final confidentiality determinations and emission
data designations for new and substantially revised data elements
included in these final amendments. Substantially revised data elements
include those data elements where the EPA is, in this final action,
substantially revising the data elements as compared to the existing
requirements. Please refer to the preamble to the 2023 Subpart W
Proposal for additional information regarding the proposed
confidentiality determinations for these data elements.
The EPA is not finalizing the proposed confidentiality
determinations for certain data elements in subpart W because the EPA
is not taking final action on the requirements to report these data
elements at this time (see section III. of this preamble for additional
information). These data elements are listed in Table 4 of the
memorandum, Confidentiality Determinations and Emission Data
Designations for Data Elements in the 2024 Final Revisions to the
Greenhouse Gas Reporting Rule for Petroleum and Natural Gas Systems,
available in the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-
2023-0234.
For one data element, the EPA proposed a confidentiality
determination in the 2023 Subpart W Proposal but is not finalizing a
confidentiality determination at this time. In the 2023 Subpart W
Proposal, the EPA proposed a confidentiality determination of
``Eligible for Confidential Treatment'' for 40 CFR 98.236(aa)(3)(ix),
the quantity of residue gas leaving that has been processed by the
facility and any gas that passes through the facility to sale without
being processed by the facility in the calendar year. In the 2024 WEC
Proposal, the EPA re-proposed the confidentiality status for this data
element as ``No Determination.'' We intend to consider comments
submitted on the 2024 WEC rulemaking on this proposed confidentiality
status before finalizing a confidentiality determination for this data
element through rulemaking. We intend to make this determination along
a similar timeline as the final WEC rule.
In some cases, the EPA is finalizing revisions from the proposed
rule that include new data elements for which the EPA did not propose a
confidentiality determination. These data elements are listed in table
6 of this preamble and Table 5 of the memorandum, Confidentiality
Determinations and Emission Data Designations for Data Elements in the
2024 Final Revisions to the Greenhouse Gas Reporting Rule for Petroleum
and Natural Gas Systems, available in the docket to this rulemaking,
Docket ID. No. EPA-HQ-OAR-2023-0234. Because these data elements were
not included in the proposal, the EPA was unable to solicit public
comment on confidentiality determinations for these data elements.
Accordingly, we are not finalizing confidentiality determinations for
any of these data elements at this time.
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In a handful of cases, the EPA has made minor revisions to data
elements in this final action as compared to the proposed data element
included in the 2023 Subpart W Proposal. For certain proposed data
elements, we have revised the citations from proposal to final. In
other cases, the minor revisions include clarifications to the text.
The EPA evaluated these data elements and how they have been clarified
in the final rule to verify that the information collected has not
substantially changed since proposal. These data elements are listed in
Table 6 of the memorandum, Confidentiality Determinations and Emission
Data Designations for Data Elements in the 2024 Final Revisions to the
Greenhouse Gas Reporting Rule for Petroleum and Natural Gas Systems,
available in the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-
2023-0234. Because the information to be collected has not
substantially changed in a way that would affect the confidential
nature of the information to be collected from the proposal, we are
finalizing the confidentiality determinations or emission data
designations for these data elements as proposed. For additional
information on the rationales for the confidentiality determinations
for these data elements, see the preamble to the 2023 Subpart W
Proposal and the memorandum, Proposed Confidentiality Determinations
and Emission Data Designations for Data Elements in Proposed Revisions
to the Greenhouse Gas Reporting Rule for Petroleum and Natural Gas
Systems, available in the docket for this rulemaking (Docket ID. No.
EPA-HQ-OAR-2023-0234).
For all other confidentiality determinations for the new or
substantially revised data reporting elements for these subparts, the
EPA is finalizing the confidentiality determinations as they were
proposed. Please refer to the preamble to the 2023 Subpart W Proposal
for additional information regarding these confidentiality
determinations.
2. Final Confidentiality Determinations and Emission Data Designations
for Existing Data Elements for Which the EPA Did Not Previously
Finalize a Confidentiality Determination or Emission Data Designation
The EPA is finalizing the confidentiality determination as it was
proposed for the one subpart W data reporting element for which no
determination has been previously established. The EPA received no
comments on the proposed determination. Please refer to the preamble to
the 2023 Subpart W Proposal for additional information regarding the
proposed confidentiality determination.
C. Final Reporting Determinations for Inputs to Emissions Equations
In the 2023 Subpart W Proposal, the EPA proposed to assign several
data elements to the ``Inputs to Emission Equation'' data category. As
discussed in section VI.B.1. of the 2022 Proposed Rule (87 FR 36920,
June 21, 2022), the EPA determined that the Argus Leader decision does
not affect our approach for handling of data elements assigned to the
``Inputs to Emission Equations'' data category. Data assigned to the
``Inputs to Emission Equations'' data category are assigned to one of
two subcategories, including ``inputs to emission equations'' that must
be directly reported to the EPA, and ``inputs to emission equations''
that are not reported but are entered into the EPA's IVT. The EPA
received no comments specific to the proposed reporting determinations
for inputs to emission equations in the proposed rules. Additional
information regarding these reporting determinations may be found in
section V.C. of the preamble to the 2023 Subpart W Proposal.
The EPA is not finalizing the proposed reporting determinations for
certain data elements in subpart W because the EPA is not taking final
action on the requirements to report these data elements at this time
(see section III. of this preamble for additional information). These
data elements are listed in Table 2 of the memorandum, Reporting
[[Page 42209]]
Determinations for Data Elements Assigned to the Inputs to Emission
Equations Data Category in the 2024 Final Revisions to the Greenhouse
Gas Reporting Rule for Petroleum and Natural Gas Systems, available in
the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
In some cases, the EPA is finalizing revisions that include new
data elements that the EPA did not propose to assign to the ``Inputs to
Emission Equations'' data category. These data elements are listed in
Table 3 of the memorandum, Reporting Determinations for Data Elements
Assigned to the Inputs to Emission Equations Data Category in the 2024
Final Revisions to the Greenhouse Gas Reporting Rule for Petroleum and
Natural Gas Systems, available in the docket to this rulemaking, Docket
ID. No. EPA-HQ-OAR-2023-0234. Because the EPA has not proposed or
solicited public comment on an inputs determination for these data
elements, we are not finalizing reporting determinations for these data
elements at this time.
In a handful of cases, the EPA has made minor revisions to data
elements assigned to the ``Inputs to Emissions Equations'' category in
this final action as compared to the proposed data element included in
the 2023 Subpart W Proposal. For certain proposed data elements, we
have revised the citations from proposal to final. In other cases, the
minor revisions include clarifications to the text. The EPA evaluated
these inputs to emissions equations and how they have been clarified in
the final rule to verify that the data element has not substantially
changed since proposal. These data elements and how they have been
clarified in the final rule are listed in Table 4 of the memorandum,
Reporting Determinations for Data Elements Assigned to the Inputs to
Emission Equations Data Category in the 2024 Final Revisions to the
Greenhouse Gas Reporting Rule for Petroleum and Natural Gas Systems,
available in the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-
2023-0234. Because the input has not substantially changed since
proposal, we are finalizing the proposed reporting determinations for
these data elements as proposed. For additional information on the
rationale for the reporting determinations for the data elements, see
the preamble to the 2023 Subpart W Proposal and the memorandum Proposed
Reporting Determinations for Data Elements Assigned to the Inputs to
Emission Equations Data Category in Proposed Revisions to the
Greenhouse Gas Reporting Rule for Petroleum and Natural Gas Systems,
available in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-
2023-0234).
For all other reporting determinations for the data elements
assigned to the ``Inputs to Emission Equations'' data category, the EPA
is finalizing the reporting determinations as they were proposed.
Please refer to the preamble to the 2023 Subpart W Proposal for
additional information.
VI. Impacts of the Final Amendments
This section summarizes the impacts related to the specific
substantive final amendments for subpart W (as well as subparts A and
C), as generally described in section II. of this preamble. Major
changes to the impacts analysis for the final rule as compared to the
impacts analysis for the proposed revisions are identified in this
section. Total costs have increased from $92.3 million per year at
proposal to $183.6 million per year at final due to underestimates at
proposal in the labor hours needed to comply with these amendments. As
described in section II. of this preamble, for some proposed revisions,
we are not taking final action on revisions to calculation, monitoring,
or reporting requirements that would have required reporters to collect
or submit additional data. Therefore, the final burden for these
sources have been revised to reflect only those requirements that are
being finalized. For example, as discussed in section II.N. of this
preamble, the proposed revision to require continuous parameter
monitoring for flares is not being finalized, resulting in the
reduction of capital costs by $19.1 million as compared to the
proposal's cost analysis.
The EPA also received a number of comments on the proposed
revisions and the impacts of the proposed revisions. Following
consideration of these comments, the EPA has, in some cases, revised
the final rule requirements and updated the impacts analysis to reflect
these changes. The summary of the final amendments impacts is followed
by a summary of the major comments on the proposed amendments impacts
and the EPA's responses to those comments. The document Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Petroleum and Natural Gas Systems
under the Greenhouse Gas Reporting Rule, available in the docket to
this rulemaking (Docket ID. No. EPA-HQ-OAR-2023-0234), contains the
full text of all the comments on impacts of the 2023 Subpart W
Proposal, including the major comments responded to in this preamble.
A. Cost Analysis
1. Summary of Cost Analysis for Final Amendments
The revisions will amend requirements that apply to the petroleum
and natural gas systems source category of the Greenhouse Gas Reporting
Rule consistent with CAA section 136(h) to ensure that reporting under
subpart W is based on empirical data and accurately reflects total
CH4 emissions and waste emissions from applicable
facilities, and to allow owners and operators of applicable facilities
to submit empirical emissions data that appropriately could demonstrate
the extent to which a charge is owed in future implementation of CAA
section 136. These revisions include improving the existing
calculation, recordkeeping, and reporting requirements. Note that one
proposed revision to require continuous parameter monitoring for flares
is not being finalized, resulting in the reduction of capital costs by
$19.1 million.
The EPA is finalizing amendments to part 98 in order to implement
improvements to the GHGRP, including revisions to update existing
emission factors and emissions estimation methodologies, revisions to
require reporting of additional data for new emission sources and
address potential gaps in reporting, and revisions to collect data that
will improve the EPA's understanding of the sector-specific processes
or other factors that influence GHG emission rates, verification of
collected data, or to complement or inform other EPA programs. The EPA
is also finalizing revisions that will improve implementation of the
program, such as those that will provide flexibility for or simplifying
calculation and monitoring methodologies, streamline recordkeeping and
reporting, and other minor technical corrections or clarifications
identified as a result of working with the affected sources during rule
implementation and outreach. The EPA anticipates that the revisions to
improve accuracy of reporting will increase costs for reporters.
As discussed in section V. of this preamble, we are implementing
some of these provisions beginning in RY2024 and some beginning in
RY2025. The amendments for requirements for which reporters would incur
costs will be effective beginning in RY2025. Costs have been estimated
over the three years
[[Page 42210]]
following the year of implementation. The incremental implementation
costs for each reporting year are summarized in table 7 of this
preamble. The estimated annual average labor burden is $169.4 million
per year and the annual average labor burden per reporter is $55,100.
The incremental burden for subpart W and the incremental costs per
reporter are shown in table 7 of this preamble.
Table 7--Total Incremental Labor Burden for Reporting Years 2025-2027
[$2021/year]
----------------------------------------------------------------------------------------------------------------
Cost summary RY2025 RY2026 RY2027 Annual average
----------------------------------------------------------------------------------------------------------------
Burden by Year.................. $169.4 million.... $169.4 million.... $169.4 million.... $169.4 million.
Number of Reporters............. 3,077............. 3,077............. 3,077............. 3,077.
Incremental Labor Cost per $55,100........... $55,100........... $55,100........... $55,100.
Reporter.
----------------------------------------------------------------------------------------------------------------
There is an additional annualized incremental burden of $14.1
million for operation and maintenance (O&M) costs, which reflects
changes to applicability and monitoring. Including capital and O&M
costs, the total annual average burden is $183.6 million over the next
3 years.
The total incremental burden and burden by reporter per subpart W
industry segment are shown in table 8 of this preamble.
Table 8--Total Incremental Burden by Industry Segment and by Reporter
[$2021/year] \a\
----------------------------------------------------------------------------------------------------------------
Count of Capital and Total annual
Industry segment reporters Labor costs O&M Total annual cost per
\b\ \c\ (annualized) cost reporter
----------------------------------------------------------------------------------------------------------------
Onshore Petroleum and Natural Gas 777 $142,067,784 $3,693,563 $145,761,348 $187,595
Production........................
Offshore Petroleum and Natural Gas 141 3,922 0 3,922 28
Production........................
Onshore Petroleum and Natural Gas 361 10,767,359 1,319,919 12,087,278 33,483
Gathering and Boosting............
Onshore Natural Gas Processing..... 515 11,873,365 2,776,745 14,650,110 28,447
Onshore Natural Gas Transmission 1,008 4,064,345 5,891,787 9,956,131 9,877
Compression.......................
Natural Gas Transmission Pipeline.. 53 89,867 187 90,054 1,699
Underground Natural Gas Storage.... 68 319,173 370,275 689,448 10,139
LNG Import and Export Equipment.... 11 51,729 26,350 78,079 7,098
LNG Storage........................ 7 29,922 24,890 54,812 7,830
Natural Gas Distribution........... 164 179,491 0 179,491 1,094
Petroleum and Natural Gas Systems 3,077 169,446,957 14,103,716 183,550,673 59,652
(all segments)....................
----------------------------------------------------------------------------------------------------------------
\a\ Includes estimated increase in costs following implementation of revisions in RY2025.
\b\ Counts are based on GHGRP data reported in RY2020 and 567 new facilities, as detailed in the memorandum,
Assessment of Burden Impacts for Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural Gas
Systems.
\c\ Initial year and subsequent year labor costs are $169.4 million per year.
A full discussion of the cost and burden impacts may be found in
the memorandum, Assessment of Burden Impacts for Greenhouse Gas
Reporting Rule Revisions for Petroleum and Natural Gas Systems,
available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-
2023-0234. As described further in section VI.B. of this preamble, the
national total annual costs of the final rule reflect the fact that
there are a large number of affected entities, but per entity costs and
impacts are low. Considering the improvements to the GHGRP contained in
this final rule as well as the need to comply with CAA section 136(h)
and the anticipated costs of this rule in the context of this industry,
the EPA concludes that the anticipated costs are reasonable and support
the final rule.
2. Summary of Comments and Responses
This section summarizes the major comments and responses related to
the proposed cost impacts.
Comment: Multiple commenters disagreed with the cost estimates
related to changing the reporting of total emissions at the basin level
to reporting total emissions at the well-pad level (for Onshore
Petroleum and Natural Gas Production) or gathering and boosting site
level (for Onshore Petroleum and Natural Gas Gathering and Boosting).
The commenters estimated costs that were 8 times higher than the EPA's
costs for Onshore Petroleum and Natural Gas Production reporting and 15
times higher than the EPA's costs for Onshore Petroleum and Natural Gas
Gathering and Boosting reporting.
Response: Based on consideration of the commenter's cost analysis,
the EPA reassessed the costs for these proposed changes. After
consideration of the large amount of administrative burden shown by the
commenters, the EPA determined it was appropriate to increase the
estimated level of burden and associated costs. The relevant cost
analysis in the proposal was based only on the number of facilities,
without taking into consideration the number of wells per well-pad per
Onshore Petroleum and Natural Gas Production facility and the number of
sites per Onshore Petroleum and Natural Gas Gathering and Boosting
facility. The labor hours were increased from 15 hours at proposal to
90 hours at final for the Onshore Petroleum and Natural Gas Production
industry segment and from 5 hours at proposal to 45 hours at final for
the Onshore Petroleum and Natural Gas Gathering and Boosting industry
segment. As a result, in the EPA's final amendments cost analysis,
these costs have increased from $1.0 million total for both industry
segments in the proposal to $6.5 million total for both industry
segments. For more information, see the information collection request
(ICR) document OMB No. 2060-0751 (EPA ICR number 2774.02) and
Assessment of Burden Impacts for Greenhouse Gas Reporting Rule
Revisions for Petroleum and Natural Gas Systems.
Comment: One commenter noted that the cost analyses related to the
[[Page 42211]]
determination of fuel consumption through fuel records in order to
incorporate combustion slip into their emissions was underestimated.
The commenter argued that the costs should be based on the number of
well-pads or sites instead of the number of facilities and that the
level of effort should be increased from 30 minutes to one hour.
Response: The costs analysis relevant here in the proposal was
based only on the number of facilities, without taking into
consideration the number of wells per well-pad per Onshore Petroleum
and Natural Gas Production facility and the number of sites per Onshore
Petroleum and Natural Gas Gathering and Boosting facility. In the EPA's
final amendments cost analysis, these costs have increased from $50,000
total for both industry segments to $9.2 million total for the three
applicable industry segments. Costs were updated based on the number of
well-pads or sites instead of the number of facilities and the labor
estimate was increased from 30 minutes per facility to one hour per
well-pad or site for the Onshore Petroleum and Natural Gas Production
industry segment and the Onshore Petroleum and Natural Gas Gathering
and Boosting industry segment. The labor estimate was increased from 30
minutes per facility to one hour per facility for the Natural Gas
Distribution industry segment. In the final impacts analysis we also
changed the characterization of combustion slip from a new emission
source to a change in requirements. For more information, see ICR
document OMB No. 2060-0751 (EPA ICR number 2774.02) and Assessment of
Burden Impacts for Greenhouse Gas Reporting Rule Revisions for
Petroleum and Natural Gas Systems.
Comment: One commenter noted that the cost analyses related to the
proposed revisions to 40 CFR 98.36(c)(1) and (3) did not include burden
for the industry segments that have previously reported their
combustion emissions to subpart C. The commenter stated that the
proposed revisions clarify that reporters must separately report
equipment type within the same aggregation of units or common pipe
configuration. According to the commenter, there is significant burden
to change from the aggregation/common pipe methods in subpart C to the
methods within subpart W. The commenter stated that the costs should be
at least 2 hours per year per each aggregation of units/common pipe
reported under subpart C.
Response: As noted by the commenter, costs for this revision were
inadvertently excluded from the impacts analysis in the proposal. After
review of commenter's suggestions, the costs have been incorporated
using the suggested burden, and we included the average number of
aggregations reported to Subpart C for each of the five affected
industry segments (Onshore Natural Gas Processing, Onshore Natural Gas
Transmission Compression, Underground Natural Gas Storage, LNG Import
and Export Equipment, and LNG Storage). Costs were calculated assuming
10 hours per facility per year, or 2 hours per aggregation of units/
common pipe reported under subpart C and an average of five
aggregations per facility based on subpart C data. In the EPA's final
amendments cost analysis, these costs have increased to $1.7 million
total for the five affected industry segments. For more information,
see ICR document OMB No. 2060-0751 (EPA ICR number 2774.02) and
Assessment of Burden Impacts for Greenhouse Gas Reporting Rule
Revisions for Petroleum and Natural Gas Systems.
Comment: Two commenters noted that the cost analyses related to the
proposed revisions to 40 CFR 98.233(n)(2) did not include burden to
account for the monthly visual inspections required for flares that are
not equipped with continuous pilot light monitoring.
Response: As noted by the commenter, costs for this revision were
inadvertently excluded from the impacts analysis in the proposal. After
review of commenter's suggestions, the costs have been incorporated.
Assuming that a technician will inspect each flare once per month,
costs have been updated to $870,000 for Onshore Natural Gas Processing,
$23,000 for Onshore Natural Gas Transmission Compression, $25,000 for
Underground Natural Gas Storage, $31,000 for LNG Import and Export
Equipment, $4.9 million for Onshore Petroleum and Natural Gas Gathering
and Boosting, and $53.5 million for Onshore Petroleum and Natural Gas
Production. Overall costs increased by $59.4 million from proposal to
final.
For more information, see ICR document OMB No. 2060-0751 (EPA ICR
number 2774.02) and Assessment of Burden Impacts for Greenhouse Gas
Reporting Rule Revisions for Petroleum and Natural Gas Systems.
Comment: One commenter noted that the cost analyses related to the
requirement to inspect dump valves was based on the number of
malfunctioning dump valves in each industry segment instead of the
number of tanks in each industry segment.
A second commenter noted that malfunctioning dump valves on
atmospheric storage tanks were incorrectly categorized as new emission
sources even though dump valves are currently reported under the GHGRP
with different requirements.
Response: As noted by the commenter, costs for this revision were
inadvertently based on the number of malfunctioning dump valves in one
reporting year instead of the number of dump valves that must be
inspected. Changes were made to the costs related to dump valve
inspections, assuming one dump valve per tank and using the count of
tanks for each industry segment. Costs in the final rule impacts
analysis are $4.2 million for Onshore Petroleum and Natural Gas
Production, $650,000 for Onshore Petroleum and Natural Gas Gathering
and Boosting and $920,000 for Onshore Natural Gas Processing. The
overall costs increased by $5.7 million from proposal to final.
For more information, see ICR document OMB No. 2060-0751 (EPA ICR
number 2774.02) and Assessment of Burden Impacts for Greenhouse Gas
Reporting Rule Revisions for Petroleum and Natural Gas Systems.
In response to the second commenter, the final impacts analysis
changed the characterization of malfunctioning dump valves from a new
emission source to a change in requirements.
B. Cost-to-Revenue Ratio Analysis
To further assess the economic impacts of the final rule, the EPA
revised from proposal its screening analysis comparing the estimated
total annualized compliance costs for the petroleum and natural gas
systems industry segments with industry mean cost-to-revenue ratios
based on the total facility costs that are applicable to parent
entities in each segment in the final rule. This analysis shows that
the per-entity impacts within each industry segment are low. These low
mean cost-to-revenue ratios indicate that the final rule is unlikely to
result in significant changes in parent entity production decisions or
other choices that would result in significant fluctuations in prices
or quantities in affected markets.
[[Page 42212]]
Table 9--Mean CRRs for Parent Entities by Industry Segment, All Business
Sizes
------------------------------------------------------------------------
Mean CRR (standard
Industry segment error)
------------------------------------------------------------------------
Onshore petroleum and natural gas production... 1.71% (1.63-1.80%)
Offshore petroleum and natural gas production.. 0.02% (0.01-0.02%)
Onshore petroleum and natural gas gathering and 0.90% (0.82-0.99%)
boosting......................................
Onshore natural gas processing................. 0.71% (0.61-0.81%)
Onshore natural gas transmission compression... 0.39% (0.30-0.48%)
Onshore natural gas transmission pipeline...... 0.36% (0.22-0.49%)
Underground natural gas storage................ 0.01% (0.01-0.01%)
LNG import and export equipment................ 0.02% (0.01-0.03%)
LNG storage.................................... 0.00% (0.00-0.00%)
Natural gas distribution....................... 0.17% (0.11-0.23%)
All segments................................... 1.05% (1.00-1.10%)
------------------------------------------------------------------------
CRR = cost-to-revenue ratio.
The EPA also evaluated the mean costs to individual facilities and
mean costs to parents (accounting for multiple owned facilities) for
reporters (shown in table 10 of this preamble), which are relatively
small given the high revenues of parent companies within the petroleum
and natural gas systems sector. There are currently 2,322 existing
facilities reporting to subpart W that are owned by approximately 600
parent entities. Based on a review of revenue data available for
approximately 587 parent entities, the final rule costs represent less
than one percent of the total annual revenue for parent entities that
would be reporting under subpart W.
Table 10--Estimated Mean Costs and Revenues for Facility and Parent
Entities, All Segments
------------------------------------------------------------------------
Estimated values (95%
Metric confidence interval)
------------------------------------------------------------------------
Mean cost to parent entity per facility $43.1 ($42.8-$43.3)
(thousands) \a\..........................
Mean number of facilities owned per parent 4.6
Mean cost to parent for all associated $201.8 ($196.1-$207.5)
facilities (thousands) \a\...............
Mean parent entity revenue (billions) \a\. $11.70 ($10.90-$12.50)
Total revenue for all subpart W parents $8.82 ($8.22-$9.42)
(trillions)..............................
Mean CRR for parent entities, using all 1.05% (1.00-1.10%)
facility costs \b\.......................
------------------------------------------------------------------------
\a\ Average across all existing and new reporters.
\b\ Because parent revenues are heavily skewed towards higher revenues,
the ratio of mean cost to mean revenue (which is approximately
0.0004%) differs substantially from the mean cost-to-revenue ratio
(which is approximately 1.05%).
The EPA has also assessed the potential benefits of the final
amendments to subpart W. The implementation of the final rule will
provide numerous benefits for stakeholders, the Agency, industry, and
the general public. The final revisions strengthen the empirical basis
for and scope of reporting under subpart W so that reporting is based
on empirical data accurately reflects total CH4 emissions
and waste emissions from applicable facilities. These revisions include
improvements to the calculation, monitoring, and reporting
requirements, including updates to existing emission factors and
emissions estimation methodologies, revisions to require reporting of
additional data for new emission sources and address potential gaps in
reporting, and revisions to collect data that will improve the EPA's
understanding of the sector-specific processes or other factors that
influence GHG emission rates, verification of collected data, or to
complement or inform other EPA programs. The revisions will maintain
and improve the quality of the data collected under part 98 where
continued collection of information assists in evaluation and support
of EPA programs and policies under provisions of the CAA.
Because this is a final reporting rule, the EPA did not quantify
estimated emission reductions or monetize the benefits from such
reductions that could be associated with this action. The benefits of
the final amendments are based on their relevance to policy making,
transparency, and market efficiency. The final amendments to the
reporting system for petroleum and natural gas systems will benefit the
EPA, other policymakers, and the public by increasing the completeness
and accuracy of facility emissions data. Public data on emissions
allows for accountability of emitters to the public. Improved facility-
specific emissions data will aid local, state, and national
policymakers as they evaluate and consider future climate change policy
decisions and other policy decisions for criteria pollutants, ambient
air quality standards, and toxic air emissions. The benefits of
improved reporting of petroleum and natural gas systems GHG emissions
to government also include enhancing existing programs, such as the
Natural Gas STAR Program, that provide significant benefits, such as
identifying cost-effective technologies and practices to reduce
emissions of CH4 from operations in all of the major
industry sectors--production, gathering and processing, transmission,
and distribution. The Natural Gas STAR program leverages GHGRP
reporting data to track partner petroleum and natural gas company
activities related to their Methane Challenge commitments. The final
changes to subpart W will increase knowledge of the location and
magnitude of significant CH4 emissions sources in the
petroleum and natural gas industry, and associated activities and
technologies, which can result in improvements in technologies and the
identification of new emissions reducing technologies.
Benefits to industry of improved GHG emissions monitoring and
reporting under the proposed amendments include the value of having
verifiable empirical data to present to the public to demonstrate
appropriate
[[Page 42213]]
environmental stewardship, and a better understanding of their emission
levels and sources to identify opportunities to reduce emissions. The
EPA also anticipates that improvements to monitoring and implementation
of empirical measurement methods will result in emissions reductions.
Based on activity data used to inform the U.S. GHG Inventory, the EPA
estimated approximately 403.4 billion cubic feet of fugitive
CH4 emissions (including fugitive leaks, venting, and
flaring) in 2021, representing a potential loss of over $871 million
\88\ to industry. To the extent that more frequent monitoring helps to
identify and mitigate emissions from leakage, a robust reporting
program based on empirical data can help industry demonstrate and
disseminate their environmental achievements. Businesses and other
innovators can use the data to determine and track their GHG
footprints, find cost-saving efficiencies that reduce GHG emissions and
save product, and foster technologies to protect public health and the
environment and to reduce costs associated with fugitive emissions.
Such monitoring also allows for inclusion of standardized GHG data into
environmental management systems, providing the necessary information
to track actual company performance and to demonstrate and disseminate
their environmental achievements. Once facilities invest in the
institutional knowledge and systems to monitor and report emissions,
the cost of monitoring should fall and the accuracy of the accounting
should continue to improve. The final amendments will continue to allow
for facilities to benchmark themselves against similar facilities to
understand better their relative standing within their industry and
achieve and disseminate information about their environmental
performance.
---------------------------------------------------------------------------
\88\ Based on natural gas prices from EIA (current monthly
average, April 2023). See https://www.eia.gov/dnav/ng/hist/rngwhhdm.htm.
---------------------------------------------------------------------------
In addition, transparent public data on emissions allows for
accountability of polluters to the public who bear the cost of the
pollution. The GHGRP serves as a powerful data resource and provides a
critical tool for communities to identify nearby sources of GHGs and
provide information to state and local governments. GHGRP data are
easily accessible to the public via the EPA's online data publication
tool, also known as FLIGHT (Facility Level Information on Greenhouse
gases Tool) at: https://ghgdata.epa.gov/ghgp/main.do. FLIGHT is
designed for the general public and allows users to view and sort GHG
data from over 8,000 entities in a variety of ways including by
location, industrial sector, and type of GHG emitted, and includes
demographic data. Although the emissions reported to the EPA by
reporting facilities are global pollutants, many of these facilities
also release pollutants that have a more direct and local impact in the
surrounding communities. Citizens, community groups, and labor unions
have made use of public pollutant release data to negotiate directly
with emitters to lower emissions, avoiding the need for additional
regulatory action.
The publicly available data generated by this final rule may be of
particular interest to environmental justice communities. The EPA has
previously engaged with representatives of communities with
environmental justice concerns and heard directly from stakeholders
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. The data
generated in this final reporting rule can be used to inform community
residents or other stakeholders as they search for information about
pollution that affects them, and may provide vital pollutant release
data that is needed for advocates to push for stronger protections
within their communities. This final rule substantially improves the
data reported and made available to environmental justice communities
by improving the accuracy, completeness, and relevance of the data to
community members. Specifically, the disaggregation of reporting
requirements within the Onshore Petroleum and Natural Gas Production
and Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments to at least the well-pad and gathering boosting site-level,
respectively, will provide communities with more localized information
on GHG emissions from these segments that may impact their localities.
Such information has previously been unavailable to affected
environmental justice communities. Additionally, the final amendments
will improve the quality and transparency of reported data to affected
communities, for example, by providing data on other large release
events, including the location, description, and volume of pollutants
released. This final rule also requires reporting of data related to
facilities that receive super-emitter event notifications, including
the type of event resulting in the emissions and an indication of
whether the emissions are included and reported under subpart W. This
information provides transparency and accountability for large
emissions releases and provides important data for impacted
individuals, particularly in environmental justice communities.
Therefore, while the EPA has not quantified the benefits of these
amendments to subpart W, the agency believes that they will be
substantial, and further support a conclusion that the rule is
reasonable and worthwhile. In addition, the focus on strengthening the
empirical basis of the data that is the foundation of this final rule
was mandated by Congress in the IRA.
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is a ``significant regulatory action'' as defined in
Executive Order 12866, as amended by Executive Order 14094.
Accordingly, the EPA submitted this action to the Office of Management
and Budget (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 rulemaking, Docket ID. No. EPA-HQ-OAR-
2023-0234. The EPA prepared an analysis of the potential impacts
associated with this action. This analysis, Assessment of Burden
Impacts for Greenhouse Gas Reporting Rule Revisions for Petroleum and
Natural Gas Systems, is also available in the docket to this rulemaking
and is briefly summarized in section VI. of this preamble.
B. Paperwork Reduction Act (PRA)
The information collection activities in this rule have been
submitted for approval to the OMB under the PRA. The Information
Collection Request (ICR) document that the EPA prepared has been
assigned OMB Number 2060-0751 (EPA ICR number 2774.02). 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.
The EPA estimates that the amendments will result in an increase in
burden. The burden associated with the final rule is due to revisions
that will expand reporting to include new emission sources or that
expand the industry segments covered by existing emissions sources and
that may impact
[[Page 42214]]
the facilities that are required to report to subpart W; revisions to
emissions calculation methodologies that will require additional
monitoring; and revisions to collect additional data to more accurately
reflect and verify total CH4 emissions in reports submitted
to the GHGRP or to provide information for future implementation of the
waste emissions charge under CAA section 136. As a result of these
revisions, 567 new sources are expected to become subject to subpart W.
Labor and O&M costs are included for those new sources to comply with
the reporting and recordkeeping costs detailed in EPA ICR number
2300.18, as well as costs to comply with these revisions.\89\
---------------------------------------------------------------------------
\89\ In addition to the costs to comply with these revisions,
the 567 new sources will also incur the average subpart W reporter-
level labor and O&M costs, which differ by industry segment, from
OMB Number 2060-0629 (EPA ICR number 2300.18) to comply with the
subpart W requirements that were in place prior to these revisions.
---------------------------------------------------------------------------
The estimated annual average burden is 1,902,792 hours and $183.6
million (per year) over the 3 years covered by this information
collection. Further information on the EPA's assessment on the impact
on burden can be found in the memorandum, Assessment of Burden Impacts
for Greenhouse Gas Reporting Rule Revisions for Petroleum and Natural
Gas Systems, in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2023-0234.
Respondents/affected entities: Owners and operators of petroleum
and natural gas systems that must report their GHG emissions and other
data to the EPA to comply with 40 CFR part 98.
Respondent's obligation to respond: The respondent's obligation to
respond is mandatory under the authority provided in CAA sections 114
and 136.
Estimated number of respondents: 3,077 (affected by final
amendments).
Frequency of response: Annually.
Total estimated burden: 1,902,792 hours (per year). Burden is
defined at 5 CFR 1320.3(b).
Total estimated cost: $183.6 million, (per year), includes $14.1
million annualized operation & maintenance costs.
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)
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. The
small entities subject to the requirements of this action are small
businesses in the petroleum and natural gas industry. Small entities
include small businesses, small organizations, and small governmental
jurisdictions. The EPA has determined that some small entities are
affected because their production processes emit GHGs that must be
reported.
In the implementation of the GHGRP, the EPA previously determined
thresholds that reduced the number of small businesses reporting. For
example, petroleum and natural gas facilities generally only report to
part 98 if all combined emissions from the facility, including
stationary fuel combustion and other applicable manufacturing source
categories, exceed 25,000 mtCO2e per year. However,
facilities from the Onshore Petroleum and Natural Gas Production,
Natural Gas Distribution, Onshore Petroleum and Natural Gas Gathering
and Boosting, and Onshore Natural Gas Transmission Pipeline industry
segments must report if specific petroleum and natural gas emissions
sources from these operations emit 25,000 mtCO2e or more per
year. These thresholds are intended to exclude smaller enterprises
that, generally, are not significant emissions sources. The EPA
estimates that in most cases, smaller enterprises have very small
operations (such as a single family owning a few production wells) that
are unlikely to cross the 25,000 mtCO2e reporting threshold.
The final revisions will not revise the threshold for existing subpart
W reporters, therefore, we do not expect a significant number of small
entities will be newly impacted under the final rule revisions.
The amendments apply to 2,322 existing facilities and 567 new
facilities that result from rule revisions that require the reporting
of new emission sources or that expand the industry segments covered.
The rule amendments predominantly apply to existing reporters and are
amendments that will expand reporting to include new emission sources;
add, remove, or refine emissions estimation methodologies to improve
the accuracy and transparency of reported emission data; for the
Onshore Natural Gas Production and Onshore Natural Gas Gathering and
Boosting segments, revise reporting of emissions from a basin level to
a site level; implement requirements to collect new or revised data;
clarify or update provisions that have been misinterpreted; or
streamline or simplify requirements by increasing flexibility for
reporters or removing redundant requirements.
The EPA conducted a small entity analysis that assessed the costs
and impacts to small entities, including: (1) Revisions to add new
emissions sources and expand the industry segments covered by existing
emissions sources, (2) changes to improve existing monitoring or
calculation methodologies, and (3) revisions to reporting and
recordkeeping requirements for data provided to the program. The Agency
anticipates that although a subset of small entity reporters (160-180)
have a cost-to-revenue ratio (CRR) > 1%, there are only a limited
number (73-75) of small entities, primarily in the very small business
size range (1-19 employees), that would be likely to have significant
impacts with CRR > 3%, reflecting a small proportion (6.3%-14.0%) of
the total affected small entities. The mean CRR for these very small
entities (1-19 employees) is estimated to be between 2.19% (2.11-2.28%)
and 3.79% (3.47-4.11%) based on the incremental costs for existing
reporting entities and between 2.78% (2.63-2.92%) and 4.79% (4.28-
5.31%) based on the costs for newly reporting entities.\90\ Details of
this analysis are presented in the memorandum, Assessment of Burden
Impacts for Greenhouse Gas Reporting Rule Revisions for Petroleum and
Natural Gas Systems, available in the docket for this rulemaking,
Docket ID. No. EPA-HQ-OAR-2023-0234. Based on the results of this
analysis, we have concluded that this action is not likely to have a
significant regulatory burden for a substantial number of small
entities and thus that this action will not have a significant economic
impact on a substantial number of small entities.
---------------------------------------------------------------------------
\90\ The EPA conducted a multi-level analysis to estimate mean
CRRs for multiple scenarios. The mean CRR and associated 95-percent
confidence intervals provide an estimate of the range of cost-to-
sales rtios expected to apply to affected very small entities that
would be expected in the total population.
---------------------------------------------------------------------------
D. Unfunded Mandates Reform Act (UMRA)
This action does not contain an unfunded mandate of $100 million or
more (adjusted annually for inflation) as described in UMRA, 2 U.S.C.
1531-1538, for state, local, and tribal governments, in the aggregate,
or the
[[Page 42215]]
private sector in any one year, and does not significantly or uniquely
affect small governments. The costs involved in this action are
estimated not to exceed $100 million or more (adjusted for inflation,
with the current threshold of approximately $198 million) in any one
year. The yearly costs of this final action are presented in tables 7
and 8 of this preamble. The action in part implements mandate(s)
specifically and explicitly set forth in CAA section 136.
This final rule does not apply to governmental entities unless the
government entity owns a facility in the petroleum and gas industry
that directly emits GHG above part 98 applicability threshold levels.
It does not impose any implementation responsibilities on state, local,
or tribal governments and it is not expected to increase the cost of
existing regulatory programs managed by those governments. Thus, the
impact on governments affected by the final rule is expected to be
minimal.
E. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government. This final
rule does not apply to governmental entities unless the government
entity owns a facility in the petroleum and gas industry (e.g., an LDC)
that directly emits GHG above part 98 applicability threshold levels.
Therefore, the EPA anticipates relatively few state or local government
facilities will be affected.
However, consistent with the EPA's policy to promote communications
between the EPA and state and local governments, the EPA sought
comments from small governments concerning the regulatory requirements
that might significantly or uniquely affect them in the development of
the final rule. Specifically, the EPA previously published an RFI
seeking public comment in a non-regulatory docket to collect responses
to a range of questions related to the Methane Emissions Reduction
Program, including subpart W revisions (see Docket ID. No. EPA-HQ-OAR-
2022-0875). The EPA received two comments from government entities
supporting the use of empirical data and improvements to the accuracy
of calculation methods under subpart W. The EPA also solicited comments
on the 2023 Subpart W Proposal; the EPA did not receive any comments
regarding concerns that this rule will significantly or uniquely affect
small governments. All comments were considered during the development
of the final rule.
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. This regulation will apply
directly to petroleum and natural gas facilities that may be owned by
tribal governments that emit GHGs. However, it will generally only have
tribal implications where the tribal entity owns a facility that
directly emits GHGs above threshold levels; therefore, relatively few
tribal facilities will be affected. Of the subpart W facilities
currently reporting to the GHGRP in RY2021, we identified four
facilities currently reporting to part 98 that are owned by one tribal
parent company. In addition to tribes that will be directly impacted by
the final revisions due to owning a facility subject to the
requirements, the EPA anticipates that tribes could be impacted in
cases where facilities subject to the final revisions are located on
Tribal land. In particular, the EPA reviewed the location of the
production wells reported by facilities under the Onshore Petroleum and
Natural Gas Production segment and found production wells reported
under subpart W on lands associated with approximately 20 tribes.
Therefore, although the EPA anticipates that only one tribe will be
directly subject to the rule, the EPA took a number of steps to provide
information, consult with, and obtain input from tribal governments and
representatives during the development of the rule. On November 4,
2022, the EPA published an RFI seeking public comment on a range of
questions related to the Methane Emissions Reduction Program, including
subpart W revisions (see Docket ID. No. EPA-HQ-OAR-2022-0875). The EPA
received one comment from a tribal entity relevant to subpart W. The
commenter supported the use of empirical data and improvements to the
accuracy of calculation methods under subpart W, including the use of
advanced CH4 detection technologies for leak surveys at well
sites and compressor stations; these comments were considered during
the development of the rule. The EPA further consulted with tribal
officials under the EPA Policy on Consultation and Coordination with
Indian Tribes early in the process of developing this regulation, to
permit them to have meaningful and timely input into its development.
On July 11, 2023, the EPA invited all 574 federally-recognized Tribes,
Alaska Native Villages, and Alaska Native Corporations, to consult on
the proposed revisions at a date and time developed in consultation
with Tribes requesting consultation, with an anticipated consultation
timeline of September 4, 2023; a copy of this letter is available in
the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
Only one Tribe participated in government-to-government consultation
with the EPA. In response, the EPA met with the Ute Indian Tribe's
Business Committee via video conference at 3:30 p.m. Eastern Time on
September 20, 2023. The EPA provided several other opportunities for
tribal input; the EPA opened the rule for public comment from August 1
to October 2, 2023, and hosted a virtual public hearing for the
proposed revisions on August 21, 2023. The EPA provided a subsequent
informational webinar on the technical aspects of the rule on September
7, 2023. The EPA has considered the tribal input from the coordination
and consultation calls, informational webinar, and public comments in
the development of the final rule.
As required by section 7(a), the EPA's Tribal Consultation Official
has certified that the requirements of the executive order have been
met in a meaningful and timely manner. A copy of the certification is
included in the docket for this action.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that concern environmental health or safety risks
that the EPA has reason to believe may disproportionately affect
children, per the definition of ``covered regulatory action'' in
section 2-202 of the Executive Order. This action regarding revisions
to reporting requirements is not subject to Executive Order 13045
because it does not concern an environmental health risk or safety
risk.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
This action is not a ``significant energy action'' because it is
not likely to have a significant adverse effect on the supply,
distribution or use of energy. The final amendments will expand
reporting to include new emission sources; add, remove, or refine
emissions estimation methodologies; improve the accuracy and
transparency
[[Page 42216]]
of reported emission data; for the Onshore Natural Gas Production and
Onshore Natural Gas Gathering and Boosting segments, revise reporting
of emissions from a basin level to a site level; implement requirements
to collect new or revised data; clarify or update provisions that have
been misinterpreted; or streamline or simplify requirements by
increasing flexibility for reporters or removing redundant
requirements. We are also finalizing revisions that streamline or
simplify requirements or alleviate burden through revision,
simplification, or removal of certain calculation, monitoring,
recordkeeping, or reporting requirements. In general, these changes
will not have a significant, adverse effect on the supply,
distribution, or use of energy. In addition, the EPA is finalizing
confidentiality determinations for new and revised data elements
included in this rulemaking and for certain existing data elements for
which a confidentiality determination has not previously been
finalized. These amendments and confidentiality determinations do not
make any changes to the existing monitoring, calculation, and reporting
requirements under subpart W and are not likely to have a significant
adverse effect on the supply, distribution, or use of energy.
I. National Technology Transfer and Advancement Act and 1 CFR Part 51
This action involves technical standards. The EPA has decided to
incorporate by reference several standards in establishing monitoring
requirements in these final amendments.
For enclosed combustion devices, the EPA is finalizing a
requirement to conduct a performance test to use the Tier 2 destruction
efficiency and combustion efficiency. The test must be conducted in
accordance with 40 CFR 60.5413b(b) or (d) or using EPA Other Test
Method 52 (OTM-52), Method for Determination of Combustion Efficiency
from Enclosed Combustors Located at Oil and Gas Production Facilities,
dated September 26, 2023. In OTM-52, a gas sample is continuously
extracted from the exhaust duct of an enclosed combustion device and
conveyed to a gas analyzer(s) for determination of CO2, CO,
and hydrocarbon concentrations for the calculation of combustion
efficiency. Anyone may access OTM-52 at https://www.epa.gov/emc/emc-other-test-methods. This standard is available to everyone at no cost;
therefore, the method is reasonably available for reporters.
For facilities that conduct a performance test to calculate
combustion slip, the EPA is finalizing a requirement that the
performance test will be conducted in accordance with one of the test
methods in 40 CFR 98.234(i), which include EPA Methods 18 and 320 as
well as an alternate method, ASTM D6348-12 (Reapproved 2020), Standard
Test Method for Determination of Gaseous Compounds by Extractive Direct
Interface Fourier Transform Infrared (FTIR) Spectroscopy, Approved
December 1, 2020. The EPA is allowing the use of the alternate method
ASTM D6348-12, which is based on the use of a Fourier transform
infrared (FTIR) spectrometer for the identification and quantification
of multicomponent gaseous compounds in stationary source effluent, in
lieu of EPA Method 320. The EPA currently allows for the use of an
earlier version of this method, ASTM D6348-03, under other subparts of
part 98, including subparts I (Electronics Manufacturing), V (Nitric
Acid Production), and OO (Fluorinated Gas Production), for the
quantification of other GHGs. Therefore, the EPA is allowing ASTM
D6348-12 to be used in subpart W to quantify CH4 emissions
from combustion slip. Anyone may access the standard ASTM D6348-12 on
the ASTM website (https://www.astm.org/) for additional information.
The standard is available to everyone at a cost determined by the ASTM
($76). The ASTM also offers memberships or subscriptions that allow
unlimited access to their methods. The cost of obtaining these methods
is not a significant financial burden, making the methods reasonably
available for reporters. The EPA will also make a copy of these
documents available in hard copy at the appropriate EPA office (see the
FOR FURTHER INFORMATION CONTACT section of this preamble for more
information) for review purposes only.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Because this is an information collection and reporting rule, it
does not directly affect human health or environmental conditions and
therefore the EPA cannot evaluate potentially disproportionate and
adverse effects on communities with environmental justice concerns.
Although this action does not directly affect human health or
environmental conditions, we expect it will affect environmental
justice concerns by greatly improving the availability, accuracy, and
relevance of information about pollution in their communities.
The EPA has developed improvements to the GHGRP in the final rule
that benefit the public, including environmental justice communities,
by increasing the completeness and accuracy of facility emissions data.
The data that will be collected through this action will provide an
important data resource for communities and the public to understand
GHG emissions. Although the emissions reported to the EPA by reporting
facilities are global pollutants, many of these facilities also release
pollutants that have a more direct and local impact in the surrounding
communities. Since facilities will be required to use prescribed
calculation and monitoring methods, emissions data can be compared and
analyzed, including locations of emissions sources. GHGRP data are
easily accessible to the public via the EPA's online data publication
tool (FLIGHT), available at: https://ghgdata.epa.gov/ghgp/main.do.
FLIGHT allows users to view and sort GHG data for every reporting year
starting with 2010 from over 8,000 entities in a variety of ways
including by location, industrial sector, and type of GHG emitted, and
provides supplementary demographic data that may be useful to
communities with environmental justice concerns. This powerful data
resource provides a critical tool for communities to identify nearby
sources of GHGs, including methane and nitrous oxide, and to provide
information to state and local governments. The EPA believes that the
transparency provided by the data reported under these final revisions
will ultimately encourage and result in reduction of GHG emissions and
other co-pollutants, such as hazardous air pollutants and volatile
organic compounds.
The final revisions to part 98 include requirements for reporting
of GHG data from additional emission sources (other large release
events, nitrogen removal units, produced water tanks, crankcase
venting, and mud degassing), improvements to emissions calculation
methodologies, and collection of data to support verification of GHG
emissions and transparency. The disaggregation of reporting
requirements within the Onshore Petroleum and Natural Gas Production
and Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments to at least the well-pad and gathering boosting site-level,
respectively, and the required reporting of geographical coordinates
for other large release events, will provide communities with
additional, more localized information on GHG emissions from these
segments. Overall, these
[[Page 42217]]
revisions will improve the quality, availability and relevance of the
data collected under the program and available to communities, and
generally will improve environmental justice outcomes.
Finally, the EPA has promoted meaningful engagement from
communities in developing the action, and in developing requirements
that improve the quality of data submitted to the EPA, which are also
available to communities as consistent with EPA's confidentiality
determinations. The EPA has provided several opportunities for public
engagement. The EPA opened the rule for public comment from August 1 to
October 2, 2023, and hosted a virtual public hearing for the proposed
revisions on August 21, 2023. The EPA provided a subsequent
informational webinar on the technical aspects of the rule on September
7, 2023. The EPA has taken into consideration comments received from
representatives and stakeholders in the development of this final rule.
K. Congressional Review Act (CRA)
This action is subject to the CRA, and the EPA will submit a rule
report to each House of the Congress and to the Comptroller General of
the United States. The Office of Information and Regulatory Affairs has
determined that this action meets the criteria set forth by 5 U.S.C.
804(2).
L. Judicial Review
Under CAA section 307(b)(1), any petition for review of this final
rule must be filed in the U.S. Court of Appeals for the District of
Columbia Circuit by July 15, 2024. This final rule establishes
requirements applicable to owners and operators of facilities in the
petroleum and natural gas systems source category located across the
United States that are subject to 40 CFR part 98 and therefore is
``nationally applicable'' within the meaning of CAA section 307(b)(1).
Under CAA section 307(d)(7)(B), only an objection to this final rule
that was raised with reasonable specificity during the period for
public comment can be raised during judicial review. CAA section
307(d)(7)(B) also provides a mechanism for the EPA to convene a
proceeding for reconsideration, ``[i]f the person raising an objection
can demonstrate to 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 should submit a Petition for Reconsideration
to the Office of the Administrator, Environmental Protection Agency,
Room 3000, William Jefferson Clinton Building, 1200 Pennsylvania Ave.
NW, Washington, DC 20460, with an electronic copy to the person listed
in FOR FURTHER INFORMATION CONTACT, and the Associate General Counsel
for the Air and Radiation Law Office, Office of General Counsel (Mail
Code 2344A), Environmental Protection Agency, 1200 Pennsylvania Ave.
NW, Washington, DC 20004. Note that under CAA section 307(b)(2), the
requirements established by this final rule may not be challenged
separately in any civil or criminal proceedings brought by the EPA to
enforce these requirements.
M. Determination Under CAA Section 307(d)
Pursuant to CAA section 307(d)(1)(V), the Administrator determined
that this rule is subject to the provisions of CAA section 307(d). See
CAA section 307(d)(1)(V) (the provisions of section 307(d) apply to
``such other actions as the Administrator may determine'').
N. Severability
This final rule includes new and revised requirements for numerous
provisions under various aspects of subpart W of the GHGRP. Therefore,
this final rule is a multifaceted rule that addresses many separate
things for independent reasons, as detailed in each respective portion
of this preamble. We intend each portion of this rule to be severable
from each other, though we took the approach of including all the parts
in one rulemaking rather than promulgating multiple rules to ensure the
changes are adopted and implemented in a coordinated manner, even
though the changes are not inter-dependent.
For example, the EPA notes that our judgments regarding revisions
for each industry segment consistent with our Clean Air Act authority
and the directives in CAA section 136(h) reflect our determinations
specific to considerations within each industry segment, while our
judgment regarding the revisions to requirements for each type of
source within each subpart W industry segment reflect our
determinations specific to considerations for each source in each
industry segment. The revisions for a given industry segment are
intended to be and are implementable even absent revisions to the other
industry segments (for example, Offshore Production revisions are
independent from Onshore Petroleum and Natural Gas Production
revisions), and likewise for each source within each industry segment,
as they each independently ensure that the emissions reported under
subpart W for the given source or industry segment at issue are
consistent with the directives in CAA section 136(h) and improve the
subpart W provisions as described in section II. of this preamble.
Regarding revisions to requirements for each source being separate from
each other, this includes, for a couple of examples, revisions to
provisions for determining emissions emitted to the atmosphere being
separate from revisions to provisions for determining emissions sent to
a control device from a source as well as revisions to provisions for
determining emissions emitted as an other large release event being
separate from revisions to provisions for determining emissions from
such a source when the emissions do not qualify as an other large
release event. Accordingly, the EPA finds that revisions to each type
of source in each industry segment are severable from revisions to each
other type of source in each industry segment, and that at minimum
revisions to each industry segment are severable from revisions to each
of the other industry segments.
Additionally, our judgments regarding each calculation method for
each source are likewise independent and do not rely on one another, as
they each independently ensure that the emissions reported under
subpart W for the given source or industry segment at issue are
consistent with the directives in CAA section 136(h) and improve the
subpart W provisions as described in section II. of this preamble.
Accordingly, the EPA finds that each calculation method for each source
is severable.
Finally, as described in section II. of this preamble, the EPA
notes that there are changes the EPA is making related to amending
certain requirements that apply to the general provisions, general
stationary fuel combustion, and petroleum and natural gas systems
source categories of the Greenhouse Gas Reporting Rule to improve
calculation, monitoring, and reporting of greenhouse gas data for
petroleum and natural gas systems facilities, as well as establishing
and amending confidentiality determinations for the reporting of
certain data elements to be added or substantially revised in these
amendments. The EPA's overall GHGRP subpart W program continues to be
fully implementable even in the absence of any one or more of these
elements.
Thus, the EPA has independently considered and adopted each of
these portions of the final rule (including but
[[Page 42218]]
not limited to the updates to each industry segment; each type of
source in each industry segment; each calculation methodology for each
source; requirements that apply to the general provisions, general
stationary fuel combustion, and petroleum and natural gas systems
source categories of the Greenhouse Gas Reporting Rule to improve
calculation, monitoring, and reporting of greenhouse gas data for
petroleum and natural gas systems facilities; and establishing and
amending confidentiality determinations for the reporting of certain
data elements to be added or substantially revised in these amendments)
and each is severable should there be judicial review. If a court were
to invalidate any one of these elements of the final rule, we intend
the remainder of this action to remain effective. Importantly, we have
designed these different elements of the program to function sensibly
and independently, the supporting basis for each of these elements of
the final rule reflects that they are independently justified and
appropriate, and we find each portion appropriate even if one or more
other parts of the rule has been set aside. For example, if a reviewing
court were to invalidate any of the revisions to address potential gaps
in reporting of emissions data for specific sectors, the other
regulatory amendments, including not only the other revisions to
address potential gaps but also the other changes to discrete elements
of the subpart W provisions, remain fully operable. Moreover, this list
is not intended to be exhaustive, and should not be viewed as an
intention by the EPA to consider other parts of the rule not explicitly
listed here as not severable from other parts of the rule.
List of Subjects in 40 CFR Part 98
Environmental protection, Greenhouse gases, Incorporation by
reference, Reporting and recordkeeping requirements.
Michael S. Regan,
Administrator.
For the reasons stated in the preamble, the Environmental
Protection Agency amends title 40, chapter I, of the Code of Federal
Regulations as follows:
PART 98--MANDATORY GREENHOUSE GAS REPORTING
0
1. The authority citation for part 98 continues to read as follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart A--General Provision
0
2. Amend Sec. 98.1 by revising paragraph (c) to read as follows:
Sec. 98.1 Purpose and scope.
* * * * *
(c) For facilities required to report under onshore petroleum and
natural gas production under subpart W of this part, the terms Owner
and Operator used in this subpart have the same definition as Onshore
petroleum and natural gas production owner or operator, as defined in
Sec. 98.238. For facilities required to report under onshore petroleum
and natural gas gathering and boosting under subpart W of this part,
the terms Owner and Operator used in this subpart have the same
definition as Gathering and boosting system owner or operator, as
defined in Sec. 98.238. For facilities required to report under
onshore natural gas transmission pipeline under subpart W of this part,
the terms Owner and Operator used in this subpart have the same
definition as Onshore natural gas transmission pipeline owner or
operator, as defined in Sec. 98.238.
0
3. Amend Sec. 98.2 by revising paragraph (i)(3) and adding paragraph
(i)(7) to read as follows:
Sec. 98.2 Who must report?
* * * * *
(i) * * *
(3) If the operations of a facility or supplier are changed such
that all applicable processes and operations subject to paragraphs
(a)(1) through (4) of this section cease to operate, then the owner or
operator may discontinue complying with this part for the reporting
years following the year in which cessation of such operations occurs,
provided that the owner or operator submits a notification to the
Administrator that announces the cessation of reporting and certifies
to the closure of all applicable processes and operations no later than
March 31 of the year following such changes. If one or more processes
or operations subject to paragraphs (a)(1) through (4) of this section
at a facility or supplier cease to operate, but not all applicable
processes or operations cease to operate, then the owner or operator is
exempt from reporting for any such processes or operations in the
reporting years following the reporting year in which cessation of the
process or operation occurs, provided that the owner or operator
submits a notification to the Administrator that announces the
cessation of reporting for the process or operation no later than March
31 following the first reporting year in which the process or operation
has ceased for an entire reporting year. Cessation of operations in the
context of underground coal mines includes, but is not limited to,
abandoning and sealing the facility. This paragraph (i)(3) does not
apply to seasonal or other temporary cessation of operations. This
paragraph (i)(3) does not apply to the municipal solid waste landfills
source category (subpart HH of this part), or the industrial waste
landfills source category (subpart TT of this part). This paragraph
(i)(3) does not apply when there is a change in the owner or operator
for facilities in industry segments with a unique definition of
facility as defined in Sec. 98.238 of the petroleum and natural gas
systems source category (subpart W of this part), unless the changes
result in permanent cessation of all applicable processes and
operations. The owner or operator must resume reporting for any future
calendar year during which any of the GHG-emitting processes or
operations resume operation.
* * * * *
(7) If a facility in an industry segment with a unique definition
of facility as defined in Sec. 98.238 of the petroleum and natural gas
systems source category (subpart W of this part) undergoes the type of
change in owner or operator specified in paragraph Sec. 98.4(n)(4) of
this subpart, then the prior owner or operator may discontinue
complying with the reporting requirements of this part for the facility
for the reporting years following the year in which the change in owner
or operator occurred, provided that the prior owner or operator submits
a notification to the Administrator that announces the discontinuation
of reporting no later than March 31 of the year following such change.
* * * * *
0
4. Amend Sec. 98.4 by revising the first sentence of paragraph (h) and
adding paragraph (n) to read as follows:
Sec. 98.4 Authorization and responsibilities of the designated
representative.
* * * * *
(h) Changes in owners and operators. Except as provided in
paragraph (n) of this section, in the event an owner or operator of the
facility or supplier is not included in the list of owners and
operators in the certificate of representation under this section for
the facility or supplier, such owner or operator shall be deemed to be
subject to and bound by the certificate of representation, the
representations, actions, inactions, and submissions of the designated
representative and any
[[Page 42219]]
alternate designated representative of the facility or supplier, as if
the owner or operator were included in such list. * * *
* * * * *
(n) Alternative provisions for changes in owners and operators for
industry segments with a unique definition of facility as defined in
Sec. 98.238. When there is a change to the owner or operator of a
facility required to report under the onshore petroleum and natural gas
production, natural gas distribution, onshore petroleum and natural gas
gathering and boosting, or onshore natural gas transmission pipeline
industry segments of subpart W of this part, or a change to the owner
or operator for some emission sources from the facility in one of these
industry segments, the provisions specified in paragraphs (n)(1)
through (4) of this section apply for the respective type of change in
owner or operator.
(1) If the entire facility is acquired by an owner or operator that
does not already have a reporting facility in the same industry segment
and basin (for onshore petroleum and natural gas production or onshore
petroleum and natural gas gathering and boosting) or state (for natural
gas distribution), then within 90 days after the change in the owner or
operator, the designated representative or any alternate designated
representative shall submit a certificate of representation that is
complete under this section. If the new owner or operator already had
emission sources specified in Sec. 98.232(c), (i), (j), or (m), as
applicable, prior to the acquisition in the same basin (for onshore
petroleum and natural gas production or onshore petroleum and natural
gas gathering and boosting) or state (for natural gas distribution) as
the acquired facility but had not previously met the applicability
requirements in Sec. Sec. 98.2(a) and 98.231, then per the applicable
definition of facility in Sec. 98.238, the previously owned applicable
emission sources must be included in the acquired facility. The new
owner or operator and the new designated representative shall be
responsible for submitting the annual report for the facility for the
entire reporting year beginning with the reporting year in which the
acquisition occurred.
(2) If the entire facility is acquired by an owner or operator that
already has a reporting facility in the same industry segment and basin
(for onshore petroleum and natural gas production or onshore petroleum
and natural gas gathering and boosting) or state (for natural gas
distribution), the new owner or operator shall merge the acquired
facility with their existing facility for purposes of the annual GHG
report. The owner or operator shall also follow the provisions of Sec.
98.2(i)(6) to notify EPA that the acquired facility will discontinue
reporting and shall provide the e-GGRT identification number of the
merged, or reconstituted, facility. The owner or operator of the merged
facility shall be responsible for submitting the annual report for the
merged facility for the entire reporting year beginning with the
reporting year in which the acquisition occurred.
(3) If only some emission sources from the facility are acquired by
one or more new owners or operators, the existing owner or operator
(i.e., the owner or operator of the portion of the facility that is not
sold) shall continue to report under subpart W of this part for the
retained emission sources unless and until that facility meets one of
the criteria in Sec. 98.2(i). Each owner or operator that acquires
emission sources from the facility must account for those acquired
emission sources according to paragraph (n)(3)(i) or (ii) of this
section, as applicable.
(i) If the purchasing owner or operator that acquires only some of
the emission sources from the existing facility does not already have a
reporting facility in the same industry segment and basin (for onshore
petroleum and natural gas production or onshore petroleum and natural
gas gathering and boosting) or state (for natural gas distribution),
the purchasing owner or operator shall begin reporting as a new
facility. The new facility must include the acquired emission sources
specified in Sec. 98.232(c), (i), (j), or (m), as applicable, and any
emission sources the purchasing owner or operator already owned in the
same industry segment and basin (for onshore petroleum and natural gas
production or onshore petroleum and natural gas gathering and boosting)
or state (for natural gas distribution). The designated representative
for the new facility must be selected by the purchasing owner or
operator according to the schedule and procedure specified in
paragraphs (b) through (d) of this section. The purchasing owner or
operator shall be responsible for submitting the annual report for the
new facility for the entire reporting year beginning with the reporting
year in which the acquisition occurred. The purchasing owner or
operator shall continue to report under subpart W of this part for the
new facility unless and until that facility meets one of the criteria
in Sec. 98.2(i).
(ii) If the purchasing owner or operator that acquires only some of
the emission sources from the existing facility already has a reporting
facility in the same industry segment and basin (for onshore petroleum
and natural gas production or onshore petroleum and natural gas
gathering and boosting) or state (for natural gas distribution), then
per the applicable definition of facility in Sec. 98.238, the
purchasing owner or operator must add the acquired emission sources
specified in Sec. 98.232(c), (i), (j), or (m), as applicable, to their
existing facility for purposes of reporting under subpart W of this
part. The purchasing owner or operator shall be responsible for
submitting the annual report for the entire facility, including the
acquired emission sources, for the entire reporting year beginning with
the reporting year in which the acquisition occurred.
(4) If all the emission sources from a reporting facility are sold
to multiple owners or operators within the same reporting year, such
that the prior owner or operator of the facility does not retain any of
the emission sources, then the prior owner or operator of the facility
shall notify EPA within 90 days of the last transaction that all of the
facility's emission sources were acquired by multiple purchasers,
including the identity of the purchasers. Each owner or operator that
acquires emission sources from a facility shall account for those
sources according to paragraph (n)(3)(i) or (ii) of this section, as
applicable.
0
5. Amend Sec. 98.6 by revising the definitions ``Dehydrator,''
``Dehydrator vent emissions,'' ``Desiccant,'' and ``Vapor recovery
system'' to read as follows:
Sec. 98.6 Definitions.
* * * * *
Dehydrator means a device in which a liquid absorbent (including
ethylene glycol, diethylene glycol, or triethylene glycol) or desiccant
directly contacts a natural gas stream to remove water vapor.
Dehydrator vent emissions means natural gas and CO2
released from a natural gas dehydrator system absorbent (typically
glycol) regenerator still vent and, if present, a flash tank separator,
to the atmosphere, flare, regenerator fire-box/fire tubes, or vapor
recovery system. Emissions include stripping natural gas and motive
natural gas used in absorbent circulation pumps.
* * * * *
Desiccant means a material used in solid-bed dehydrators to remove
water from raw natural gas by adsorption or absorption. Desiccants
include, but are not limited to, molecular sieves,
[[Page 42220]]
activated alumina, pelletized calcium chloride, lithium chloride and
granular silica gel material. Wet natural gas is passed through a bed
of the granular or pelletized solid adsorbent or absorbent in these
dehydrators. As the wet gas contacts the surface of the particles of
desiccant material, water is adsorbed on the surface or absorbed and
dissolves the surface of these desiccant particles. Passing through the
entire desiccant bed, almost all of the water is adsorbed onto or
absorbed into the desiccant material, leaving the dry gas to exit the
contactor.
* * * * *
Vapor recovery system means any equipment located at the source of
potential gas emissions to the atmosphere or to a flare, that is
composed of piping, connections, and, if necessary, flow-inducing
devices, and that is used for routing the gas back into the process as
a product and/or fuel. For purposes of Sec. 98.233, routing emissions
from a dehydrator regenerator still vent or flash tank separator vent
to a regenerator fire-box/fire tubes does not meet the definition of
vapor recovery system.
* * * * *
0
6. Amend Sec. 98.7 by redesignating paragraphs (d)(36) through (50) as
(d)(37) though (51), respectively, adding new paragraph (d)(36), and
adding paragraph (m)(15) to read as follows:
Sec. 98.7 What standardized methods are incorporated by reference
into this part?
* * * * *
(d) * * *
(36) ASTM D6348-12 (Reapproved 2020) Standard Test Method for
Determination of Gaseous Compounds by Extractive Direct Interface
Fourier Transform Infrared (FTIR) Spectroscopy, Approved December 1,
2020, IBR approved for Sec. 98.234(i).
* * * * *
(m) * * *
(15) Other Test Method 52 (OTM-52), Method for Determination of
Combustion Efficiency from Enclosed Combustors Located at Oil and Gas
Production Facilities, dated September 26, 2023, https://www.epa.gov/emc/emc-other-test-methods, IBR approved for Sec. 98.233(n).
* * * * *
Subpart C--General Stationary Fuel Combustion Sources
0
7. Amend Sec. 98.33 by revising parameter ``EF'' of equation C-8 in
paragraph (c)(1) introductory text, parameter ``EF'' of equation C-8a
in paragraph (c)(1)(i), parameter ``EF'' of equation C-8b in paragraph
(c)(1)(ii), parameter ``EF'' of equation C-9a in paragraph (c)(2), and
parameter ``EF'' of equation C-10 in paragraph (c)(4) introductory text
to read as follows:
Sec. 98.33 Calculating GHG emissions.
* * * * *
(c) * * *
(1) * * *
Where: * * *
EF = Fuel-specific default emission factor for CH4 or
N2O, from table C-2 to this subpart (kg CH4 or
N2O per mmBtu), except for natural gas-fired
reciprocating internal combustion engines and gas turbines at
facilities subject to subpart W of this part, which must use a
CH4 emission factor determined in accordance with Sec.
98.233(z)(4).
* * * * *
(i) * * *
Where: * * *
EF = Fuel-specific default emission factor for CH4 or
N2O, from table C-2 to this subpart (kg CH4 or
N2O per mmBtu), except for natural gas-fired
reciprocating internal combustion engines and gas turbines at
facilities subject to subpart W of this part, which must use a
CH4 emission factor determined in accordance with Sec.
98.233(z)(4).
* * * * *
(ii) * * *
Where: * * *
EF = Fuel-specific default emission factor for CH4 or
N2O, from table C-2 to this subpart (kg CH4 or
N2O per mmBtu), except for natural gas-fired
reciprocating internal combustion engines and gas turbines at
facilities subject to subpart W of this part, which must use a
CH4 emission factor determined in accordance with Sec.
98.233(z)(4).
* * * * *
(2) * * *
Where: * * *
EF = Fuel-specific default emission factor for CH4 or
N2O, from table C-2 to this subpart (kg CH4 or
N2O per mmBtu), except for natural gas-fired
reciprocating internal combustion engines and gas turbines at
facilities subject to subpart W of this part, which must use a
CH4 emission factor determined in accordance with Sec.
98.233(z)(4).
* * * * *
(4) * * *
Where: * * *
EF = Fuel-specific default emission factor for CH4 or
N2O, from table C-2 to this subpart (kg CH4 or
N2O per mmBtu), except for natural gas-fired
reciprocating internal combustion engines and gas turbines at
facilities subject to subpart W of this part, which must use a
CH4 emission factor determined in accordance with Sec.
98.233(z)(4).
* * * * *
0
8. Amend Sec. 98.36 by adding paragraphs (b)(12), (c)(1)(xii), and
(c)(3)(xi) to read as follows:
Sec. 98.36 Data reporting requirements.
* * * * *
(b) * * *
(12) For natural gas-fired reciprocating internal combustion
engines or gas turbines at facilities subject to subpart W of this
part, which must use a CH4 emission factor determined in
accordance with Sec. 98.233(z)(4), you must also report:
(i) Type of equipment (i.e., two-stroke lean-burn reciprocating
internal combustion engine, four-stroke lean-burn reciprocating
internal combustion engine, four-stroke rich-burn reciprocating
internal combustion engine, or gas turbine).
(ii) Method by which the CH4 emission factor was
determined: performance test, manufacturer data, or default emission
factor.
(iii) Value of the CH4 emission factor.
(c) * * *
(1) * * *
(xii) For natural gas-fired reciprocating internal combustion
engines or gas turbines at facilities subject to subpart W of this
part, which must use a CH4 emission factor determined in
accordance with Sec. 98.233(z)(4), you must report the equipment type
(i.e., two-stroke lean-burn reciprocating internal combustion engine,
four-stroke lean-burn reciprocating internal combustion engine, four-
stroke rich-burn reciprocating internal combustion engine, and gas
turbine), the method by which the CH4 emission factor was
determined (i.e., performance test, manufacturer data, or default
emission factor), and the average value of the CH4 emission
factor.
* * * * *
(3) * * *
(xi) For natural gas-fired reciprocating internal combustion
engines or gas turbines at facilities subject to subpart W of this
part, which must use a CH4 emission factor determined in
accordance with Sec. 98.233(z)(4), you must report the equipment type
(i.e., two-stroke lean-burn reciprocating internal combustion engine,
four-stroke lean-burn reciprocating internal combustion engine, four-
stroke rich-burn reciprocating internal combustion engine, and gas
turbine) the method by which the CH4 emission factor was
determined (i.e., performance test, manufacturer data, or default
emission factor), and the average value of the CH4 emission
factor.
* * * * *
0
9. Amend table C-2 to subpart C of part 98 by revising the entry
``Natural Gas'' to read as follows:
[[Page 42221]]
Table C-2 to Subpart C of Part 98--Default CH4 and N2O Emission Factors
for Various Types of Fuel
------------------------------------------------------------------------
Default CH4 Default N2O
Fuel type emission factor (kg emission factor (kg
CH4/mmBtu) N2O/mmBtu)
------------------------------------------------------------------------
* * * * * * *
Natural Gas\1\................ 1.0 x 10-\03\ 1.0 x 10-\04\
* * * * * * * * * *
------------------------------------------------------------------------
\1\ Reporters subject to subpart W of this part may only use the default
CH4 emission factor for natural gas-fired combustion units that are
not reciprocating internal combustion engines or gas turbines. For
natural gas-fired reciprocating internal combustion engines or gas
turbines, at facilities subject to subpart W of this part, reporters
must use a CH4 emission factor determined in accordance with Sec.
98.233(z)(4).
* * * * *
Subpart W--Petroleum and Natural Gas Systems
0
10. Amend Sec. 98.230 by revising paragraphs (a)(2), (3), and (9) to
read as follows:
Sec. 98.230 Definition of the source category.
(a) * * *
(2) Onshore petroleum and natural gas production. Onshore petroleum
and natural gas production means all equipment on a single well-pad or
associated with a single well-pad (including but not limited to
compressors, generators, dehydrators, storage vessels, engines,
boilers, heaters, flares, separation and processing equipment, and
portable non-self-propelled equipment, which includes well drilling and
completion equipment, workover equipment, and leased, rented or
contracted equipment) used in the production, extraction, recovery,
lifting, stabilization, separation or treating of petroleum and/or
natural gas (including condensate). This equipment also includes
associated storage or measurement vessels, all petroleum and natural
gas production equipment located on islands, artificial islands, or
structures connected by a causeway to land, an island, or an artificial
island. Onshore petroleum and natural gas production also means all
equipment on or associated with a single enhanced oil recovery (EOR)
well-pad using CO2 or natural gas injection.
(3) Onshore natural gas processing. Onshore natural gas processing
means the forced extraction of natural gas liquids (NGLs) from field
gas, fractionation of mixed NGLs to natural gas products, or both.
Natural gas processing does not include a Joule-Thomson valve, a dew
point depression valve, or an isolated or standalone Joule-Thomson
skid. This segment also includes all residue gas compression equipment
owned or operated by the natural gas processing plant.
* * * * *
(9) Onshore petroleum and natural gas gathering and boosting.
Onshore petroleum and natural gas gathering and boosting means
gathering pipelines and other equipment used to collect petroleum and/
or natural gas from onshore production gas or oil wells and used to
compress, dehydrate, sweeten, or transport the petroleum and/or natural
gas to a downstream endpoint, typically a natural gas processing
facility, a natural gas transmission pipeline or a natural gas
distribution pipeline. Gathering and boosting equipment includes, but
is not limited to gathering pipelines, separators, compressors, acid
gas removal units, dehydrators, pneumatic devices/pumps, storage
vessels, engines, boilers, heaters, and flares. Gathering and boosting
equipment does not include equipment reported under any other industry
segment defined in this section. Gathering pipelines operating on a
vacuum and gathering pipelines with a GOR less than 300 standard cubic
feet per stock tank barrel (scf/STB) are not included in this industry
segment (oil here refers to hydrocarbon liquids of all API gravities).
* * * * *
0
11. Amend Sec. 98.232 by:
0
a. Revising paragraphs (a) and (b);
0
b. Adding paragraph (c)(2);
0
c. Revising paragraphs (c)(10), (17), and (21);
0
d. Adding paragraphs (c)(23) through (25);
0
e. Revising paragraphs (d)(5) and (7);
0
f. Adding paragraphs (d)(8) through (11);
0
g. Revising paragraphs (e)(3) and (8);
0
h. Adding paragraphs (e)(9) through (11);
0
i. Revising paragraphs (f)(6) and (8);
0
j. Adding paragraphs (f)(9) through (13);
0
k. Revising paragraphs (g)(6) and (7);
0
l. Adding paragraphs (g)(8) through (11);
0
m. Revising paragraphs (h)(7) and (8);
0
n. Adding paragraphs (h)(9) through (11) and (i)(8) through (11);
0
o. Revising paragraphs (j)(3), (6), and (10);
0
p. Adding paragraphs (j)(13) and (14); and
0
q. Revising paragraph (m).
The revisions and additions read as follows:
Sec. 98.232 GHGs to report.
(a) You must report CO2, CH4, and
N2O emissions from each industry segment specified in
paragraphs (b) through (j) and (m) of this section, CO2,
CH4, and N2O emissions from each flare as
specified in paragraphs (b) through (j) of this section, and stationary
and portable combustion emissions as applicable as specified in
paragraph (k) of this section. You must also report the information
specified in paragraph (l) of this section, as applicable.
(b) For offshore petroleum and natural gas production, report
CO2, CH4, and N2O emissions from the
following sources. Offshore platforms do not need to report emissions
from portable equipment.
(1) Equipment leaks (i.e., fugitives), vented emission, and flare
emission source types as identified by Bureau of Ocean Energy
Management (BOEM) in compliance with 30 CFR 550.302 through 304.
(2) Other large release events.
(c) * * *
(2) Blowdown vent stacks.
* * * * *
(10) Hydrocarbon liquids and produced water storage tank emissions.
* * * * *
(17) Acid gas removal unit vents and nitrogen removal unit vents.
* * * * *
(21) Equipment leaks listed in paragraph (c)(21)(i) or (ii) of this
section, as applicable:
(i) Equipment leaks from components including valves, connectors,
open ended lines, pressure relief valves, pumps, flanges, and other
components (such as instruments, loading arms,
[[Page 42222]]
stuffing boxes, compressor seals, dump lever arms, and breather caps,
but does not include components listed in paragraph (c)(11) or (19) of
this section, and it does not include thief hatches or other openings
on a storage vessel).
(ii) Equipment leaks from major equipment including wellheads,
separators, meters/piping, compressors, dehydrators, heaters, and
storage vessels.
* * * * *
(23) Other large release events.
(24) Drilling mud degassing.
(25) Crankcase vents.
(d) * * *
(5) Acid gas removal unit vents and nitrogen removal unit vents.
* * * * *
(7) Equipment leaks from valves, connectors, open ended lines,
pressure relief valves, and meters, and equipment leaks from all other
components in gas service (not including thief hatches or other
openings on storage vessels) that either are subject to equipment leak
standards for onshore natural gas processing plants in Sec. 60.5400b
or Sec. 60.5401b of this chapter, or an applicable approved state plan
or applicable Federal plan in part 62 of this chapter or that you elect
to survey using a leak detection method described in Sec. 98.234(a).
(8) Natural gas pneumatic device venting.
(9) Other large release events.
(10) Hydrocarbon liquids and produced water storage tank emissions.
(11) Crankcase vents.
(e) * * *
(3) Condensate storage tanks.
* * * * *
(8) Equipment leaks from all other components that are not listed
in paragraph (e)(1), (2), or (7) of this section and either are subject
to the well site or compressor station fugitive emissions standards in
Sec. 60.5397a of this chapter, the fugitive emissions standards for
well sites, centralized production facilities, and compressor stations
in Sec. 60.5397b or Sec. 60.5398b of this chapter, or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter, or that you elect to survey using a leak detection method
described in Sec. 98.234(a). The other components subject to this
paragraph (e)(8) also do not include thief hatches or other openings on
a storage vessel.
(9) Other large release events.
(10) Dehydrator vents.
(11) Crankcase vents.
(f) * * *
(6) Equipment leaks from all other components that are associated
with storage stations, are not listed in paragraph (f)(1), (2), or (5)
of this section, and either are subject to the well site or compressor
station fugitive emissions standards in Sec. 60.5397a of this chapter,
the fugitive emissions standards for well sites, centralized production
facilities, and compressor stations in Sec. 60.5397b or Sec. 60.5398b
of this chapter, or an applicable approved state plan or applicable
Federal plan in part 62 of this chapter or that you elect to survey
using a leak detection method described in Sec. 98.234(a). The other
components subject to this paragraph (f)(6) do not include thief
hatches or other openings on a storage vessel.
* * * * *
(8) Equipment leaks from all other components that are associated
with storage wellheads, are not listed in paragraph (f)(1), (2), or (7)
of this section, and either are subject to the well site or compressor
station fugitive emissions standards in Sec. 60.5397a of this chapter,
the fugitive emissions standards for well sites, centralized production
facilities, and compressor stations in Sec. 60.5397b or Sec. 60.5398b
of this chapter, or an applicable approved state plan or applicable
Federal plan in part 62 of this chapter or that you elect to survey
using a leak detection method described in Sec. 98.234(a).
(9) Other large release events.
(10) Dehydrator vents.
(11) Blowdown vent stacks.
(12) Condensate storage tanks.
(13) Crankcase vents.
(g) * * *
(6) Equipment leaks from all components in gas service that are
associated with a vapor recovery compressor, are not listed in
paragraph (g)(1) or (2) of this section, and either are subject to the
well site or compressor station fugitive emissions standards in Sec.
60.5397a of this chapter, the fugitive emissions standards for well
sites, centralized production facilities, and compressor stations in
Sec. 60.5397b or Sec. 60.5398b of this chapter, or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter or that you elect to survey using a leak detection method
described in Sec. 98.234(a).
(7) Equipment leaks from all components in gas service that are not
associated with a vapor recovery compressor, are not listed in
paragraph (g)(1) or (2) of this section, and either are subject to the
well site or compressor station fugitive emissions standards in Sec.
60.5397a of this chapter, the fugitive emissions standards for well
sites, centralized production facilities, and compressor stations in
Sec. 60.5397b or Sec. 60.5398b of this chapter, or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter or that you elect to survey using a leak detection method
described in Sec. 98.234(a).
(8) Other large release events.
(9) Blowdown vent stacks.
(10) Acid gas removal unit vents and nitrogen removal unit vents.
(11) Crankcase vents.
(h) * * *
(7) Equipment leaks from all components in gas service that are
associated with a vapor recovery compressor, are not listed in
paragraph (h)(1) or (2) of this section, and either are subject to the
well site or compressor station fugitive emissions standards in Sec.
60.5397a of this chapter, the fugitive emissions standards for well
sites, centralized production facilities, and compressor stations in
Sec. 60.5397b or Sec. 60.5398b of this chapter, or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter or that you elect to survey using a leak detection method
described in Sec. 98.234(a).
(8) Equipment leaks from all components in gas service that are not
associated with a vapor recovery compressor, are not listed in
paragraph (h)(1) or (2) of this section, and either are subject to the
well site or compressor station fugitive emissions standards in Sec.
60.5397a of this chapter, the fugitive emissions standards for well
sites, centralized production facilities, and compressor stations in
Sec. 60.5397b or Sec. 60.5398b of this chapter, or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter or that you elect to survey using a leak detection method
described in Sec. 98.234(a).
(9) Acid gas removal unit vents and nitrogen removal unit vents.
(10) Other large release events.
(11) Crankcase vents.
(i) * * *
(8) Other large release events.
(9) Blowdown vent stacks.
(10) Natural gas pneumatic device venting.
(11) Crankcase vents.
(j) * * *
(3) Acid gas removal unit vents and nitrogen removal unit vents.
* * * * *
(6) Hydrocarbon liquids and produced water storage tank emissions.
* * * * *
(10) Equipment leaks listed in paragraph (j)(10)(i) or (ii) of this
section, as applicable:
(i) Equipment leaks from components including valves, connectors,
open ended lines, pressure relief valves,
[[Page 42223]]
pumps, flanges, and other components (such as instruments, loading
arms, stuffing boxes, compressor seals, dump lever arms, and breather
caps, but does not include components in paragraph (j)(8) or (9) of
this section, and it does not include thief hatches or other openings
on a storage vessel).
(ii) Equipment leaks from major equipment including wellheads,
separators, meters/piping, compressors, dehydrators, heaters, and
storage vessels.
* * * * *
(13) Other large release events.
(14) Crankcase vents.
* * * * *
(m) For onshore natural gas transmission pipeline, report
CO2, CH4, and N2O emissions from the
following source types:
(1) Blowdown vent stacks.
(2) Other large release events.
(3) Equipment leaks listed in paragraph (m)(3)(i) or (ii) of this
section, as applicable:
(i) Equipment leaks at transmission company interconnect metering-
regulating stations.
(ii) Equipment leaks from valves, connectors, open ended lines,
pressure relief valves, and meters at transmission company interconnect
metering-regulating stations.
(4) Equipment leaks listed in paragraph (m)(4)(i) or (ii) of this
section, as applicable:
(i) Equipment leaks at farm tap and/or direct sale metering-
regulating stations.
(ii) Equipment leaks from valves, connectors, open ended lines,
pressure relief valves, and meters at farm tap and/or direct sale
metering-regulating stations.
(5) Transmission pipeline equipment leaks.
0
12. Effective July 15, 2024, amend Sec. 98.233 by:
0
a. Revising paragraphs (a), (c), the first sentence of paragraph
(d)(2), and (d)(4) introductory text;
0
b. Adding paragraph (d)(12);
0
c. Revising paragraphs (e) introductory text, (e)(1) introductory text,
and (e)(2);
0
d. Revising paragraph (g) introductory text and (g)(1)(i);
0
e. Revising parameter ``FRi,p'' of equation W-12B in
paragraph (g)(1)(iv);
0
f. Revising paragraph (i)(2)(i);
0
g. Revising paragraphs (j) introductory text, and (j)(2) introductory
text and (j)(3);
0
h. Revising paragraphs (m)(1) through (3), (o)(10), (p)(10), (q)
introductory text, (q)(1), and (q)(2) introductory text;
0
i. Adding paragraphs (q)(3) and (q)(4);
0
j. Revising paragraphs (s)(1) and (2) and (z)(1) introductory text;
0
k. Adding paragraph (z)(1)(iii); and
0
l. Revising paragraphs (z)(2) introductory text and (z)(2)(ii).
The revisions and additions read as follows:
Sec. 98.233 Calculating GHG emissions.
* * * * *
(a) Natural gas pneumatic device venting. Calculate CH4
and CO2 emissions from natural gas pneumatic device venting
using the applicable provisions as specified in this paragraph (a) of
this section. If you have a continuous flow meter on the natural gas
supply line dedicated to any one or combination of natural gas
pneumatic devices or natural gas driven pneumatic pumps vented directly
to the atmosphere for any portion of the year, you may use the method
specified in paragraph (a)(1) of this section to calculate
CH4 and CO2 emissions from those devices. For
natural gas pneumatic devices for which you do not elect to use
Calculation Method 1, use the applicable methods specified in
paragraphs (a)(2) through (7) of this section to calculate
CH4 and CO2 emissions. All references to natural
gas pneumatic devices for Calculation Method 1 in this paragraph (a)
also apply to combinations of natural gas pneumatic devices and natural
gas driven pneumatic pumps that are served by a common natural gas
supply line. For Reporting Year 2024, you may use data collected
anytime during the calendar year for any of the applicable calculation
methods, provided that the data were collected in accordance with and
meet the criteria of the applicable paragraphs (a)(1) through (4) of
this section.
(1) Calculation Method 1. If you have or elect to install a
continuous flow meter that is capable of meeting the requirements of
Sec. 98.234(b) on the natural gas supply line dedicated to any one or
combination of natural gas pneumatic devices and natural gas driven
pneumatic pumps that are vented directly to the atmosphere, you may use
the applicable methods specified in paragraphs (a)(1)(i) through (iv)
of this section to calculate CH4 and CO2
emissions from those devices.
(i) For volumetric flow monitors:
(A) Determine the cumulative annual volumetric flow, in standard
cubic feet, as measured by the flow monitor in the reporting year. If
all natural gas pneumatic devices supplied by the measured natural gas
supply line are routed to the atmosphere for only a portion of the year
and are routed to a flare, combustion, or vapor recovery system for the
remaining portion of the year, determine the cumulative annual
volumetric flow considering only those times when one or more of the
natural gas pneumatic devices were vented directly to the atmosphere.
If the flow meter was installed during the year, calculate the total
volumetric flow for the year based on the measured volumetric flow
times the total hours in the calendar year the devices were in service
(i.e., supplied with natural gas) divided by the number of hours the
devices were in service (i.e., supplied with natural gas) and the
volumetric flow was being measured.
(B) Convert the natural gas volumetric flow from paragraph
(a)(1)(i)(A) of this section to CH4 and CO2
volumetric emissions following the provisions in paragraph (u) of this
section.
(C) Convert the CH4 and CO2 volumetric
emissions from paragraph (a)(1)(i)(B) of this section to CH4
and CO2 mass emissions using calculations in paragraph (v)
of this section.
(ii) For mass flow monitors:
(A) Determine the cumulative annual mass flow, in metric tons, as
measured by the flow monitor in the reporting year. If all natural gas
pneumatic devices supplied by the measured natural gas supply line are
vented directly to the atmosphere for only a portion of the year and
are routed to a flare, combustion, or vapor recovery system for the
remaining portion of the year, determine the cumulative annual mass
flow considering only those times when one or more of the natural gas
pneumatic devices were vented directly to the atmosphere. If the flow
meter was installed during the year, calculate the total mass flow for
the year based on the measured mass flow times the total hours in the
calendar year the devices were in service (i.e., supplied with natural
gas) divided by the number of hours the devices were in service (i.e.,
supplied with natural gas) and the mass flow was being measured.
(B) Convert the cumulative mass flow from paragraph (a)(1)(ii)(A)
of this section to CH4 and CO2 mass emissions by
multiplying by the mass fraction of CH4 and CO2
in the supplied natural gas. You must follow the provisions in
paragraph (u) of this section for determining the mole fraction of
CH4 and CO2 and use molecular weights of 16 kg/
kg-mol and 44 kg/kg-mol for CH4 and CO2,
respectively. You may assume unspecified components have an average
molecular weight of 28 kg/kg-mol.
(iii) If the flow meter on the natural gas supply line serves both
natural gas pneumatic devices and natural gas driven pneumatic pumps,
disaggregate
[[Page 42224]]
the total measured amount of natural gas to pneumatic devices and
natural gas driven pneumatic pumps based on engineering calculations
and best available data.
(iv) The flow meter must be operated and calibrated according to
the methods set forth in Sec. 98.234(b).
(2) Calculation Method 2. Except as provided in paragraph (a)(1) of
this section, you may elect to measure the volumetric flow rate of each
natural gas pneumatic device vent that vents directly to the atmosphere
at your well-pad site, gathering and boosting site, or facility, as
applicable, as specified in paragraphs (a)(2)(i) through (ix) of this
section. You must exclude the counts of devices measured according to
paragraph (a)(1) of this section from the counts of devices to be
measured or for which emissions are calculated according to the
requirements in this paragraph (a)(2).
(i) For facilities in the onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and boosting
industry segments, you may elect to measure your pneumatic devices
according to this Calculation Method 2 for some well-pad sites or
gathering and boosting sites and use other methods for other sites.
When you elect to measure the emissions from natural gas pneumatic
devices according to this Calculation Method 2 at a well-pad site or
gathering and boosting site, you must measure all natural gas pneumatic
devices that are vented directly to the atmosphere at the well-pad site
or gathering and boosting site during the same calendar year and you
must measure and calculate emissions according to the provisions in
paragraphs (a)(2)(iii) through (viii) of this section.
(ii) For facilities in the onshore natural gas processing, onshore
natural gas transmission compression, underground natural gas storage,
or natural gas distribution industry segments electing to use this
Calculation Method 2, you must measure all natural gas pneumatic
devices vented directly to the atmosphere at your facility each year
or, if your facility has 26 or more pneumatic devices, over multiple
years, not to exceed the number of years as specified in paragraphs
(a)(2)(ii)(A) through (D) of this section. If you elect to measure your
pneumatic devices over multiple years, you must measure approximately
the same number of devices each year. You must measure and calculate
emissions for natural gas pneumatic devices at your facility according
to the provisions in paragraphs (a)(2)(iii) through (ix), as
applicable.
(A) If your facility has at least 26 but not more than 50 natural
gas pneumatic devices vented directly to the atmosphere, the maximum
number of years to measure all devices at your facility is 2 years.
(B) If your facility has at least 51 but not more than 75 natural
gas pneumatic devices vented directly to the atmosphere, the maximum
number of years to measure all devices at your facility is 3 years.
(C) If your facility has at least 76 but not more than 100 natural
gas pneumatic devices vented directly to the atmosphere, the maximum
number of years to measure all devices at your facility is 4 years.
(D) If your facility has 101 or more natural gas pneumatic devices
vented directly to the atmosphere, the maximum number of years to
measure all devices at your facility is 5 years.
(iii) For all industry segments, determine the volumetric flow rate
of each natural gas pneumatic device vent (in standard cubic feet per
hour) using one of the methods specified in Sec. 98.234(b) through
(d), as appropriate, according to the requirements specified in
paragraphs (a)(2)(iii)(A) through (E) of this section. You must measure
the emissions under conditions representative of normal operations,
which excludes periods immediately after conducting maintenance on the
device or manually actuating the device.
(A) If you use a temporary meter, such as a vane anemometer,
according to the methods set forth in Sec. 98.234(b) or a high volume
sampler according to methods set forth in Sec. 98.234(d), you must
measure the emissions from each device for a minimum of 15 minutes
while the device is in service (i.e., supplied with natural gas),
except for natural gas pneumatic isolation valve actuators. For natural
gas pneumatic isolation valve actuators, you must measure the emissions
from each device for a minimum of 5 minutes while the device is in
service (i.e., supplied with natural gas). If there is no measurable
flow from the natural gas pneumatic device after the minimum sampling
period, you can discontinue monitoring and follow the applicable
methods in paragraph (a)(2)(v) of this section.
(B) If you use calibrated bagging, follow the methods set forth in
Sec. 98.234(c) except you need only fill one bag to have a valid
measurement. You must collect sample for a minimum of 5 minutes for
natural gas pneumatic isolation valve actuators or 15 minutes for other
natural gas pneumatic devices. If no gas is collected in the calibrated
bag during the minimum sampling period, you can discontinue monitoring
and follow the applicable methods in paragraph (a)(2)(v) of this
section. If gas is collected in the bag during the minimum sampling
period, you must either continue sampling until you fill the calibrated
bag or you may elect to remeasure the vent according to paragraph
(a)(2)(iii)(A) of this section.
(C) You do not need to use the same measurement method for each
natural gas pneumatic device vent.
(D) If the measurement method selected measures the volumetric flow
rate in actual cubic feet, convert the measured flow to standard cubic
feet following the methods specified in paragraph (t)(1) of this
section.
(E) If there is measurable flow from the device vent, calculate the
volumetric flow rate of each natural gas pneumatic device vent (in
standard cubic feet per hour) by dividing the cumulative volume of
natural gas measured during the measurement period (in standard cubic
feet) by the duration of the measurement (in hours).
(iv) For all industry segments, if there is measurable flow from
the device vent, calculate the volume of natural gas emitted from each
natural gas pneumatic device vent as the product of the natural gas
flow rate measured in paragraph (a)(2)(iii) of this section and the
number of hours the pneumatic device was in service (i.e., supplied
with natural gas) in the calendar year.
(v) For all industry segments, if there is no measurable flow from
the device vent, estimate the emissions from the device according to
the methods in paragraphs (a)(2)(v)(A) through (C) of this section, as
applicable.
(A) For continuous high bleed pneumatic devices:
(1) Confirm that the device is in-service. If not, remeasure the
device according to paragraph (a)(2)(iii) of this section at a time the
device is in-service and calculate natural gas emissions from the
device according to paragraph (a)(2)(iv) of this section.
(2) Confirm that the device is correctly characterized as a
continuous high bleed pneumatic device according to the provisions in
paragraph (a)(7) of this section. If the device type was
mischaracterized, recharacterize the device type and use the
appropriate methods in paragraph (a)(2)(v)(B) or (C) of this section,
as applicable.
(3) Upon confirmation of the items in paragraphs (a)(2)(v)(A)(1)
and (2) of this section, remeasure the device vent using a different
measurement method specified in Sec. 98.234(b) through (d) or longer
monitoring duration until there is a measurable flow from the device
and calculate the natural gas emissions from
[[Page 42225]]
the device according to paragraph (a)(2)(iv) of this section.
(B) For continuous low bleed pneumatic devices:
(1) Confirm that the device is in-service. If not, remeasure the
device according to paragraph (a)(2)(iii) of this section at a time the
device is in-service and calculate natural gas emissions from the
device according to paragraph (a)(2)(iv) of this section.
(2) Determine natural gas bleed rate (in standard cubic feet per
hour) at the supply pressure used for the pneumatic device based on the
manufacturer's steady state natural gas bleed rate reported for the
device. If the steady state bleed rate is reported in terms of air
consumption, multiply the air consumption rate by 1.29 to calculate the
steady state natural gas bleed rate. If a steady state bleed rate is
not reported, follow the requirements in paragraph (a)(2)(v)(B)(4) of
this section.
(3) Calculate the volume of natural gas emitted from the natural
gas pneumatic device vent as the product of the natural gas steady
state bleed rate determined in paragraph (a)(2)(v)(B)(2) of this
section and number of hours the pneumatic device was in service (i.e.,
supplied with natural gas) in the calendar year.
(4) If a steady state bleed rate is not reported, reassess whether
the device is correctly characterized as a continuous low bleed
pneumatic device according to the provisions in paragraph (a)(7) of
this section. If the device is confirmed to be a continuous low bleed
pneumatic device, you must remeasure the device vent using a different
measurement method specified in Sec. 98.234(b) through (d) or longer
monitoring duration until there is a measurable flow from the device
and calculate natural gas emissions from the device according to
paragraph (a)(2)(iv) of this section. If the device type was
mischaracterized, recharacterize the device type and use the
appropriate methods in paragraph (a)(2)(v)(A) or (C) of this section,
as applicable.
(C) For intermittent bleed pneumatic devices:
(1) Confirm that the device is in-service. If not, remeasure the
device according to paragraph (a)(2)(iii) of this section at a time the
device is in-service and calculate natural gas emissions according to
paragraph (a)(2)(iv) of this section. For devices confirmed to be in-
service during the measurement period, calculate natural gas emissions
according to paragraphs (a)(2)(v)(C)(2) through (5) of this section.
(2) Calculate the volume of the controller, tubing and actuator (in
actual cubic feet) based on the device and tubing size.
(3) Sum the volumes in paragraph (a)(2)(v)(C)(2) of this section
and convert the volume to standard cubic feet following the methods
specified in paragraph (t)(1) of this section based on the natural gas
supply pressure.
(4) Estimate the number of actuations during the year based on
company records, if available, or best engineering estimates. For
isolation valve actuators, you may multiply the number of valve
closures during the year by 2 (one actuation to close the valve; one
actuation to open the valve).
(5) Calculate the volume of natural gas emitted from the natural
gas pneumatic device vent as the product of the per actuation volume in
standard cubic feet determined in paragraph (a)(2)(v)(C)(3) of this
section, the number of actuations during the year as determined in
paragraph (a)(2)(v)(C)(4) of this section, and the relay correction
factor. Use 1 for the relay correction factor if there is no relay; use
3 for the relay correction factor if there is a relay.
(vi) For each pneumatic device, convert the volumetric emissions of
natural gas at standard conditions determined in paragraph (a)(2)(iv)
or (v) of this section, as applicable, to CO2 and
CH4 volumetric emissions at standard conditions using the
methods specified in paragraph (u) of this section.
(vii) For each pneumatic device, convert the GHG volumetric
emissions at standard conditions determined in paragraph (a)(2)(vi) of
this section to GHG mass emissions using the methods specified in
paragraph (v) of this section.
(viii) Sum the CO2 and CH4 mass emissions
determined in paragraph (a)(2)(vii) of this section separately for each
type of natural gas pneumatic device (continuous high bleed, continuous
low bleed, and intermittent bleed).
(ix) For facilities in the onshore natural gas processing, onshore
natural gas transmission compression, underground natural gas storage,
or natural gas distribution industry segments, if you chose to conduct
natural gas pneumatic device measurements over multiple years, ``n,''
according to paragraph (a)(2)(ii) of this section, then you must
calculate the emissions from all pneumatic devices at your facility as
specified in paragraph (a)(2)(ix)(A) through (E) of this section.
(A) Use the emissions calculated in (a)(2)(viii) of this section
for the devices measured during the reporting year.
(B) Calculate the whole gas emission factor for each type of
pneumatic device at the facility using equation W-1A to this section
and all available data from the current year and the previous years in
your monitoring cycle (n-1 years) for which natural gas pneumatic
device vent measurements were made according to Calculation Method 2 in
paragraph (a)(2) of this section (e.g., if your monitoring cycle is 3
years, then use measured data from the current year and the two
previous years). This emission factor must be updated annually.
[GRAPHIC] [TIFF OMITTED] TR14MY24.024
Where:
EFt = Whole gas population emission factor for natural
gas pneumatic device vents of type ``t'' (continuous high bleed,
continuous low bleed, intermittent bleed), in standard cubic feet
per hour per device.
MTs,t,y = Volumetric whole gas emissions rate measurement
at standard (``s'') conditions from component type ``t'' during year
``y'' in standard cubic feet per hour, as calculated in paragraph
(a)(2)(iii) [if there was measurable flow from the device vent],
(a)(2)(v)(B)(2), or (a)(2)(v)(C)(6) of this section, as applicable.
Countt,y = Count of natural gas pneumatic device vents of
type ``t'' measured according to Calculation Method 2 in year ``y.''
n = Number of years of data to include in the emission factor
calculation according to the number of years used to monitor all
natural gas pneumatic device vents at the facility.
(C) Calculate CH4 and CO2 volumetric
emissions from continuous high bleed, continuous low bleed, and
intermittent bleed natural gas pneumatic devices that were not measured
during the reporting year using equation W-1B to this section.
[[Page 42226]]
[GRAPHIC] [TIFF OMITTED] TR14MY24.025
Where:
Es,i = Annual total volumetric GHG emissions at standard
conditions in standard cubic feet per year from natural gas
pneumatic device vents, of types ``t'' (continuous high bleed,
continuous low bleed, intermittent bleed), for GHGi.
Countt = Total number of natural gas pneumatic devices of
type ``t'' (continuous high bleed, continuous low bleed,
intermittent bleed) as determined in paragraphs (a)(5) through (7)
of this section that vent directly to the atmosphere and that were
not directly measured according to the requirements in paragraph
(a)(1) or (a)(2)(iii) of this section.
EFt = Population emission factors for natural gas
pneumatic device vents (in standard cubic feet per hour per device)
of each type ``t'' (continuous high bleed, continuous low bleed,
intermittent bleed) as calculated using equation W-1A to this
section.
GHGi = Concentration of GHGi, CH4
or CO2, in produced natural gas or processed natural gas
for each facility as specified in paragraph (u)(2) of this section.
Tt = Average estimated number of hours in the operating
year the devices, of each type ``t'', were in service (i.e.,
supplied with natural gas) using engineering estimates based on best
available data. Default is 8,760 hours.
(D) Convert the volumetric emissions calculated using equation W-1B
to this section to CH4 and CO2 mass emissions
using the methods specified in paragraph (v) of this section.
(E) Sum the CH4 and CO2 mass emissions
calculated in paragraphs (a)(2)(ix)(A) and (D) of this section
separately for each type of pneumatic device (continuous high bleed,
continuous low bleed, intermittent bleed) to calculate the total
CH4 and CO2 mass emissions by device type for
Calculation Method 2.
(3) Calculation Method 3. For facilities in the onshore petroleum
and natural gas production and onshore petroleum and natural gas
gathering and boosting industry segments, you may elect to use the
applicable methods specified in paragraphs (a)(3)(i) through (iv) of
this section, as applicable, to calculate CH4 and
CO2 emissions from your natural gas pneumatic devices that
are vented directly to the atmosphere at your site except those that
are measured according to paragraph (a)(1) or (2) of this section. You
must exclude the counts of devices measured according to paragraph
(a)(1) of this section from the counts of devices to be monitored or
for which emissions are calculated according to the requirements in
this paragraph (a)(3). You may not use this Calculation Method 3 for
those well-pad sites or gathering and boosting sites for which you
elected to measure emissions according to paragraph (a)(2) of this
section.
(i) For continuous high bleed and continuous low bleed natural gas
pneumatic devices vented directly to the atmosphere, you must calculate
CH4 and CO2 volumetric emissions using either the
methods in paragraph (a)(3)(i)(A) or (B) of this section.
(A) Measure all continuous high bleed and continuous low bleed
pneumatic devices at your well-pad site or gathering and boosting site,
as applicable, according to the provisions in paragraphs (a)(2) of this
section.
(B) Use equation W-1B to this section, except use the appropriate
default whole gas population emission factors for natural gas pneumatic
device vents (in standard cubic feet per hour per device) of each type
``t'' (continuous high bleed and continuous low bleed) as listed in
table W-1A to this subpart.
(ii) For intermittent bleed pneumatic devices, monitor each
intermittent bleed pneumatic device at your well-pad site or gathering
and boosting site as specified in paragraphs (a)(3)(ii)(A) through (C)
of this section, as applicable.
(A) You must use one of the monitoring methods specified in Sec.
98.234(a)(1) through (3) except that the monitoring dwell time for each
device vent must be at least 2 minutes or until a malfunction is
identified, whichever is shorter. A device is considered malfunctioning
if any leak is observed when the device is not actuating or if a leak
is observed for more than 5 seconds, or the extended duration as
specified in paragraph (a)(3)(ii)(C) of this section if applicable,
during a device actuation. If you cannot tell when a device is
actuating, any observed leak from the device indicates a malfunctioning
device.
(B) If you elect to monitor emissions from natural gas pneumatic
devices at a well-pad site or gathering and boosting site according to
this Calculation Method 3, you must monitor all natural gas
intermittent bleed pneumatic devices that are vented directly to the
atmosphere at the well-pad site or gathering and boosting site during
the same calendar year. You must monitor the natural gas intermittent
bleed pneumatic devices under conditions representative of normal
operations, which excludes periods immediately after conducting
maintenance on the device or manually actuating the device.
(C) For certain throttling pneumatic devices or isolation valve
actuators on pipes greater than 5 inches in diameter, that may actuate
for more than 5 seconds under normal conditions, you may elect to
identify individual devices for which longer bleed periods may be
allowed as specified in paragraphs (a)(3)(ii)(C)(1) and (2) of this
section prior to monitoring these devices for the first time.
(1) You must identify the devices for which extended actuations are
considered normal operations. For each device identified, you must
determine the typical actuation time and maintain documentation and
rationale for the extended actuation duration value.
(2) You must clearly and permanently tag the device vent for each
natural gas pneumatic device that has an extended actuation duration.
The tag must include the device ID and the normal duration period (in
seconds) as determined and documented for the device as specified in
paragraph (a)(3)(ii)(C)(1) of this section.
(iii) For intermittent bleed pneumatic devices that are monitored
according to paragraph (a)(3)(ii) of this section during the reporting
year, you must calculate CH4 and CO2 volumetric
emissions from intermittent bleed natural gas pneumatic devices vented
directly to the atmosphere using equation W-1C to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.026
[[Page 42227]]
Where:
Ei = Annual total volumetric emissions of GHGi
from intermittent bleed natural gas pneumatic devices in standard
cubic feet.
GHGi = Concentration of GHGi, CH4
or CO2, in natural gas supplied to the intermittent bleed
natural gas pneumatic device as defined in paragraph (u)(2) of this
section.
x = Total number of intermittent bleed natural gas pneumatic devices
detected as malfunctioning in any pneumatic device monitoring survey
during the year. A component found as malfunctioning in two or more
surveys during the year is counted as one malfunctioning component.
K1 = Whole gas emission factor for malfunctioning
intermittent bleed natural gas pneumatic devices, in standard cubic
feet per hour per device. Use 24.1 for well-pad sites in the onshore
petroleum and natural gas production industry segment and use 16.1
for gathering and boosting sites in the onshore petroleum and
natural gas gathering and boosting industry segment.
Tmal,z = The total time the surveyed pneumatic device
``z'' was in service (i.e., supplied with natural gas) and assumed
to be malfunctioning, in hours. If one pneumatic device monitoring
survey is conducted in the calendar year, assume the device found
malfunctioning was malfunctioning for the entire calendar year. If
multiple pneumatic device monitoring surveys are conducted in the
calendar year, assume a device found malfunctioning in the first
survey was malfunctioning since the beginning of the year until the
date of the survey; assume a device found malfunctioning in the last
survey of the year was malfunctioning from the preceding survey
through the end of the year; assume a device found malfunctioning in
a survey between the first and last surveys of the year was
malfunctioning since the preceding survey until the date of the
survey; and sum times for all malfunctioning periods.
Tt,z = The total time the surveyed natural gas pneumatic
device ``z'' was in service (i.e., supplied with natural gas) during
the year. Default is 8,760 hours for non-leap years and 8,784 hours
for leap years.
K2 = Whole gas emission factor for properly operating
intermittent bleed natural gas pneumatic devices, in standard cubic
feet per hour per device. Use 0.3 for well-pad sites in the onshore
petroleum and natural gas production industry segment and use 2.8
for gathering and boosting sites in the onshore petroleum and
natural gas gathering and boosting industry segment.
Count = Total number of intermittent bleed natural gas pneumatic
devices that were never observed to be malfunctioning during any
monitoring survey during the year.
Tavg = The average time the intermittent bleed natural
gas pneumatic devices that were never observed to be malfunctioning
during any monitoring survey were in service (i.e., supplied with
natural gas) using engineering estimates based on best available
data. Default is 8,760 hours for non-leap years and 8,784 hours for
leap years.
(A) You must conduct at least one complete pneumatic device
monitoring survey in a calendar year. If you conduct multiple complete
pneumatic device monitoring surveys in a calendar year, you must use
the results from each complete pneumatic device monitoring survey when
calculating emissions using equation W-1C to this section.
(B) For the purposes of paragraph (a)(3)(iii)(A) of this section, a
complete monitoring survey is a survey of all intermittent bleed
natural gas pneumatic devices vented directly to the atmosphere at a
well-pad site for onshore petroleum and natural gas production
facilities (except those measured according to paragraph (a)(1) of this
section) or all intermittent bleed pneumatic devices vented directly to
the atmosphere at a gathering and boosting site for onshore petroleum
and natural gas gathering and boosting facilities (except those
measured according to paragraph (a)(1) of this section).
(iv) You must convert the CH4 and CO2
volumetric emissions as determined according to paragraphs (a)(3)(i)
and (iii) of this section and calculate both CO2 and
CH4 mass emissions using calculations in paragraph (v) of
this section for each type of natural gas pneumatic device (continuous
high bleed, continuous low bleed, and intermittent bleed).
(4) Calculation Method 4. You may elect to calculate CH4
and CO2 emissions from your natural gas pneumatic devices at
your facility using the methods specified in paragraphs (a)(4)(i) and
(ii) of this section except those that are measured according to
paragraphs (a)(1) through (3) of this section. You must exclude the
counts of devices measured according to paragraph (a)(1) of this
section from the counts of devices to be monitored or for which
emissions are calculated according to the requirements in this
paragraph (a)(4). You may not use this Calculation Method 4 for those
devices for which you elected to measure emissions according to
paragraph (a)(1), (2), or (3) of this section.
(i) You must calculate CH4 and CO2 volumetric
emissions using equation W-1B to this section, except use the
appropriate default whole gas population emission factors for natural
gas pneumatic device vents (in standard cubic feet per hour per device)
of each type ``t'' (continuous high bleed, continuous low bleed, and
intermittent bleed) listed in table W-1A to this subpart for onshore
petroleum and natural gas production and onshore petroleum and natural
gas gathering and boosting facilities, table W-3B to this subpart for
onshore natural gas transmission compression facilities, and table W-4B
to this subpart for underground natural gas storage facilities.
(ii) You must convert the CH4 and CO2
volumetric emissions as determined according to paragraphs (a)(4)(i) of
this section and calculate both CO2 and CH4 mass
emissions using calculations in paragraph (v) of this section for each
type of natural gas pneumatic device (continuous high bleed, continuous
low bleed, and intermittent bleed).
(5) Counts of natural gas pneumatic devices. For all industry
segments, determine ``Countt'' for equation W-1A, W-1B, or W-1C to this
section for each type of natural gas pneumatic device (continuous high
bleed, continuous low bleed, and intermittent bleed) by counting the
total number of devices at the well-pad site, gathering and boosting
site, or facility, as applicable, the number of devices that are vented
directly to the atmosphere and the number of those devices that were
measured or monitored during the reporting year, as applicable, except
as specified in paragraph (a)(6) of this section.
(6) Counts of onshore petroleum and natural gas production industry
segment or the onshore petroleum and natural gas gathering and boosting
natural gas pneumatic devices. For facilities in the onshore petroleum
and natural gas production industry segment or the onshore petroleum
and natural gas gathering and boosting industry segment, you have the
option in the first two consecutive calendar years to determine the
total number of natural gas pneumatic devices at the facility and the
number of devices that are vented directly to the atmosphere for each
type of natural gas pneumatic device (continuous high bleed, continuous
low bleed, and intermittent bleed), as applicable, using engineering
estimates based on best available data. Counts of natural gas pneumatic
devices measured or monitored during the reporting year must be made
based on actual counts.
(7) Type of natural gas pneumatic devices. For all industry
segments, determine the type of natural gas pneumatic device using
engineering estimates based on best available information.
* * * * *
(c) Natural gas driven pneumatic pump venting. Calculate
CH4 and CO2
[[Page 42228]]
emissions from natural gas driven pneumatic pumps as specified in
paragraph (c)(1), (2), or (3) of this section, as applicable. If you
have a continuous flow meter on the natural gas supply line that is
dedicated to any one or more natural gas driven pneumatic pumps, each
of which only vents directly to the atmosphere, you may use Calculation
Method 1 as specified in paragraph (c)(1) of this section to calculate
vented CH4 and CO2 emissions from those pumps.
You may use Calculation Method 1 for any portion of a year when all of
the pumps on the continuously measured natural gas supply line were
vented directly to atmosphere. For natural gas driven pneumatic pumps
for which you do not elect to use Calculation Method 1, use either the
method specified in paragraph (c)(2) or (3) of this section to
calculate CH4 and CO2 emissions; you may not use
Calculation Method 2 for some vented natural gas driven pneumatic pumps
and Calculation Method 3 for other natural gas driven pneumatic pumps.
All references to natural gas driven pneumatic pumps for Calculation
Method 1 in this paragraph (c) also apply to combinations of natural
gas pneumatic devices and natural gas driven pneumatic pumps that are
served by a common natural gas supply line. You do not have to
calculate emissions from natural gas driven pneumatic pumps covered in
paragraph (e) of this section under this paragraph (c). For Reporting
Year 2024, you may use data collected anytime during the calendar year
for any of the applicable calculation methods, provided that the data
were collected in accordance with and meet the criteria of the
applicable paragraphs (c)(1) through (3) of this section.
(1) Calculation Method 1. If you have or elect to install a
continuous flow meter that is capable of meeting the requirements of
Sec. 98.234(b) on a supply line to natural gas driven pneumatic pumps,
then for the period of the year when the natural gas supply line is
dedicated to any one or more natural gas driven pneumatic pumps, and
each of the pumps is vented directly to the atmosphere, you may use the
applicable methods specified in paragraphs (c)(1)(i) or (ii) of this
section to calculate vented CH4 and CO2 emissions
from those pumps.
(i) For volumetric flow monitors:
(A) Determine the cumulative annual volumetric flow, in standard
cubic feet, as measured by the flow monitor in the reporting year. If
the flow meter was installed during the year, calculate the total
volumetric flow for the year based on the measured volumetric flow
times the total hours in the calendar year in which at least one of the
pumps connected to the supply line was pumping liquid divided by the
number of hours in the year when at least one of pumps connected to the
supply line was pumping liquid and the volumetric flow was being
measured.
(B) Convert the natural gas volumetric flow from paragraph
(c)(1)(i)(A) of this section to CH4 and CO2
volumetric emissions following the provisions in paragraph (u) of this
section.
(C) Convert the CH4 and CO2 volumetric
emissions from paragraph (c)(1)(i)(B) of this section to CH4
and CO2 mass emissions using calculations in paragraph (v)
of this section.
(ii) For mass flow monitors:
(A) Determine the cumulative annual mass flow, in metric tons, as
measured by the flow monitor in the reporting year. If the flow meter
was installed during the year, calculate the total mass flow of vented
natural gas emissions for the year based on the measured mass flow
times the total hours in the calendar year in which at least one of the
pumps connected to the supply line was pumping liquid divided by the
number of hours in the year when at least one of pumps connected to the
supply line was pumping liquid and the mass flow was being measured.
(B) Convert the cumulative mass flow from paragraph (c)(1)(ii)(A)
of this section to CH4 and CO2 mass emissions by
multiplying by the mass fraction of CH4 and CO2
in the supplied natural gas. You must follow the provisions in
paragraph (u) of this section for determining the mole fraction of
CH4 and CO2 and use molecular weights of 16 kg/
kg-mol and 44 kg/kg-mol for CH4 and CO2,
respectively. You may assume unspecified components have an average
molecular weight of 28 kg/kg-mol.
(iii) If the supply line serves both natural gas pneumatic devices
and natural gas driven pneumatic pumps, disaggregate the total measured
amount of natural gas to natural gas pneumatic devices and natural gas
driven pneumatic pumps based on engineering calculations and best
available data.
(iv) The flow meter must be operated and calibrated according to
the methods set forth in Sec. 98.234(b).
(2) Calculation Method 2. Except as provided in paragraph (c)(1) of
this section, you may elect to measure the volumetric flow rate of each
natural gas driven pneumatic pump at your facility that vents directly
to the atmosphere as specified in paragraphs (c)(2)(i) through (vii) of
this section. You must exclude the counts of pumps measured according
to paragraph (c)(1) of this section from the counts of pumps to be
measured and for which emissions are calculated according to the
requirements in this paragraph (c)(2).
(i) Measure all natural gas driven pneumatic pumps at your facility
at least once every 5 years. If you elect to measure your pneumatic
pumps over multiple years, you must measure approximately the same
number of pumps each year. When you measure the emissions from natural
gas driven pneumatic pumps at a well-pad site or gathering and boosting
site, you must measure all pneumatic pumps that are vented directly to
the atmosphere at the well-pad site or gathering and boosting site
during the same calendar year.
(ii) Determine the volumetric flow rate of each natural gas driven
pneumatic pump (in standard cubic feet per hour) using one of the
methods specified in Sec. 98.234(b) through (d), as appropriate,
according to the requirements specified in paragraphs (c)(2)(ii)(A)
through (D) of this section. You must measure the emissions under
conditions representative of normal operations, which excludes periods
immediately after conducting maintenance on the pump.
(A) If you use a temporary meter, such as a vane anemometer,
according to the methods set forth in Sec. 98.234(b) or a high volume
sampler according to methods set forth in Sec. 98.234(d), you must
measure the emissions from each pump for a minimum of 5 minutes, during
a period when the pump is continuously pumping liquid.
(B) If you use calibrated bagging, follow the methods set forth in
Sec. 98.234(c), except under Sec. 98.234(c)(2), only one bag must be
filled to have a valid measurement. You must collect sample for a
minimum of 5 minutes, or until the bag is full, whichever is shorter,
during a period when the pump is continuously pumping liquid. If the
bag is not full after 5 minutes, you must either continue sampling
until you fill the calibrated bag or you may elect to remeasure the
vent according to paragraph (c)(2)(ii)(A) of this section.
(C) You do not need to use the same measurement method for each
natural gas driven pneumatic pump vent.
(D) If the measurement method selected measures the volumetric flow
rate in actual cubic feet, convert the measured flow to standard cubic
feet following the methods specified in paragraph (t)(1) of this
section. Convert the measured flow during the test period to standard
cubic feet per hour, as appropriate.
(iii) Calculate the volume of natural gas emitted from each natural
gas driven pneumatic pump vent as the product of
[[Page 42229]]
the natural gas emissions flow rate measured in paragraph (c)(2)(ii) of
this section and the number of hours that liquid was pumped by the
pneumatic pump in the calendar year.
(iv) For each pneumatic pump, convert the volumetric emissions of
natural gas at standard conditions determined in paragraph (c)(2)(iii)
of this section to CO2 and CH4 volumetric
emissions at standard conditions using the methods specified in
paragraph (u) of this section.
(v) For each pneumatic pump, convert the GHG volumetric emissions
at standard conditions determined in paragraph (c)(2)(iv) of this
section to GHG mass emissions using the methods specified in paragraph
(v) of this section.
(vi) Sum the CO2 and CH4 mass emissions
determined in paragraph (c)(2)(v) of this section.
(vii) If you chose to conduct natural gas pneumatic pump
measurements over multiple years, ``n,'' according to paragraph
(c)(2)(i) of this section, then you must calculate the emissions from
all pneumatic pumps at your facility as specified in paragraph
(c)(2)(vii)(A) through (D) of this section.
(A) Use the emissions calculated in paragraph (c)(2)(vi) of this
section for the pumps measured during the reporting year.
(B) Calculate the whole gas emission factor for pneumatic pumps at
the facility using equation W-2A to this section and all available data
from the current year and the previous years in your monitoring cycle
(n-1 years) for which natural gas pneumatic pump vent measurements were
made according to Calculation Method 2 in paragraph (c)(2) of this
section (e.g., if your monitoring cycle is 3 years, then use measured
data from the current year and the two previous years). This emission
factor must be updated annually.
[GRAPHIC] [TIFF OMITTED] TR14MY24.027
Where:
EFs = Whole gas population emission factor for natural
gas pneumatic pump vents, in standard cubic feet per hour per pump.
MTs,y = Volumetric whole gas emissions rate measurement
at standard (``s'') conditions during year ``y'' in standard cubic
feet per hour, as calculated in paragraph (c)(2)(iii) of this
section.
County = Count of natural gas driven pneumatic pump vents
measured according to Calculation Method 2 in year ``y.''
n = Number of years of data to include in the emission factor
calculation according to the number of years used to monitor all
natural gas pneumatic pump vents at the facility.
(C) Calculate CH4 and CO2 volumetric
emissions from natural gas driven pneumatic pumps that were not
measured during the reporting year using equation W-2B to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.028
Where:
Es,i = Annual total volumetric GHG emissions at standard
conditions in standard cubic feet per year from natural gas driven
pneumatic pump vents, for GHGi.
Count = Total number of natural gas driven pneumatic pumps that
vented directly to the atmosphere and that were not directly
measured according to the requirements in paragraphs (c)(1) or
(c)(2)(ii) of this section.
EFs = Population emission factors for natural gas driven
pneumatic pumps (in standard cubic feet per hour per pump) as
calculated using equation W-2A to this section.
GHGi = Concentration of GHGi, CH4
or CO2, in produced natural gas as defined in paragraph
(u)(2)(i) of this section.
T = Average estimated number of hours in the operating year the
pumps that vented directly to the atmosphere were pumping liquid
using engineering estimates based on best available data. Default is
8,760 hours for pumps that only vented directly to the atmosphere.
(D) Calculate both CH4 and CO2 mass emissions
from volumetric emissions calculated using equation W-2B to this
section using calculations in paragraph (v) of this section.
(E) Sum the CH4 and CO2 mass emissions
calculated in paragraphs (c)(2)(vii)(A) and (D) of this section to
calculate the total CH4 and CO2 mass emissions
for Calculation Method 2.
(3) Calculation Method 3. If you elect not to measure emissions as
specified in Calculation Method 2, then you must use the applicable
method specified in paragraphs (c)(3)(i) and (ii) of this section to
calculate CH4 and CO2 emissions from all natural
gas driven pneumatic pumps that are vented directly to the atmosphere
at your facility and that are not measured according to paragraph
(c)(1) of this section. You must exclude the counts of devices measured
according to paragraph (c)(1) of this section from the counts of pumps
for which emissions are calculated according to the requirements in
this paragraph (c)(3).
(i) Calculate CH4 and CO2 volumetric
emissions from natural gas driven pneumatic pumps using equation W-2B
to this section, except use the appropriate default whole gas
population emission factor for natural gas pneumatic pump vents (in
standard cubic feet per hour per device) as provided in table W-1A to
this subpart.
(ii) Convert the CH4 and CO2 volumetric
emissions determined according to paragraph (c)(3)(i) of this section
to CO2 and CH4 mass emissions using calculations
in paragraph (v) of this section.
(d) * * *
(2) Calculation Method 2. Except as specified in paragraph (d)(4)
of this section, if a CEMS is not available but a vent meter is
installed, use the CO2 composition and annual volume of vent
gas to calculate emissions using equation W-3 to this section.
* * * * *
(4) Calculation Method 4. If CEMS or a vent meter is not installed,
you may calculate emissions using any standard simulation software
package, such as AspenTech HYSYS[supreg], or API 4679 AMINECalc, that
uses the Peng-Robinson equation of state and speciates CO2
emissions. You may also use this method if a vent meter is installed
but a CEMS is not, in which case you must determine the difference
between the annual volume of vent gas measured by the vent meter and
the simulated annual volume of vent gas according to paragraph (d)(12)
of this section. A minimum of the following, determined for typical
operating conditions over the calendar year by engineering estimate and
process knowledge based on best
[[Page 42230]]
available data, must be used to characterize emissions:
* * * * *
(12) Comparison of annual volume of vent gas. If a vent meter is
installed but you wish to use Calculation Method 4 rather than
Calculation Method 2 for an AGR, use equation W-4D to this section to
determine the difference between the annual volume of vent gas measured
by the vent meter and the simulated annual volume of vent gas.
[GRAPHIC] [TIFF OMITTED] TR14MY24.029
Where:
PD = Percent difference between vent gas volumes, %.
Va,meter = Total annual volume of vent gas flowing out of
the AGR in cubic feet per year at actual conditions as determined by
flow meter using methods set forth in Sec. 98.234(b).
Alternatively, you may follow the manufacturer's instructions or
industry standard practice for calibration of the vent meter.
Va,sim = Total annual volume of vent gas flowing out of
the AGR in cubic feet per year at actual conditions as determined by
a standard simulation software package consistent with paragraph
(d)(4) of this section.
(e) Dehydrator vents. For dehydrator vents, calculate annual
CH4 and CO2 emissions using the applicable
calculation methods described in paragraphs (e)(1) through (e)(4) of
this section. For glycol dehydrators that have an annual average daily
natural gas throughput that is greater than or equal to 0.4 million
standard cubic feet per day, use Calculation Method 1 in paragraph
(e)(1) of this section. For glycol dehydrators that have an annual
average of daily natural gas throughput that is greater than 0 million
standard cubic feet per day and less than 0.4 million standard cubic
feet per day, use either Calculation Method 1 in paragraph (e)(1) of
this section or Calculation Method 2 in paragraph (e)(2) of this
section. If emissions from dehydrator vents are routed to a vapor
recovery system, you must adjust the emissions downward according to
paragraph (e)(5) of this section. If emissions from dehydrator vents
are routed to a flare or regenerator fire-box/fire tubes, you must
calculate CH4, CO2, and N2O annual
emissions as specified in paragraph (e)(6) of this section. For
Reporting Year 2024, you may use data collected anytime during the
calendar year for any of the applicable calculation methods, provided
that the data were collected in accordance with and meet the criteria
of the applicable paragraphs (e)(1) through (3) of this section.
(1) Calculation Method 1. Calculate annual mass emissions from
glycol dehydrators by using a software program, such as AspenTech
HYSYS[supreg] or GRI-GLYCalcTM, that uses the Peng-Robinson
equation of state to calculate the equilibrium coefficient, speciates
CH4 and CO2 emissions from dehydrators, and has
provisions to include regenerator control devices, a separator flash
tank, stripping gas and a gas injection pump or gas assist pump. The
following parameters must be determined by engineering estimate based
on best available data and must be used at a minimum to characterize
emissions from dehydrators:
* * * * *
(2) Calculation Method 2. Calculate annual volumetric emissions
from glycol dehydrators using equation W-5 to this section:
[GRAPHIC] [TIFF OMITTED] TR14MY24.030
Where:
Es,i = Annual total volumetric GHG emissions (either
CO2 or CH4) at standard conditions in cubic
feet.
EFi = Population emission factors for glycol dehydrators
in thousand standard cubic feet per dehydrator per year. Use 73.4
for CH4 and 3.21 for CO2 at 60 [deg]F and 14.7
psia.
Count = Total number of glycol dehydrators that have an annual
average daily natural gas throughput that is less than 0.4 million
standard cubic feet per day for which you elect to use this
Calculation Method 2.
1000 = Conversion of EFi in thousand standard cubic feet
to standard cubic feet.
* * * * *
(g) Well venting during completions and workovers with hydraulic
fracturing. Calculate annual volumetric natural gas emissions from gas
well and oil well venting during completions and workovers involving
hydraulic fracturing using equation W-10A or equation W-10B to this
section. Equation W-10A to this section applies to well venting when
the gas flowback rate is measured from a specified number of example
completions or workovers and equation W-10B to this section applies
when the gas flowback vent or flare volume is measured for each
completion or workover. Completion and workover activities are
separated into two periods, an initial period when flowback is routed
to open pits or tanks and a subsequent period when gas content is
sufficient to route the flowback to a separator or when the gas content
is sufficient to allow measurement by the devices specified in
paragraph (g)(1) of this section, regardless of whether a separator is
actually utilized. If you elect to use equation W-10A to this section,
you must follow the procedures specified in paragraph (g)(1) of this
section. If you elect to use equation W-10B to this section, you must
use a recording flow meter installed on the vent line, downstream of a
separator and ahead of a flare or vent, to measure the gas flowback. To
calculate emissions during the initial period, you must calculate the
gas flowback rate in the initial flowback period as described in
equation W-10B to this section. Alternatively, you may use a multiphase
flow meter placed on the flow line downstream of the wellhead and ahead
of the separator to directly measure gas flowback during the initial
period when flowback is routed to open pits or tanks. If you use a
multiphase flow meter, measurements must be taken from initiation of
flowback to the beginning of the period of time when sufficient
quantities of gas are present to enable separation. For Reporting Year
2024, you may use data collected by a multiphase flow meter anytime
during the calendar year. For either equation,
[[Page 42231]]
emissions must be calculated separately for completions and workovers,
for each sub-basin, and for each well type combination identified in
paragraph (g)(2) of this section. You must calculate CH4 and
CO2 volumetric and mass emissions as specified in paragraph
(g)(3) of this section. If emissions from well venting during
completions and workovers with hydraulic fracturing are routed to a
flare, you must calculate CH4, CO2, and
N2O annual emissions as specified in paragraph (g)(4) of
this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.031
[GRAPHIC] [TIFF OMITTED] TR14MY24.032
Where:
Es,n = Annual volumetric natural gas emissions in
standard cubic feet from gas venting during well completions or
workovers following hydraulic fracturing for each sub-basin and well
type combination.
W = Total number of wells completed or worked over using hydraulic
fracturing in a sub-basin and well type combination.
Tp,s = Cumulative amount of time of flowback, after
sufficient quantities of gas are present to enable separation, where
gas vented or flared for the completion or workover, in hours, for
each well, p, in a sub-basin and well type combination during the
reporting year. This may include non-contiguous periods of venting
or flaring.
Tp,i = Cumulative amount of time of flowback to open
tanks/pits, from when gas is first detected until sufficient
quantities of gas are present to enable separation, for the
completion or workover, in hours, for each well, p, in a sub-basin
and well type combination during the reporting year. This may
include non-contiguous periods of routing to open tanks/pits but
does not include periods when the oil well ceases to produce fluids
to the surface.
FRMs = Ratio of average gas flowback, during the period
when sufficient quantities of gas are present to enable separation,
of well completions and workovers from hydraulic fracturing to 30-
day production rate for the sub-basin and well type combination,
calculated using procedures specified in paragraph (g)(1)(iii) of
this section.
FRMi = Ratio of initial gas flowback rate during well
completions and workovers from hydraulic fracturing to 30-day gas
production rate for the sub-basin and well type combination,
calculated using procedures specified in paragraph (g)(1)(iv) of
this section, for the period of flow to open tanks/pits.
PRs,p = Average gas production flow rate during the first
30 days of production after completions of newly drilled wells or
well workovers using hydraulic fracturing in standard cubic feet per
hour of each well p, that was measured in the sub-basin and well
type combination. If applicable, PRs,p may be calculated
for oil wells using procedures specified in paragraph (g)(1)(vii) of
this section.
EnFs,p = Volume of N2 injected gas in cubic
feet at standard conditions that was injected into the reservoir
during an energized fracture job or during flowback for each well,
p, as determined by using an appropriate meter according to methods
described in Sec. 98.234(b), or by using receipts of gas purchases
that are used for the energized fracture job or injection during
flowback. Convert to standard conditions using paragraph (t) of this
section. If the fracture process did not inject gas into the
reservoir or if the injected gas is CO2 then
EnFs,p is 0.
FVs,p = Flow volume of vented or flared gas for each
well, p, in standard cubic feet measured using a recording flow
meter (digital or analog) on the vent line to measure gas flowback
during the separation period of the completion or workover according
to methods set forth in Sec. 98.234(b).
FRp,i = Flow rate vented or flared of each well, p, in
standard cubic feet per hour measured using a recording flow meter
(digital or analog) on the vent line to measure the flowback, at the
beginning of the period of time when sufficient quantities of gas
are present to enable separation, of the completion or workover
according to methods set forth in Sec. 98.234(b). Alternatively,
flow rate during the initial period may be measured using a
multiphase flow meter installed upstream of the separator capable of
accurately measuring gas flow prior to separation.
Zp,i = If a multiphase flow meter is used to measure
flowback during the initial period, then Zp,i is equal to
1. If flowback is measured using a recording flow meter (digital or
analog) on the vent line to measure the flowback, at the beginning
of the period of time when sufficient quantities of gas are present
to enable separation, then Zp,i is equal to 0.5.
(1) * * *
(i) Calculation Method 1. You must use equation W-12A to this
section as specified in paragraph (g)(1)(iii) of this section to
determine the value of FRMs. You must use equation W-12B to
this section as specified in paragraph (g)(1)(iv) of this section to
determine the value of FRMi. The procedures specified in
paragraphs (g)(1)(v) and (vi) of this section also apply. When making
gas flowback measurements for use in equations W-12A and W-12B to this
section, you must use a recording flow meter (digital or analog)
installed on the vent line, downstream of a separator and ahead of a
flare or vent, to measure the gas flowback rates in units of standard
cubic feet per hour according to methods set forth in Sec. 98.234(b).
Alternatively, you may use a multiphase flow meter placed on the flow
line downstream of the wellhead and ahead of the separator to directly
measure gas flowback during the initial period when flowback is routed
to open pits or tanks. If you use a multiphase flow meter, measurements
must be taken from initiation of flowback to the beginning of the
period of time when sufficient quantities of gas are present to enable
separation. For Reporting Year 2024, you may use data collected by a
multiphase flow meter anytime during the calendar year.
* * * * *
(iv) * * *
FRi,p = Initial measured gas flowback rate from
Calculation Method 1 described in paragraph (g)(1)(i) of this
section or initial calculated flow rate from Calculation Method 2
described in paragraph (g)(1)(ii) of this section in standard cubic
feet per hour for well(s), p, for each sub-basin and well type
combination. Measured and calculated FRi,p values must be
based on flow conditions at the beginning of the separation period
and must be expressed at standard conditions or measured using a
multiphase flow meter installed upstream of the separator capable of
accurately measuring gas flow prior to separation.
* * * * *
[[Page 42232]]
(i) * * *
(2) * * *
(i) Calculate the total annual natural gas emissions from each
unique physical volume that is blown down using either equation W-14A
or W-14B to this section. For Reporting Year 2024, you may use best
available information to determine temperature and pressure of any
emergency blowdown during the calendar year from the industry segments
specified.
[GRAPHIC] [TIFF OMITTED] TR14MY24.033
Where:
Es,n = Annual natural gas emissions at standard
conditions from each unique physical volume that is blown down, in
cubic feet.
N = Number of occurrences of blowdowns for each unique physical
volume in the calendar year.
V = Unique physical volume between isolation valves, in cubic feet,
as calculated in paragraph (i)(1) of this section.
C = Purge factor is 1 if the unique physical volume is not purged,
or 0 if the unique physical volume is purged using non-GHG gases.
Ts = Temperature at standard conditions (60 [deg]F).
Ta = Temperature at actual conditions in the unique
physical volume ([deg]F). For emergency blowdowns at onshore
petroleum and natural gas gathering and boosting facilities and
onshore natural gas transmission pipeline facilities, engineering
estimates based on best available information may be used to
determine the temperature.
Ps = Absolute pressure at standard conditions (14.7
psia).
Pa = Absolute pressure at actual conditions in the unique
physical volume (psia). For emergency blowdowns at onshore petroleum
and natural gas gathering and boosting facilities and onshore
natural gas transmission pipeline facilities, engineering estimates
based on best available information may be used to determine the
pressure.
Za = Compressibility factor at actual conditions for
natural gas. You may use either a default compressibility factor of
1, or a site-specific compressibility factor based on actual
temperature and pressure conditions.
[GRAPHIC] [TIFF OMITTED] TR14MY24.034
Where:
Es,n = Annual natural gas emissions at standard
conditions from each unique physical volume that is blown down, in
cubic feet.
p = Individual occurrence of blowdown for the same unique physical
volume.
N = Number of occurrences of blowdowns for each unique physical
volume in the calendar year.
Vp = Unique physical volume between isolation valves, in
cubic feet, for each blowdown ``p.''
Ts = Temperature at standard conditions (60 [deg]F).
Ta,p = Temperature at actual conditions in the unique
physical volume ([deg]F) for each blowdown ``p''. For emergency
blowdowns at onshore petroleum and natural gas gathering and
boosting facilities and onshore natural gas transmission pipeline
facilities, engineering estimates based on best available
information may be used to determine the temperature.
Ps = Absolute pressure at standard conditions (14.7
psia).
Pa,b,p = Absolute pressure at actual conditions in the
unique physical volume (psia) at the beginning of the blowdown
``p''. For emergency blowdowns at onshore petroleum and natural gas
gathering and boosting facilities and onshore natural gas
transmission pipeline facilities, engineering estimates based on
best available information may be used to determine the pressure at
the beginning of the blowdown.
Pa,e,p = Absolute pressure at actual conditions in the
unique physical volume (psia) at the end of the blowdown ``p''; 0 if
blowdown volume is purged using non-GHG gases. For emergency
blowdowns at onshore petroleum and natural gas gathering and
boosting facilities and onshore natural gas transmission pipeline
facilities, engineering estimates based on best available
information may be used to determine the pressure at the end of the
blowdown.
Za = Compressibility factor at actual conditions for
natural gas. You may use either a default compressibility factor of
1, or a site-specific compressibility factor based on actual
temperature and pressure conditions.
(j) Onshore production and onshore petroleum and natural gas
gathering and boosting storage tanks. Calculate CH4,
CO2, and N2O (when flared) emissions from
atmospheric pressure fixed roof storage tanks receiving hydrocarbon
produced liquids from onshore petroleum and natural gas production
facilities and onshore petroleum and natural gas gathering and boosting
facilities (including stationary liquid storage not owned or operated
by the reporter), as specified in this paragraph (j). For wells, gas-
liquid separators, or onshore petroleum and natural gas gathering and
boosting non-separator equipment (e.g., stabilizers, slug catchers)
with annual average daily throughput of oil greater than or equal to 10
barrels per day, calculate annual CH4 and CO2
using Calculation Method 1 or 2 as specified in paragraphs (j)(1) and
(2) of this section. For wells, gas-liquid separators, or non-separator
equipment with annual average daily throughput less than 10 barrels per
day, use Calculation Method 1, 2, or 3 as specified in paragraphs
(j)(1) through (3) of this section. If you use Calculation Method 1 or
Calculation Method 2 for separators, you must also calculate emissions
that may have occurred due to dump valves not closing properly using
the method specified in paragraph (j)(6) of this section. If emissions
from atmospheric pressure fixed roof storage tanks are routed to a
vapor recovery system, you must adjust the emissions downward according
to paragraph (j)(4) of this section. If emissions from atmospheric
pressure fixed roof storage tanks are routed to a flare, you must
calculate CH4, CO2, and N2O annual
emissions as specified in paragraph (j)(5) of this section. For
Reporting Year 2024, you may use data collected anytime during the
calendar year for any of the applicable calculation methods, provided
that the data were collected in accordance with and meet
[[Page 42233]]
the criteria of the applicable paragraphs (j)(1) through (3) of this
section.
* * * * *
(2) Calculation Method 2. Calculate annual CH4 and
CO2 emissions using the methods in paragraph (j)(2)(i) of
this section for gas-liquid separators. Calculate annual CH4
and CO2 emissions using the methods in paragraph (j)(2)(ii)
of this section for wells that flow directly to atmospheric storage
tanks in onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting (if applicable).
Calculate annual CH4 and CO2 emissions using the
methods in paragraph (j)(2)(iii) of this section for non-separator
equipment that flow directly to atmospheric storage tanks in onshore
petroleum and natural gas gathering and boosting.
* * * * *
(3) Calculation Method 3. Calculate CH4 and
CO2 emissions using Equation W-15 of this section:
[GRAPHIC] [TIFF OMITTED] TR14MY24.035
Where:
Es,I = Annual total volumetric GHG emissions (either
CO2 or CH4) at standard conditions in cubic
feet.
EFi = Population emission factor for separators, wells,
or non-separator equipment in thousand standard cubic feet per
separator, well, or non-separator equipment per year, for crude oil
use 4.2 for CH4 and 2.8 for CO2 at 60 [deg]F
and 14.7 psia, and for gas condensate use 17.6 for CH4
and 2.8 for CO2 at 60 [deg]F and 14.7 psia.
Count = Total number of separators, wells, or non-separator
equipment with annual average daily throughput less than 10 barrels
per day. Count only separators, wells, or non-separator equipment
that feed oil directly to the storage tank for which you elect to
use this Calculation Method 3.
1,000 = Conversion from thousand standard cubic feet to standard
cubic feet.
* * * * *
(m) * * *
(1) If you measure the gas flow to a vent using a continuous flow
measurement device, you may use measurements collected from a
continuous flow measurement device anytime during the calendar year.
(2) If you do not measure the gas flow to a vent using a continuous
flow measurement device or you do measure the gas flow but do not elect
to use the measurements, you must follow the procedures in paragraphs
(m)(2)(i) through (iii) of this section.
(i) Determine the GOR of the hydrocarbon production from each well
whose associated natural gas is vented or flared. If GOR from each well
is not available, use the GOR from a cluster of wells in the same sub-
basin category.
(ii) If GOR cannot be determined from your available data, then you
must use one of the procedures specified in paragraph (m)(2)(ii)(A) or
(B) of this section to determine GOR.
(A) You may use an appropriate standard method published by a
consensus-based standards organization if such a method exists.
(B) You may use an industry standard practice as described in Sec.
98.234(b).
(iii) Estimate venting emissions using equation W-18 to this
section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.036
Where:
Es,n = Annual volumetric natural gas emissions, at the
facility level, from associated gas venting at standard conditions,
in cubic feet.
GORp,q = Gas to oil ratio, for well p in sub-basin q, in
standard cubic feet of gas per barrel of oil; oil here refers to
hydrocarbon liquids produced of all API gravities.
Vp,q = Volume of oil produced, for well p in sub-basin q,
in barrels in the calendar year during time periods in which
associated gas was vented or flared.
SGp,q = Volume of associated gas sent to sales, for well
p in sub-basin q, in standard cubic feet of gas in the calendar year
during time periods in which associated gas was vented or flared.
x = Total number of wells in sub-basin that vent or flare associated
gas.
y = Total number of sub-basins in a basin that contain wells that
vent or flare associated gas.
(3) [Reserved]
* * * * *
(o) * * *
(10) Method for calculating volumetric GHG emissions from wet seal
oil degassing vents at an onshore petroleum and natural gas production
facility or an onshore petroleum and natural gas gathering and boosting
facility. You must calculate volumetric emissions from centrifugal
compressors at an onshore petroleum and natural gas production facility
or an onshore petroleum and natural gas gathering and boosting facility
as specified in paragraphs (o)(10)(i) through (iv) of this section, as
applicable. For Reporting Year 2024, you may use data collected anytime
during the calendar year for any of the applicable calculation methods,
provided that the data were collected in accordance with and meet the
criteria of the applicable paragraphs (o)(10)(i) through (iv) of this
section.
(i) For all centrifugal compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility with dry seals and self-contained wet
seals, you may measure compressor emissions by conducting the
volumetric emission measurements as required by Sec. 60.5380b(a)(5) of
this chapter, conducting all additional volumetric emission
measurements specified in paragraph (o)(1) of this section using
methods specified in paragraphs (o)(2) through (5) of this section
(based on the compressor mode (as defined in Sec. 98.238) in which the
compressor was found at the time of measurement), and calculating
emissions as specified in paragraphs (o)(6) through (9) of this
section. Conduct all measurements required by this paragraph (o)(10)(i)
at the frequency specified by Sec. 60.5380b(a)(4) of this chapter. For
any reporting year in which measuring at the frequency specified by
Sec. 60.5380b(a)(4) of this chapter results in measurement not being
required for a subject compressor, calculate emissions for all mode-
source combinations as specified in paragraph (o)(6)(ii) of this
section.
(ii) For all centrifugal compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility, you may elect to conduct the
volumetric emission measurements specified in paragraph
[[Page 42234]]
(o)(1) of this section using methods specified in paragraphs (o)(2)
through (5) of this section (based on the compressor mode (as defined
in Sec. 98.238) in which the compressor was found at the time of
measurement), and calculate emissions as specified in paragraphs (o)(6)
through (9) of this section.
(iii) For all centrifugal compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility for which paragraph (o)(10)(i) of this
section does not apply and you do not elect to conduct the volumetric
measurements specified in paragraph (o)(1) of this section, you must
calculate total atmospheric wet seal oil degassing vent emissions from
all centrifugal compressors at either an onshore petroleum and natural
gas production facility or an onshore petroleum and natural gas
gathering and boosting facility using equation W-25A to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.037
Where:
Es,i = Annual volumetric GHGi (either
CH4 or CO2) emissions from all centrifugal
compressors, at standard conditions, in cubic feet.
Count = Total number of centrifugal compressors with wet seal oil
degassing vents that are vented directly to the atmosphere.
Es,i,p = Annual volumetric GHGi (either
CH4 or CO2) emissions for centrifugal
compressor p, at standard conditions, in cubic feet, calculated
using equation W-25B to this section.
(iv) For all centrifugal compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility for which paragraph (o)(10)(i) of this
section does not apply, and you do not elect to conduct the volumetric
measurements specified in paragraph (o)(1) of this section, you must
calculate wet seal oil degassing vent emissions from each centrifugal
compressor using equation W-25B to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.038
Where:
Es,i,p = Annual volumetric GHGi (either
CH4 or CO2) emissions for centrifugal
compressor p, at standard conditions, in cubic feet.
EFs,p = Emission factor for centrifugal compressor p, in
standard cubic feet per year. Use 1.2 x 10\7\ standard cubic feet
per year per compressor for CH4 and 5.30 x 10\5\ standard
cubic feet per year per compressor for CO2 at 60 [deg]F
and 14.7 psia.
Tp = Total time centrifugal compressor p was in operating
mode, for which Es,i,p is being calculated in the
reporting year, in hours.
Ttotal = Total hours per year. Use 8784 in leap years and
use 8760 in all other years.
GHGi,p = Mole fraction of GHG (either CH4 or
CO2) in the vent gas for centrifugal compressor p in
operating mode; use the appropriate gas compositions in paragraph
(u)(2) of this section.
GHGEF = Mole fraction of GHG (either CH4 or
CO2) used in the determination of EFs,p. Use
0.95 for CH4 and 0.05 for CO2.
* * * * *
(p) * * *
(10) Method for calculating volumetric GHG emissions from
reciprocating compressor venting at an onshore petroleum and natural
gas production facility or an onshore petroleum and natural gas
gathering and boosting facility. You must calculate volumetric
emissions from reciprocating compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility as specified in paragraphs (p)(10)(i)
through (iv) of this section, as applicable. For Reporting Year 2024,
you may use data collected anytime during the calendar year for any of
the applicable calculation methods, provided that the data were
collected in accordance with and meet the criteria of the applicable
paragraphs (p)(10)(i) through (iv) of this section.
(i) For all reciprocating compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility, you may measure compressor emissions
by conducting the volumetric emission measurements as required by Sec.
60.5385b(b) and (c) of this chapter, conducting any additional
volumetric emission measurements specified in paragraph (p)(1) of this
section using methods specified in paragraphs (p)(2) through (5) of
this section (based on the compressor mode (as defined in Sec. 98.238)
in which the compressor was found at the time of measurement), and
calculating emissions as specified in paragraphs (p)(6) through (9) of
this section. Conduct all measurements required by this paragraph
(p)(10)(i) at the frequency specified by Sec. 60.5385b(a) of this
chapter. For any reporting year in which measuring at the frequency
specified by Sec. 60.5385b(a) of this chapter results in measurement
not being required for a subject compressor, calculate emissions for
all mode-source combinations as specified in paragraph (p)(6)(ii) of
this section.
(ii) For all reciprocating compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility, you may elect to conduct volumetric
emission measurements specified in paragraph (p)(1) of this section
using methods specified in paragraphs (p)(2) through (5) of this
section (based on the compressor mode (as defined in Sec. 98.238) in
which the compressor was found at the time of measurement), and
calculate emissions as specified in paragraphs (p)(6) through (9) of
this section.
(iii) For all reciprocating compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility for which paragraph (p)(10)(i) of this
section does not apply, and you do not elect to conduct volumetric
emission measurements specified in paragraph (p)(1) of this section,
you must calculate total atmospheric rod packing emissions from all
reciprocating compressors venting at
[[Page 42235]]
either an onshore petroleum and natural gas production facility or an
onshore petroleum and natural gas gathering and boosting facility using
equation W-29D to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.039
Where:
Es,i = Annual volumetric GHGi (either
CH4 or CO2) emissions from all reciprocating
compressors, at standard conditions, in cubic feet.
Count = Total number of reciprocating compressors with rod packing
emissions vented directly to the atmosphere.
Es,i,p = Annual volumetric GHGi (either
CH4 or CO2) emissions for reciprocating
compressor p, at standard conditions, in cubic feet, calculated
using equation W-29E to this section.
(iv) For all reciprocating compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility for which paragraph (p)(10)(i) of this
section does not apply, you must calculate rod packing vent emissions
from each reciprocating compressor using equation W-29E to this
section. Reciprocating compressor rod packing emissions that are routed
to a flare, combustion, or vapor recovery system are not required to be
determined under this paragraph (p).
[GRAPHIC] [TIFF OMITTED] TR14MY24.040
Where:
Es,i,p = Annual volumetric GHGi (either
CH4 or CO2) emissions for reciprocating
compressor p, at standard conditions, in cubic feet.
EFs,p = Emission factor for reciprocating compressor p,
in standard cubic feet per year. Use 9.48 x 10\3\ standard cubic
feet per year per compressor for CH4 and 5.27 x 10\2\
standard cubic feet per year per compressor for CO2 at 60
[deg]F and 14.7 psia.
Tp = Total time reciprocating compressor p was in
operating mode, for which Es,i,p is being calculated in
the reporting year, in hours.
Ttotal = Total hours per year. Use 8784 in leap years and
use 8760 in all other years.
GHGi,p = Mole fraction of GHG (either CH4 or
CO2) in the vent gas for reciprocating compressor p in
operating mode; use the appropriate gas compositions in paragraph
(u)(2) of this section.
GHGEF = Mole fraction of GHG (either CH4 or
CO2) used in the determination of EFs,p. Use
0.98 for CH4 and 0.02 for CO2.
* * * * *
(q) Equipment leak surveys. For the components identified in
paragraphs (q)(1)(i) through (iii) of this section, you must conduct
equipment leak surveys using the leak detection methods specified in
paragraphs (q)(1)(i) through (iii) of this section. For the components
identified in paragraph (q)(1)(iv) of this section, you may elect to
conduct equipment leak surveys, and if you elect to conduct surveys,
you must use a leak detection method specified in paragraph (q)(1)(iv)
of this section. This paragraph (q) applies to components in streams
with gas content greater than 10 percent CH4 plus
CO2 by weight. Components in streams with gas content less
than or equal to 10 percent CH4 plus CO2 by
weight are exempt from the requirements of this paragraph (q) and do
not need to be reported. Tubing systems equal to or less than one half
inch diameter are exempt from the requirements of this paragraph (q)
and do not need to be reported. Equipment leak components in vacuum
service are exempt from the survey and emission estimation requirements
of this paragraph (q).
(1) Survey requirements--(i) For the components listed in Sec.
98.232(e)(7), (f)(5), (g)(4), and (h)(5), that are not subject to the
well site or compressor station fugitive emissions standards in Sec.
60.5397a of this chapter, you must conduct surveys using any of the
leak detection methods listed in Sec. 98.234(a) and calculate
equipment leak emissions using the procedures specified in either
paragraph (q)(2) or (3) of this section. For Reporting Year 2024, you
may use data collected anytime during the calendar year for any of the
applicable calculation methods, provided that the data were collected
in accordance with and meet the criteria of the applicable paragraphs
(q)(2) through (4) of this section.
(ii) For the components listed in Sec. 98.232(d)(7) and (i)(1),
you must conduct surveys using any of the leak detection methods listed
in Sec. 98.234(a)(1) through (5) and calculate equipment leak
emissions using the procedures specified in either paragraph (q)(2) or
(3) of this section.
(iii) For the components listed in Sec. 98.232(c)(21), (e)(7),
(e)(8), (f)(5), (f)(6), (f)(7), (f)(8), (g)(4), (g)(6), (g)(7), (h)(5),
(h)(7), (h)(8), and (j)(10) that are subject to the well site or
compressor station fugitive emissions standards in Sec. 60.5397a of
this chapter, you must conduct surveys using any of the leak detection
methods in Sec. 98.234(a)(6) or (7) and calculate equipment leak
emissions using the procedures specified in either paragraph (q)(2) or
(3) of this section.
(iv) For the components listed in Sec. 98.232(c)(21), (e)(8),
(f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7), (h)(8), or (j)(10),
that are not subject to fugitive emissions standards in Sec. 60.5397a
of this chapter, you may elect to conduct surveys according to this
paragraph (q), and, if you elect to do so, then you must use one of the
leak detection methods in Sec. 98.234(a).
(A) If you elect to use a leak detection method in Sec.
98.234(a)(1) through (5) for the surveyed component types in Sec.
98.232(c)(21), (f)(7), (g)(6), (h)(7), or (j)(10) in lieu of the
population count methodology specified in paragraph (r) of this
section, then you must calculate emissions for the surveyed component
types in Sec. 98.232(c)(21), (f)(7), (g)(6), (h)(7), or (j)(10) using
the procedures in either paragraph (q)(2) or (3) of this section.
(B) If you elect to use a leak detection method in Sec.
98.234(a)(1) through (5) for the surveyed component types in Sec.
98.232(e)(8), (f)(6), (f)(8), (g)(7), and (h)(8), then you must use the
procedures in either paragraph (q)(2) or (3) of this section to
calculate those emissions.
[[Page 42236]]
(C) If you elect to use a leak detection method in Sec.
98.234(a)(6) or (7) for any elective survey under this subparagraph
(q)(1)(iv), then you must survey the component types in Sec.
98.232(c)(21), (e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7),
(h)(8), and (j)(10) that are not subject to fugitive emissions
standards in Sec. 60.5397a of this chapter, and you must calculate
emissions from the surveyed component types in Sec. 98.232(c)(21),
(e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7), (h)(8), and
(j)(10) using the emission calculation requirements in either paragraph
(q)(2) or (3) of this section.
(2) Calculation Method 1: Leaker emission factor calculation
methodology. If you elect not to measure leaks according to Calculation
Method 2 as specified in paragraph (q)(3) of this section, you must use
this Calculation Method 1 for all components included in a complete
leak survey. For industry segments listed in Sec. 98.230(a)(2) through
(9), if equipment leaks are detected during surveys required or elected
for components listed in paragraphs (q)(1)(i) through (iv) of this
section, then you must calculate equipment leak emissions per component
type per reporting facility using equation W-30 to this section and the
requirements specified in paragraphs (q)(2)(i) through (xi) of this
section. For the industry segment listed in Sec. 98.230(a)(8), the
results from equation W-30 to this section are used to calculate
population emission factors on a meter/regulator run basis using
equation W-31 to this section. If you chose to conduct equipment leak
surveys at all above grade transmission-distribution transfer stations
over multiple years, ``n,'' according to paragraph (q)(2)(x)(A) of this
section, then you must calculate the emissions from all above grade
transmission-distribution transfer stations as specified in paragraph
(q)(2)(xi) of this section.
* * * * *
(3) Calculation Method 2: Leaker measurement methodology. For
industry segments listed in Sec. 98.230(a)(2) through (9), if
equipment leaks are detected during surveys required or elected for
components listed in paragraphs (q)(1)(i) through (iv) of this section,
you may elect to measure the volumetric flow rate of each natural gas
leak identified during a complete leak survey. If you elect to use this
method, you must use this method for all components included in a
complete leak survey and you must determine the volumetric flow rate of
each natural gas leak identified during the leak survey and aggregate
the emissions by the method of leak detection and component type as
specified in paragraphs (q)(3)(i) through (vii) of this section. For an
onshore petroleum and natural gas production facility electing to use
this Calculation Method 2, a survey of all required components at a
single well-pad site, as defined in Sec. 98.238, will be considered a
complete leak detection survey for purposes of this section. For an
onshore petroleum and natural gas gathering and boosting facility
electing to use this Calculation Method 2, a survey of all required
components at a gathering and boosting site, as defined in Sec.
98.238, will be considered a complete leak detection survey for
purposes of this section.
(i) Determine the volumetric flow rate of each natural gas leak
identified during the leak survey following the methods Sec. 98.234(b)
through (d), as appropriate for each leak identified. You do not need
to use the same measurement method for each leak measured. If you are
unable to measure the natural gas leak because it would require
elevating the measurement personnel more than 2 meters above the
surface and a lift is unavailable at the site or it would pose
immediate danger to measurement personnel, then you must substitute the
default leak rate for the component and site type from tables W-1E, W-
2, W-3A, W-4A, W-5A, W-6A, and W-7 to this subpart, as applicable, as
the measurement for this leak.
(ii) For each leak, calculate the volume of natural gas emitted as
the product of the natural gas flow rate measured in paragraph
(q)(3)(i) of this section and the duration of the leak. If one leak
detection survey is conducted in the calendar year, assume the
component was leaking for the entire calendar year. If multiple leak
detection surveys are conducted in the calendar year, assume a
component found leaking in the first survey was leaking since the
beginning of the year until the date of the survey; assume a component
found leaking in the last survey of the year was leaking from the
preceding survey through the end of the year; assume a component found
leaking in a survey between the first and last surveys of the year was
leaking since the preceding survey until the date of the survey. For
each leaking component, account for time the component was not
operational (i.e., not operating under pressure) using an engineering
estimate based on best available data.
(iii) For each leak, convert the volumetric emissions of natural
gas determined in paragraph (q)(3)(ii) of this section to standard
conditions using the method specified in paragraph (t)(1) of this
section.
(iv) For each leak, convert the volumetric emissions of natural gas
at standard conditions determined in paragraph (q)(3)(iii) of this
section to CO2 and CH4 volumetric emissions at
standard conditions using the methods specified in paragraph (u) of
this section.
(v) For each leak, convert the GHG volumetric emissions at standard
conditions determined in paragraph (q)(3)(iv) of this section to GHG
mass emissions using the methods specified in paragraph (v) of this
section.
(vi) Sum the CO2 and CH4 mass emissions
determined in paragraph (q)(3)(v) of this section separately for each
type of component required to be surveyed by the method used for the
survey for which a leak was detected.
(vii) Multiply the total CO2 and CH4 mass
emissions by survey method and component type determined in paragraph
(q)(3)(vi) by the survey specific value for ``k'', the factor
adjustment for undetected leaks, where k equals 1.25 for the methods in
Sec. 98.234(q)(1), (3) and (5); k equals 1.55 for the method in Sec.
98.234(q)(2)(i); and k equals 1.27 for the method in Sec.
98.234(q)(2)(ii).
(viii) For natural gas distribution facilities:
(A) Use equation W-31 to this section to determine the meter/
regulator run population emission factors for each GHGi
using the methods as specified in paragraphs (q)(2)(x)(A) and (B) of
this section, except use the sum of the GHG volumetric emissions for
each type of component required to be surveyed by the method used for
the survey for which a leak was detected calculated in paragraph
(q)(3)(iv) of this section rather than the emissions calculated using
equation W-30 to this section.
(B) If you chose to conduct equipment leak surveys at all above
grade transmission-distribution transfer stations over multiple years,
``n,'' according to paragraph (q)(1)(viii) of this section, you must
use the meter/regulator run population emission factors calculated
according to paragraph (q)(3)(viii)(A) of this section and the total
count of all meter/regulator runs at above grade transmission-
distribution transfer stations to calculate emissions from all above
grade transmission-distribution transfer stations using equation W-32B
to this section.
(4) Development of facility-specific component-level leaker
emission factors by leak detection method. If you elect to measure
leaks according to Calculation Method 2 as specified in paragraph
[[Page 42237]]
(q)(3) of this section, you must use the measurement values determined
in accordance with paragraph (q)(3) of this section to calculate a
facility-specific component-level leaker emission factor by leak
detection method as provided in paragraphs (q)(4)(i) through (iv) of
this section.
(i) You must track the leak measurements made separately for each
of the applicable components listed in paragraphs (q)(1)(i) through (v)
of this section and by the leak detection method according to the
following three bins.
(A) Method 21 as specified in Sec. 98.234(a)(2).
(B) Method 21 as specified in Sec. 98.234(a)(7).
(C) Optical gas imaging (OGI) and other leak detection methods as
specified in Sec. 98.234(a)(1) or (3) through (6).
(ii) You must accumulate a minimum of 50 leak measurements total
for a given component type and leak detection method combination before
you can develop and use a facility-specific component-level leaker
emission factor for use in calculating emissions according to paragraph
(q)(2) of this section (Calculation Method 1: Leaker emission factor
calculation methodology).
(iii) Sum the volumetric flow rate of natural gas determined in
accordance with paragraph (q)(3)(i) of this section for each leak by
component type and leak detection method as specified in paragraph
(q)(4)(i) of this section meeting the minimum number of measurement
requirement in paragraph (q)(4)(ii) of this section.
(iv) Convert the volumetric flow rate of natural gas determined in
paragraph (q)(4)(iii) of this section to standard conditions using the
method specified in paragraph (t)(1) of this section.
(v) Determine the emission factor in units of standard cubic feet
per hour component (scf/hr-component) by dividing the sum of the
volumetric flow rate of natural gas determined in paragraph (q)(4)(iv)
of this section by the total number of leak measurements for that
component type and leak detection method combination.
(vi) You must update the emission factor determined in (q)(4)(v) of
this section annually to include the results from all complete leak
surveys for which leak measurement was performed during the reporting
year in accordance with paragraph (q)(3) of this section.
* * * * *
(s) * * *
(1) Offshore production facilities under BOEMRE jurisdiction shall
calculate emissions as specified in paragraph (s)(1)(i) or (ii) of this
section, as applicable.
(i) Report the same annual emissions as calculated and reported by
BOEMRE in data collection and emissions estimation study published by
BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS).
(ii) For any calendar year that does not overlap with the most
recent BOEMRE emissions study publication year, calculate emissions as
specified in paragraph (s)(1)(i) of this section or adjust the most
recent BOEMRE reported emissions data published by BOEMRE referenced in
30 CFR 250.302 through 304 (GOADS) based on the operating time for the
facility relative to the operating time in the most recent BOEMRE
published study.
(2) Offshore production facilities that are not under BOEMRE
jurisdiction must calculate emissions as specified in paragraph
(s)(2)(i) or (ii) of this section, as applicable.
(i) Use the most recent monitoring methods and calculation methods
published by BOEMRE referenced in 30 CFR 250.302 through 250.304 to
calculate and report annual emissions (GOADS).
(ii) For any calendar year that does not overlap with the most
recent BOEMRE emissions study publication, you may calculate emissions
as specified in paragraph (s)(2)(i) of this section or report the most
recently reported emissions data submitted to demonstrate compliance
with this subpart of part 98, with emissions adjusted based on the
operating time for the facility relative to operating time in the
previous reporting period.
* * * * *
(z) * * *
(1) If a fuel combusted in the stationary or portable equipment is
listed in table C-1 to subpart C of this part, or is a blend containing
one or more fuels listed in table C-1, calculate emissions according to
paragraph (z)(1)(i) of this section. If the fuel combusted is natural
gas and is of pipeline quality specification and has a minimum high
heat value of 950 Btu per standard cubic foot, use the calculation
method described in paragraph (z)(1)(i) of this section and you may use
the emission factor provided for natural gas as listed in table C-1. If
the fuel combusted is natural gas, has a minimum higher heating value
of 950 Btu per standard cubic foot, has a maximum higher heating value
of 1,100 Btu per standard cubic foot, and has a minimum methane content
of at least 70 percent, use the calculation method described in
paragraph (z)(1)(iii) of this section. If the fuel is natural gas and
does not meet the specifications of this paragraph (z)(1), calculate
emissions according to paragraph (z)(2) of this section. If the fuel is
field gas, process vent gas, or a blend containing field gas or process
vent gas, calculate emissions according to paragraph (z)(2) of this
section.
* * * * *
(iii) For natural gas with a minimum higher heating value of 950
Btu per standard cubic foot, a maximum higher heating value of 1,100
Btu per standard cubic foot, and a minimum methane content of at least
70 percent, calculate CO2, CH4, and
N2O emissions for each unit or group of units combusting the
same fuel according to Tier 2, Tier 3, or Tier 4 listed in subpart C of
this part. You must follow all applicable calculation requirements for
that tier listed in Sec. 98.33, any monitoring or QA/QC requirements
listed for that tier in Sec. 98.34, any missing data procedures
specified in Sec. 98.35, and any recordkeeping requirements specified
in Sec. 98.37.
(2) For fuel combustion units that combust field gas, process vent
gas, a blend containing field gas or process vent gas, or natural gas
that does not met the criteria of paragraph (z)(1) of this section,
calculate combustion emissions as follows:
* * * * *
(ii) If you have a continuous gas composition analyzer on fuel to
the combustion unit, you must use these compositions for determining
the concentration of gas hydrocarbon constituent in the flow of gas to
the unit. If you do not have a continuous gas composition analyzer on
gas to the combustion unit, you may use engineering estimates based on
best available data to determine the concentration of each constituent
in the flow of gas to the unit or group of units. Otherwise, you must
use the appropriate gas compositions for each stream of hydrocarbons
going to the combustion unit as specified in the applicable paragraph
in (u)(2) of this section.
* * * * *
0
13. Revise and republish Sec. 98.233 to read as follows
Sec. 98.233 Calculating GHG emissions.
You must calculate and report the annual GHG emissions as
prescribed in this section. For calculations that specify measurements
in actual conditions, reporters may use a flow or volume measurement
system that corrects to standard conditions and
[[Page 42238]]
determine the flow or volume at standard conditions; otherwise,
reporters must use average atmospheric conditions or typical operating
conditions as applicable to the respective monitoring methods in this
section.
(a) Natural gas pneumatic device venting. Calculate CH4
and CO2 emissions from natural gas pneumatic device venting
using the applicable provisions as specified in this paragraph (a) of
this section. If you have a continuous flow meter on the natural gas
supply line dedicated to any one or combination of natural gas
pneumatic devices or natural gas driven pneumatic pumps vented directly
to the atmosphere for any portion of the year, you must use the method
specified in paragraph (a)(1) of this section to calculate
CH4 and CO2 emissions from those devices. For
natural gas pneumatic devices vented directly to the atmosphere for
which the natural gas supply rate is not continuously measured, use the
applicable methods specified in paragraphs (a)(2) through (7) of this
section to calculate CH4 and CO2 emissions. For
natural gas pneumatic devices that are routed to flares, combustion, or
vapor recovery systems, use the applicable provisions specified in
paragraphs (a)(8) of this section. All references to natural gas
pneumatic devices for Calculation Method 1 in this paragraph (a) also
apply to combinations of natural gas pneumatic devices and natural gas
driven pneumatic pumps that are served by a common natural gas supply
line.
(1) Calculation Method 1. If you have or elect to install a
continuous flow meter that is capable of meeting the requirements of
Sec. 98.234(b) on the natural gas supply line dedicated to any one or
combination of natural gas pneumatic devices and natural gas driven
pneumatic pumps that are vented directly to the atmosphere, you must
use the applicable methods specified in paragraph (a)(1)(i) through
(iv) of this section to calculate CH4 and CO2
emissions from those devices.
(i) For volumetric flow monitors:
(A) Determine the cumulative annual volumetric flow, in standard
cubic feet, as measured by the flow monitor in the reporting year. If
all natural gas pneumatic devices supplied by the measured natural gas
supply line are routed to the atmosphere for only a portion of the year
and are routed to a flare, combustion, or vapor recovery system for the
remaining portion of the year, determine the cumulative annual
volumetric flow considering only those times when one or more of the
natural gas pneumatic devices were vented directly to the atmosphere.
If the flow meter was installed during the year, calculate the total
volumetric flow for the year based on the measured volumetric flow
times the total hours in the calendar year the devices were in service
(i.e., supplied with natural gas) divided by the number of hours the
devices were in service (i.e., supplied with natural gas) and the
volumetric flow was being measured.
(B) Convert the natural gas volumetric flow from paragraph
(a)(1)(i)(A) of this section to CH4 and CO2
volumetric emissions following the provisions in paragraph (u) of this
section.
(C) Convert the CH4 and CO2 volumetric
emissions from paragraph (a)(1)(i)(B) of this section to CH4
and CO2 mass emissions using calculations in paragraph (v)
of this section.
(ii) For mass flow monitors:
(A) Determine the cumulative annual mass flow, in metric tons, as
measured by the flow monitor in the reporting year. If all natural gas
pneumatic devices supplied by the measured natural gas supply line are
vented directly to the atmosphere for only a portion of the year and
are routed to a flare, combustion, or vapor recovery system for the
remaining portion of the year, determine the cumulative annual mass
flow considering only those times when one or more of the natural gas
pneumatic devices were vented directly to the atmosphere. If the flow
meter was installed during the year, calculate the total mass flow for
the year based on the measured mass flow times the total hours in the
calendar year the devices were in service (i.e., supplied with natural
gas) divided by the number of hours the devices were in service (i.e.,
supplied with natural gas) and the mass flow was being measured.
(B) Convert the cumulative mass flow from paragraph (a)(1)(ii)(A)
of this section to CH4 and CO2 mass emissions by
multiplying by the mass fraction of CH4 and CO2
in the supplied natural gas. You must follow the provisions in
paragraph (u) of this section for determining the mole fraction of
CH4 and CO2 and use molecular weights of 16 kg/
kg-mol and 44 kg/kg-mol for CH4 and CO2,
respectively. You may assume unspecified components have an average
molecular weight of 28 kg/kg-mol.
(iii) If the flow meter on the natural gas supply line serves both
natural gas pneumatic devices and natural gas driven pneumatic pumps,
disaggregate the total measured amount of natural gas to pneumatic
devices and natural gas driven pneumatic pumps based on engineering
calculations and best available data.
(iv) The flow meter must be operated and calibrated according to
the methods set forth in Sec. 98.234(b).
(2) Calculation Method 2. Except as provided in paragraph (a)(1) of
this section, you may elect to measure the volumetric flow rate of each
natural gas pneumatic device vent that vents directly to the atmosphere
at your well-pad site, gathering and boosting site, or facility as
specified in paragraphs (a)(2)(i) through (ix) of this section. You
must exclude the counts of devices measured according to paragraph
(a)(1) of this section from the counts of devices to be measured or for
which emissions are calculated according to the requirements in this
paragraph (a)(2).
(i) For facilities in the onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and boosting
industry segments, you may elect to measure your pneumatic devices
according to this Calculation Method 2 for some well-pad sites or
gathering and boosting sites and use other methods for other sites.
When you elect to measure the emissions from natural gas pneumatic
devices according to this Calculation Method 2 at a well-pad site or
gathering and boosting site, you must measure all natural gas pneumatic
devices that are vented directly to the atmosphere at the well-pad site
or gathering and boosting site during the same calendar year and you
must measure and calculate emissions according to the provisions in
paragraphs (a)(2)(iii) through (viii) of this section.
(ii) For facilities in the onshore natural gas processing, onshore
natural gas transmission compression, underground natural gas storage,
or natural gas distribution industry segments electing to use this
Calculation Method 2, you must measure all natural gas pneumatic
devices vented directly to the atmosphere at your facility each year
or, if your facility has 26 or more pneumatic devices, over multiple
years, not to exceed the number of years as specified in paragraphs
(a)(2)(ii)(A) through (D) of this section. If you elect to measure your
pneumatic devices over multiple years, you must measure approximately
the same number of devices each year. You must measure and calculate
emissions for natural gas pneumatic devices at your facility according
to the provisions in paragraphs (a)(2)(iii) through (ix), as
applicable.
(A) If your facility has at least 26 but not more than 50 natural
gas pneumatic devices vented directly to the atmosphere, the maximum
number of
[[Page 42239]]
years to measure all devices at your facility is 2 years.
(B) If your facility has at least 51 but not more than 75 natural
gas pneumatic devices vented directly to the atmosphere, the maximum
number of years to measure all devices at your facility is 3 years.
(C) If your facility has at least 76 but not more than 100 natural
gas pneumatic devices vented directly to the atmosphere, the maximum
number of years to measure all devices at your facility is 4 years.
(D) If your facility has 101 or more natural gas pneumatic devices
vented directly to the atmosphere, the maximum number of years to
measure all devices at your facility is 5 years.
(iii) For all industry segments, determine the volumetric flow rate
of each natural gas pneumatic device vent (in standard cubic feet per
hour) using one of the methods specified in Sec. 98.234(b) through
(d), as appropriate, according to the requirements specified in
paragraphs (a)(2)(iii)(A) through (E) of this section. You must measure
the emissions under representative conditions representative of normal
operations, which excludes periods immediately after conducting
maintenance on the device or manually actuating the device.
(A) If you use a temporary meter, such as a vane anemometer,
according to the methods set forth in Sec. 98.234(b) or a high volume
sampler according to methods set forth in Sec. 98.234(d), you must
measure the emissions from each device for a minimum of 15 minutes
while the device is in service (i.e., supplied with natural gas),
except for natural gas pneumatic isolation valve actuators. For natural
gas pneumatic isolation valve actuators, you must measure the emissions
from each device for a minimum of 5 minutes while the device is in
service (i.e., supplied with natural gas). If there is no measurable
flow from the natural gas pneumatic device after the minimum sampling
period, you can discontinue monitoring and follow the applicable
methods in paragraph (a)(2)(v) of this section.
(B) If you use calibrated bagging, follow the methods set forth in
Sec. 98.234(c) except you need only fill one bag to have a valid
measurement. You must collect sample for a minimum of 5 minutes for
natural gas pneumatic isolation valve actuators or 15 minutes for other
natural gas pneumatic devices. If no gas is collected in the calibrated
bag during the minimum sampling period, you can discontinue monitoring
and follow the applicable methods in paragraph (a)(2)(v) of this
section. If gas is collected in the bag during the minimum sampling
period, you must either continue sampling until you fill the calibrated
bag or you may elect to remeasure the vent according to paragraph
(a)(2)(iii)(A) of this section.
(C) You do not need to use the same measurement method for each
natural gas pneumatic device vent.
(D) If the measurement method selected measures the volumetric flow
rate in actual cubic feet, convert the measured flow to standard cubic
feet following the methods specified in paragraph (t)(1) of this
section.
(E) If there is measurable flow from the device vent, calculate the
volumetric flow rate of each natural gas pneumatic device vent (in
standard cubic feet per hour) by dividing the cumulative volume of
natural gas measured during the measurement period (in standard cubic
feet) by the duration of the measurement (in hours).
(iv) For all industry segments, if there is measurable flow from
the device vent, calculate the volume of natural gas emitted from each
natural gas pneumatic device vent as the product of the natural gas
flow rate measured in paragraph (a)(2)(iii) of this section and the
number of hours the pneumatic device was in service (i.e., supplied
with natural gas) in the calendar year.
(v) For all industry segments, if there is no measurable flow from
the device vent, estimate the emissions from the device according to
the methods in paragraphs (a)(2)(v)(A) through (C) of this section, as
applicable.
(A) For continuous high bleed pneumatic devices:
(1) Confirm that the device is in-service. If not, remeasure the
device according to paragraph (a)(2)(iii) of this section at a time the
device is in-service and calculate natural gas emissions from the
device according to paragraph (a)(2)(iv) of this section.
(2) Confirm that the device is correctly characterized as a
continuous high bleed pneumatic device according to the provisions in
paragraph (a)(6) of this section. If the device type was
mischaracterized, recharacterize the device type and use the
appropriate methods in paragraph (a)(2)(v)(B) or (C) of this section,
as applicable.
(3) Upon confirmation of the items in paragraphs (a)(2)(v)(A)(1)
and (2) of this section, remeasure the device vent using a different
measurement method specified in Sec. 98.234(b) through (d) or longer
monitoring duration until there is a measurable flow from the device
and calculate the natural gas emissions from the device according to
paragraph (a)(2)(iv) of this section.
(B) For continuous low bleed pneumatic devices:
(1) Confirm that the device is in-service. If not, remeasure the
device according to paragraph (a)(2)(iii) of this section at a time the
device is in-service and calculate natural gas emissions from the
device according to paragraph (a)(2)(iv) of this section.
(2) Determine natural gas bleed rate (in standard cubic feet per
hour) at the supply pressure used for the pneumatic device based on the
manufacturer's steady state natural gas bleed rate reported for the
device. If the steady state bleed rate is reported in terms of air
consumption, multiply the air consumption rate by 1.29 to calculate the
steady state natural gas bleed rate. If a steady state bleed rate is
not reported, follow the requirements in paragraph (a)(2)(v)(B)(4) of
this section.
(3) Calculate the volume of natural gas emitted from the natural
gas pneumatic device vent as the product of the natural gas steady
state bleed rate determined in paragraph (a)(2)(v)(B)(2) of this
section and number of hours the pneumatic device was in service (i.e.,
supplied with natural gas) in the calendar year.
(4) If a steady state bleed rate is not reported, reassess whether
the device is correctly characterized as a continuous low bleed
pneumatic device according to the provisions in paragraph (a)(7) of
this section. If the device is confirmed to be a continuous low bleed
pneumatic device, you must remeasure the device vent using a different
measurement method specified in Sec. 98.234(b) through (d) or longer
monitoring duration until there is a measurable flow from the device
and calculate natural gas emissions from the device according to
paragraph (a)(2)(iv) of this section. If the device type was
mischaracterized, recharacterize the device type and use the
appropriate methods in paragraph (a)(2)(v)(A) or (C) of this section,
as applicable.
(C) For intermittent bleed pneumatic devices:
(1) Confirm that the device is in-service. If not, remeasure the
device according to paragraph (a)(2)(iii) of this section at a time the
device is in-service and calculate natural gas emissions according to
paragraph (a)(2)(iv) of this section. For devices confirmed to be in-
service during the measurement period, calculate natural gas emissions
according to paragraphs (a)(2)(v)(C)(2) through (5) of this section.
(2) Calculate the volume of the controller, tubing and actuator (in
actual cubic feet) based on the device and tubing size.
(3) Sum the volumes in paragraph (a)(2)(v)(C)(2) of this section
and convert the volume to standard cubic feet following the methods
specified in
[[Page 42240]]
paragraph (t)(1) of this section based on the natural gas supply
pressure.
(4) Estimate the number of actuations during the year based on
company records, if available, or best engineering estimates. For
isolation valve actuators, you may multiply the number of valve
closures during the year by 2 (one actuation to close the valve; one
actuation to open the valve).
(5) Calculate the volume of natural gas emitted from the natural
gas pneumatic device vent as the product of the per actuation volume in
standard cubic feet determined in paragraph (a)(2)(v)(C)(3) of this
section, the number of actuations during the year as determined in
paragraph (a)(2)(v)(C)(4) of this section, and the relay correction
factor. Use 1 for the relay correction factor if there is no relay; use
3 for the relay correction factor if there is a relay.
(vi) For each pneumatic device, convert the volumetric emissions of
natural gas at standard conditions determined in paragraph (a)(2)(iv)
or (v) of this section, as applicable, to CO2 and
CH4 volumetric emissions at standard conditions using the
methods specified in paragraph (u) of this section.
(vii) For each pneumatic device, convert the GHG volumetric
emissions at standard conditions determined in paragraph (a)(2)(vi) of
this section to GHG mass emissions using the methods specified in
paragraph (v) of this section.
(viii) Sum the CO2 and CH4 mass emissions
determined in paragraph (a)(2)(vii) of this section separately for each
type of natural gas pneumatic device (continuous high bleed, continuous
low bleed, and intermittent bleed).
(ix) For facilities in the onshore natural gas processing, onshore
natural gas transmission compression, underground natural gas storage,
or natural gas distribution industry segments, if you chose to conduct
natural gas pneumatic device measurements over multiple years, ``n,''
according to paragraph (a)(2)(ii) of this section, then you must
calculate the emissions from all pneumatic devices at your facility as
specified in paragraph (a)(2)(ix)(A) through (E) of this section.
(A) Use the emissions calculated in (a)(2)(viii) of this section
for the devices measured during the reporting year.
(B) Calculate the whole gas emission factor for each type of
pneumatic device at the facility using equation W-1A to this section
and all available data from the current year and the previous years in
your monitoring cycle (n-1 years) for which natural gas pneumatic
device vent measurements were made according to Calculation Method 2 in
paragraph (a)(2) of this section (e.g., if your monitoring cycle is 3
years, then use measured data from the current year and the two
previous years). This emission factor must be updated annually.
[GRAPHIC] [TIFF OMITTED] TR14MY24.041
Where:
EFt = Whole gas population emission factor for natural
gas pneumatic device vents of type ``t'' (continuous high bleed,
continuous low bleed, intermittent bleed), in standard cubic feet
per hour per device.
MTs,t,y = Volumetric whole gas emissions rate measurement
at standard (``s'') conditions from component type ``t'' during year
``y'' in standard cubic feet per hour, as calculated in paragraph
(a)(2)(iii) [if there was measurable flow from the device vent],
(a)(2)(v)(B)(2), or (a)(2)(v)(C)(6) of this section, as applicable.
Countt,y = Count of natural gas pneumatic device vents of
type ``t'' measured according to Calculation Method 2 in year ``y.''
n = Number of years of data to include in the emission factor
calculation according to the number of years used to monitor all
natural gas pneumatic device vents at the facility.
(C) Calculate CH4 and CO2 volumetric
emissions from continuous high bleed, continuous low bleed, and
intermittent bleed natural gas pneumatic devices that were not measured
during the reporting year using equation W-1B to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.042
Where:
Es,i = Annual total volumetric GHG emissions at standard
conditions in standard cubic feet per year from natural gas
pneumatic device vents, of types ``t'' (continuous high bleed,
continuous low bleed, intermittent bleed), for GHGi.
Countt = Total number of natural gas pneumatic devices of
type ``t'' (continuous high bleed, continuous low bleed,
intermittent bleed) as determined in paragraphs (a)(5) through (7)
of this section that vent directly to the atmosphere and that were
not directly measured according to the requirements in paragraph
(a)(1) or (a)(2)(iii) of this section.
EFt = Population emission factors for natural gas
pneumatic device vents (in standard cubic feet per hour per device)
of each type ``t'' (continuous high bleed, continuous low bleed,
intermittent bleed) as calculated using equation W-1A to this
section.
GHGi = Concentration of GHGi CH4 or
CO2, in produced natural gas or processed natural gas for
each facility as specified in paragraph (u)(2) of this section.
Tt = Average estimated number of hours in the operating
year the devices, of each type ``t'', were in service (i.e.,
supplied with natural gas) using engineering estimates based on best
available data. Default is 8,760 hours.
(D) Convert the volumetric emissions calculated using equation W-1B
to this section to CH4 and CO2 mass emissions
using the methods specified in paragraph (v) of this section.
(E) Sum the CH4 and CO2 mass emissions
calculated in paragraphs (a)(2)(ix)(A) and (D) of this section
separately for each type of pneumatic device (continuous high bleed,
continuous low bleed, intermittent bleed) to calculate the total
CH4 and CO2 mass emissions by device type for
Calculation Method 2.
(3) Calculation Method 3. For facilities in the onshore petroleum
and natural gas production and onshore petroleum and natural gas
gathering and boosting industry segments, you may elect to use the
applicable methods specified in paragraphs (a)(3)(i) through (iv) of
this section, as applicable, to calculate CH4 and
CO2 emissions from your natural gas pneumatic devices that
are vented directly to the atmosphere at your site except those that
are measured
[[Page 42241]]
according to paragraph (a)(1) or (2) of this section. You must exclude
the counts of devices measured according to paragraph (a)(1) of this
section from the counts of devices to be monitored or for which
emissions are calculated according to the requirements in this
paragraph (a)(3). You may not use this Calculation Method 3 for those
well-pad sites or gathering and boosting sites for which you elected to
measure emissions according to paragraph (a)(2) of this section.
(i) For continuous high bleed and continuous low bleed natural gas
pneumatic devices vented directly to the atmosphere, you must calculate
CH4 and CO2 volumetric emissions using either the
methods in paragraph (a)(3)(i)(A) or (B) of this section.
(A) Measure all continuous high bleed and continuous low bleed
pneumatic devices at your well-pad site or gathering and boosting site,
as applicable, according to the provisions in paragraphs (a)(2) of this
section.
(B) Use equation W-1B to this section, except use the appropriate
default whole gas population emission factors for natural gas pneumatic
device vents (in standard cubic feet per hour per device) of each type
``t'' (continuous high bleed and continuous low bleed) as listed in
table W-1 to this subpart.
(ii) For intermittent bleed pneumatic devices, you must monitor
each intermittent bleed pneumatic device at your well-pad site or
gathering and boosting site as specified in paragraphs (a)(3)(ii)(A)
through (C) of this section, as applicable.
(A) You must use one of the monitoring methods specified in Sec.
98.234(a)(1) through (3) except that the monitoring dwell time for each
device vent must be at least 2 minutes or until a malfunction is
identified, whichever is shorter. A device is considered malfunctioning
if any leak is observed when the device is not actuating or if a leak
is observed for more than 5 seconds, or the extended duration as
specified in paragraph (a)(3)(ii)(C) of this section if applicable,
during a device actuation. If you cannot tell when a device is
actuating, any observed leak from the device indicates a malfunctioning
device.
(B) If you elect to monitor emissions from natural gas pneumatic
devices at a well-pad site or gathering and boosting site according to
this Calculation Method 3, you must monitor all natural gas
intermittent bleed pneumatic devices that are vented directly to the
atmosphere at the well-pad site or gathering and boosting site during
the same calendar year. You must monitor the natural gas intermittent
bleed pneumatic devices under conditions representative of normal
operations, which excludes periods immediately after conducting
maintenance on the device or manually actuating the device.
(C) For certain throttling pneumatic devices or isolation valve
actuators on pipes greater than 5 inches in diameter, that may actuate
for more than 5 seconds under normal conditions, you may elect to
identify individual devices for which longer bleed periods may be
allowed as specified in paragraphs (a)(3)(ii)(C)(1) and (2) of this
section prior to monitoring these devices for the first time.
(1) You must identify the devices for which extended actuations are
considered normal operations. For each device identified, you must
determine the typical actuation time and maintain documentation and
rationale for the extended actuation duration value.
(2) You must clearly and permanently tag the device vent for each
natural gas pneumatic device that has an extended actuation duration.
The tag must include the device ID and the normal duration period (in
seconds) as determined and documented for the device as specified in
paragraph (a)(3)(ii)(C)(1) of this section.
(iii) For intermittent bleed pneumatic devices that are monitored
according to paragraph (a)(3)(ii) of this section during the reporting
year, you must calculate CH4 and CO2 volumetric
emissions from intermittent bleed natural gas pneumatic devices vented
directly to the atmosphere using equation W-1C to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.043
Where:
Ei = Annual total volumetric emissions of GHGi from
intermittent bleed natural gas pneumatic devices in standard cubic
feet.
GHGi = Concentration of GHGi, CH4 or
CO2, in natural gas supplied to the intermittent bleed
natural gas pneumatic device as defined in paragraph (u)(2) of this
section.
x = Total number of intermittent bleed natural gas pneumatic devices
detected as malfunctioning in any pneumatic device monitoring survey
during the year. A component found as malfunctioning in two or more
surveys during the year is counted as one malfunctioning component.
K1 = Whole gas emission factor for malfunctioning
intermittent bleed natural gas pneumatic devices, in standard cubic
feet per hour per device. Use 24.1 for well-pad sites in the onshore
petroleum and natural gas production industry segment and use 16.1
for gathering and boosting sites in the onshore petroleum and
natural gas gathering and boosting industry segment.
Tmal,z = The total time the surveyed pneumatic device
``z'' was in service (i.e., supplied with natural gas) and assumed
to be malfunctioning, in hours. If one pneumatic device monitoring
survey is conducted in the calendar year, assume the device found
malfunctioning was malfunctioning for the entire calendar year. If
multiple pneumatic device monitoring surveys are conducted in the
calendar year, assume a device found malfunctioning in the first
survey was malfunctioning since the beginning of the year until the
date of the survey; assume a device found malfunctioning in the last
survey of the year was malfunctioning from the preceding survey
through the end of the year; assume a device found malfunctioning in
a survey between the first and last surveys of the year was
malfunctioning since the preceding survey until the date of the
survey; and sum times for all malfunctioning periods.
Tt,z = The total time the surveyed natural gas pneumatic
device ``z'' was in service (i.e., supplied with natural gas) during
the year. Default is 8,760 hours for non-leap years and 8,784 hours
for leap years.
K2 = Whole gas emission factor for properly operating
intermittent bleed natural gas pneumatic devices, in standard cubic
feet per hour per device. Use 0.3 for well-pad sites in the onshore
petroleum and natural gas production industry segment and use 2.8
for gathering and boosting sites in the onshore petroleum and
natural gas gathering and boosting industry segment.
Count = Total number of intermittent bleed natural gas pneumatic
devices that were never observed to be malfunctioning during any
monitoring survey during the year.
Tavg = The average time the intermittent bleed natural
gas pneumatic devices that were never observed to be malfunctioning
during any monitoring survey were in service (i.e., supplied with
natural gas) using engineering estimates based on best available
data.
[[Page 42242]]
Default is 8,760 hours for non-leap years and 8,784 hours for leap
years.
(A) You must conduct at least one complete pneumatic device
monitoring survey in a calendar year. If you conduct multiple complete
pneumatic device monitoring surveys in a calendar year, you must use
the results from each complete pneumatic device monitoring survey when
calculating emissions using equation W-1C to this section.
(B) For the purposes of paragraph (a)(3)(iii)(A) of this section, a
complete monitoring survey is a survey of all intermittent bleed
natural gas pneumatic devices vented directly to the atmosphere at a
well-pad site for onshore petroleum and natural gas production
facilities (except those measured according to paragraph (a)(1) of this
section) or all intermittent bleed pneumatic devices vented directly to
the atmosphere at a gathering and boosting site for onshore petroleum
and natural gas gathering and boosting facilities (except those
measured according to paragraph (a)(1) of this section).
(iv) You must convert the CH4 and CO2
volumetric emissions as determined according to paragraphs (a)(3)(i)
and (iii) of this section and calculate both CO2 and
CH4 mass emissions using calculations in paragraph (v) of
this section for each type of natural gas pneumatic device (continuous
high bleed, continuous low bleed, and intermittent bleed).
(4) Calculation Method 4. For well-pads in the onshore petroleum
and natural gas production industry segment, gathering and boosting
sites in the onshore petroleum and natural gas gathering and boosting
industry segments, or for facilities in the onshore natural gas
processing, onshore natural gas transmission compression, underground
natural gas storage, or natural gas distribution industry segments, you
may elect to calculate CH4 and CO2 emissions from
your natural gas pneumatic devices that are vented directly to the
atmosphere at your site using the methods specified in paragraphs
(a)(4)(i) and (ii) of this section except those that are measured
according to paragraphs (a)(1) through (3) of this section. You must
exclude the counts of devices measured according to paragraph (a)(1) of
this section from the counts of devices to be monitored or for which
emissions are calculated according to the requirements in this
paragraph (a)(4). You may not use this Calculation Method 4 for those
devices for which you elected to measure emissions according to
paragraph (a)(1), (2), or (3) of this section.
(i) You must calculate CH4 and CO2 volumetric
emissions using equation W-1B to this section, except use the
appropriate default whole gas population emission factors for natural
gas pneumatic device vents (in standard cubic feet per hour per device)
of each type ``t'' (continuous high bleed, continuous low bleed, and
intermittent bleed) as listed in table W-1 to this subpart.
(ii) You must convert the CH4 and CO2
volumetric emissions as determined according to paragraphs (a)(4)(i) of
this section and calculate both CO2 and CH4 mass
emissions using calculations in paragraph (v) of this section for each
type of natural gas pneumatic device (continuous high bleed, continuous
low bleed, and intermittent bleed).
(5) Counts of natural gas pneumatic devices. For all industry
segments, determine ``Countt'' for equation W-1A, W-1B, or W-1C to this
section for each type of natural gas pneumatic device (continuous high
bleed, continuous low bleed, and intermittent bleed) by counting the
total number of devices at the well-pad site, gathering and boosting
site, or facility, as applicable, the number of devices that are vented
directly to the atmosphere and the number of those devices that were
measured or monitored during the reporting year, as applicable, except
as specified in paragraph (a)(6) of this section.
(6) Counts of onshore petroleum and natural gas production industry
segment or the onshore petroleum and natural gas gathering and boosting
natural gas pneumatic devices. For facilities in the onshore petroleum
and natural gas production industry segment or the onshore petroleum
and natural gas gathering and boosting industry segment, you have the
option in the first two consecutive calendar years to determine the
total number of natural gas pneumatic devices at the facility and the
number of devices that are vented directly to the atmosphere for each
type of natural gas pneumatic device (continuous high bleed, continuous
low bleed, and intermittent bleed), as applicable, using engineering
estimates based on best available data. Counts of natural gas pneumatic
devices measured or monitored during the reporting year must be made
based on actual counts.
(7) Type of natural gas pneumatic devices. For all industry
segments, determine the type of natural gas pneumatic device using
engineering estimates based on best available information.
(8) Routing to flares, combustion, or vapor recovery systems.
Calculate emissions from natural gas pneumatic devices routed to
flares, combustion, or vapor recovery systems as specified in paragraph
(a)(8)(i) or (ii) of this section, as applicable. If a device was
vented directly to the atmosphere for part of the year and routed to a
flare, combustion unit, or vapor recovery system during another part of
the year, then calculate emissions from the time the device vents
directly to the atmosphere as specified in paragraph (a)(1), (2), (3)
or (4) of this section, as applicable, and calculate emissions from the
time the device was routed to a flare or combustion as specified in
paragraph (a)(8)(i) or (ii) of this section, as applicable. During
periods when natural gas pneumatic device emissions are collected in a
vapor recovery system that is not routed to combustion, paragraphs
(a)(1) through (4) and (a)(8)(i) and (ii) of this section do not apply
and no emissions calculations are required. Notwithstanding the
calculation and emissions reporting requirements as specified in this
paragraph (a)(8) of this section, the number of natural gas pneumatic
devices routed to flares, combustion, or vapor recovery systems, by
type, must be reported as specified in Sec. 98.236(b)(2)(iii).
(i) If any natural gas pneumatic devices were routed to a flare,
you must calculate CH4, CO2, and N2O
emissions for the flare stack as specified in paragraph (n) of this
section and report emissions from the flare as specified in Sec.
98.236(n).
(ii) If emissions from any natural gas pneumatic devices were
routed to combustion units, you must calculate and report emissions as
specified in subpart C of this part or calculate emissions as specified
in paragraph (z) of this section and report emissions from the
combustion equipment as specified in Sec. 98.236(z), as applicable.
(b) [Reserved]
(c) Natural gas driven pneumatic pump venting. Calculate
CH4 and CO2 emissions from natural gas driven
pneumatic pumps venting directly to the atmosphere as specified in
paragraph (c)(1), (2), or (3) of this section, as applicable. If you
have a continuous flow meter on the natural gas supply line that is
dedicated to any one or more natural gas driven pneumatic pumps, each
of which only vents directly to the atmosphere, you must use
Calculation Method 1 as specified in paragraph (c)(1) of this section
to calculate vented CH4 and CO2 emissions from
those pumps. Use Calculation Method 1 for any portion of a year when
all of the pumps on the
[[Page 42243]]
continuously measured natural gas supply line were vented directly to
atmosphere. For natural gas driven pneumatic pumps vented directly to
the atmosphere for which the natural gas supply rate is not
continuously measured or the continuously measured natural gas supply
line supplies some natural gas driven pneumatic pumps that vent
emissions directly to the atmosphere and others that route emissions to
flares, combustion or vapor recovery, use either the method specified
in paragraph (c)(2) or (3) of this section to calculate vented
CH4 and CO2 emissions for all of the natural gas
driven pneumatic pumps at your facility that are not subject to
Calculation Method 1; you may not use Calculation Method 2 for some
vented natural gas driven pneumatic pumps and Calculation Method 3 for
other natural gas driven pneumatic pumps. Calculate emissions from
natural gas driven pneumatic pumps routed to flares or combustion as
specified in paragraph (c)(4) of this section. All references to
natural gas driven pneumatic pumps for Calculation Method 1 in this
paragraph (c) also apply to combinations of natural gas pneumatic
devices and natural gas driven pneumatic pumps that are served by a
common natural gas supply line. You do not have to calculate emissions
from natural gas driven pneumatic pumps covered in paragraph (e) of
this section under this paragraph (c).
(1) Calculation Method 1. If you have or elect to install a
continuous flow meter that is capable of meeting the requirements of
Sec. 98.234(b) of this subpart on a supply line to natural gas driven
pneumatic pumps, then for the period of the year when the natural gas
supply line is dedicated to any one or more natural gas driven
pneumatic pumps, and each of the pumps is vented directly to the
atmosphere, you must use the applicable methods specified in paragraphs
(c)(1)(i) or (ii) of this section to calculate vented CH4
and CO2 emissions from those pumps.
(i) For volumetric flow monitors:
(A) Determine the cumulative annual volumetric flow, in standard
cubic feet, as measured by the flow monitor in the reporting year. If
the flow meter was installed during the year, calculate the total
volumetric flow for the year based on the measured volumetric flow
times the total hours in the calendar year in which at least one of the
pumps connected to the supply line was pumping liquid divided by the
number of hours in the year when at least one of pumps connected to the
supply line was pumping liquid and the volumetric flow was being
measured.
(B) Convert the natural gas volumetric flow from paragraph
(c)(1)(i)(A) of this section to CH4 and CO2
volumetric emissions following the provisions in paragraph (u) of this
section.
(C) Convert the CH4 and CO2 volumetric
emissions from paragraph (c)(1)(i)(B) of this section to CH4
and CO2 mass emissions using calculations in paragraph (v)
of this section.
(ii) For mass flow monitors:
(A) Determine the cumulative annual mass flow, in metric tons, as
measured by the flow monitor in the reporting year. If the flow meter
was installed during the year, calculate the total mass flow of vented
natural gas emissions for the year based on the measured mass flow
times the total hours in the calendar year in which at least one of the
pumps connected to the supply line was pumping liquid divided by the
number of hours in the year when at least one of pumps connected to the
supply line was pumping liquid and the mass flow was being measured.
(B) Convert the cumulative mass flow from paragraph (c)(1)(ii)(A)
of this section to CH4 and CO2 mass emissions by
multiplying by the mass fraction of CH4 and CO2
in the supplied natural gas. You must follow the provisions in
paragraph (u) of this section for determining the mole fraction of
CH4 and CO2 and use molecular weights of 16 kg/
kg-mol and 44 kg/kg-mol for CH4 and CO2,
respectively. You may assume unspecified components have an average
molecular weight of 28 kg/kg-mol.
(iii) If the supply line serves both natural gas pneumatic devices
and natural gas driven pneumatic pumps, disaggregate the total measured
amount of natural gas to natural gas pneumatic devices and natural gas
driven pneumatic pumps based on engineering calculations and best
available data.
(iv) The flow meter must be operated and calibrated according to
the methods set forth in Sec. 98.234(b).
(2) Calculation Method 2. Except as provided in paragraph (c)(1) of
this section, you may elect to measure the volumetric flow rate of each
natural gas driven pneumatic pump at your facility that vents directly
to the atmosphere as specified in paragraphs (c)(2)(i) through (vii) of
this section. You must exclude the counts of pumps measured according
to paragraph (c)(1) of this section from the counts of pumps to be
measured and for which emissions are calculated according to the
requirements in this paragraph (c)(2).
(i) Measure all natural gas driven pneumatic pumps at your facility
at least once every 5 years. If you elect to measure your pneumatic
pumps over multiple years, you must measure approximately the same
number of pumps each year. When you measure the emissions from natural
gas driven pneumatic pumps at a well-pad site or gathering and boosting
site, you must measure all pneumatic pumps that are vented directly to
the atmosphere at the well-pad site or gathering and boosting site
during the same calendar year.
(ii) Determine the volumetric flow rate of each natural gas driven
pneumatic pump (in standard cubic feet per hour) using one of the
methods specified in Sec. 98.234(b) through (d), as appropriate,
according to the requirements specified in paragraphs (c)(2)(ii)(A)
through (D) of this section. You must measure the emissions under
representative conditions representative of normal operations, which
excludes periods immediately after conducting maintenance on the pump.
(A) If you use a temporary meter, such as a vane anemometer,
according to the methods set forth in Sec. 98.234(b) or a high volume
sampler according to methods set forth in Sec. 98.234(d), you must
measure the emissions from each pump for a minimum of 5 minutes, during
a period when the pump is continuously pumping liquid.
(B) If you use calibrated bagging, follow the methods set forth in
Sec. 98.234(c), except under Sec. 98.234(c)(2), only one bag must be
filled to have a valid measurement. You must collect sample for a
minimum of 5 minutes, or until the bag is full, whichever is shorter,
during a period when the pump is continuously pumping liquid. If the
bag is not full after 5 minutes, you must either continue sampling
until you fill the calibrated bag or you may elect to remeasure the
vent according to paragraph (c)(2)(ii)(A) of this section.
(C) You do not need to use the same measurement method for each
natural gas driven pneumatic pump vent.
(D) If the measurement method selected measures the volumetric flow
rate in actual cubic feet, convert the measured flow to standard cubic
feet following the methods specified in paragraph (t)(1) of this
section. Convert the measured flow during the test period to standard
cubic feet per hour, as appropriate.
(iii) Calculate the volume of natural gas emitted from each natural
gas driven pneumatic pump vent as the product of the natural gas
emissions flow rate measured in paragraph (c)(2)(ii) of this section
and the number of hours that liquid was pumped by the pneumatic pump in
the calendar year.
(iv) For each pneumatic pump, convert the volumetric emissions of
natural gas at standard conditions
[[Page 42244]]
determined in paragraph (c)(2)(iii) of this section to CO2
and CH4 volumetric emissions at standard conditions using
the methods specified in paragraph (u) of this section.
(v) For each pneumatic pump, convert the GHG volumetric emissions
at standard conditions determined in paragraph (c)(2)(iv) of this
section to GHG mass emissions using the methods specified in paragraph
(v) of this section.
(vi) Sum the CO2 and CH4 mass emissions
determined in paragraph (c)(2)(v) of this section.
(vii) If you chose to conduct natural gas pneumatic pump
measurements over multiple years, ``n,'' according to paragraph
(c)(2)(i) of this section, then you must calculate the emissions from
all pneumatic pumps at your facility as specified in paragraph
(c)(2)(vii)(A) through (D) of this section.
(A) Use the emissions calculated in paragraph (c)(2)(vi) of this
section for the pumps measured during the reporting year.
(B) Calculate the whole gas emission factor for pneumatic pumps at
the facility using equation W-2A to this section and all available data
from the current year and the previous years in your monitoring cycle
(n-1 years) for which natural gas pneumatic pump vent measurements were
made according to Calculation Method 2 in paragraph (c)(2) of this
section (e.g., if your monitoring cycle is 3 years, then use measured
data from the current year and the two previous years). This emission
factor must be updated annually.
[GRAPHIC] [TIFF OMITTED] TR14MY24.044
Where:
EFs = Whole gas population emission factor for natural
gas pneumatic pump vents, in standard cubic feet per hour per pump.
MTs,y = Volumetric whole gas emissions rate measurement
at standard (``s'') conditions during year ``y'' in standard cubic
feet per hour, as calculated in paragraph (c)(2)(iii) of this
section.
County = Count of natural gas driven pneumatic pump vents
measured according to Calculation Method 2 in year ``y.''
n = Number of years of data to include in the emission factor
calculation according to the number of years used to monitor all
natural gas pneumatic pump vents at the facility.
(C) Calculate CH4 and CO2 volumetric
emissions from natural gas driven pneumatic pumps per well-pad site or
gathering and boosting site that were not measured during the reporting
year using equation W-2B to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.045
Where:
Es,i = Annual total volumetric GHG emissions at standard
conditions in standard cubic feet per year from natural gas driven
pneumatic pump vents, for GHGi.
Count = Total number of natural gas driven pneumatic pumps that
vented directly to the atmosphere and that were not directly
measured according to the requirements in paragraphs (c)(1) or
(c)(2)(ii) of this section.
EFs = Population emission factors for natural gas driven
pneumatic pumps (in standard cubic feet per hour per pump) as
calculated using equation W-2A to this section.
GHGi = Concentration of GHGi, CH4
or CO2, in produced natural gas as defined in paragraph
(u)(2)(i) of this section.
T = Average estimated number of hours in the operating year the
pumps that vented directly to the atmosphere were pumping liquid
using engineering estimates based on best available data. Default is
8,760 hours for pumps that only vented directly to the atmosphere.
(D) Calculate both CH4 and CO2 mass emissions
from volumetric emissions calculated using equation W-2B to this
section using calculations in paragraph (v) of this section.
(E) Sum the CH4 and CO2 mass emissions
calculated in paragraphs (c)(2)(vii)(A) and (D) of this section to
calculate the total CH4 and CO2 mass emissions
for Calculation Method 2 per well-pad site or gathering and boosting
site.
(3) Calculation Method 3. If you elect not to measure emissions as
specified in Calculation Method 2, then you must use the applicable
method specified in paragraphs (c)(3)(i) and (ii) of this section to
calculate CH4 and CO2 emissions from all natural
gas driven pneumatic pumps that are vented directly to the atmosphere
at each well-pad site or gathering and boosting site at your facility
and that are not measured according to paragraph (c)(1) of this
section. You must exclude the counts of devices measured according to
paragraph (c)(1) of this section from the counts of pumps for which
emissions are calculated according to the requirements in this
paragraph (c)(3).
(i) Calculate CH4 and CO2 volumetric
emissions from natural gas driven pneumatic pumps using equation W-2B
to this section, except use the appropriate default whole gas
population emission factor for natural gas pneumatic pump vents (in
standard cubic feet per hour per device) as provided in table W-1 to
this subpart.
(ii) Convert the CH4 and CO2 volumetric
emissions determined according to paragraph (c)(3)(i) of this section
to CO2 and CH4 mass emissions using calculations
in paragraph (v) of this section.
(4) Routing to flares, combustion, or vapor recovery systems.
Calculate emissions from natural gas driven pneumatic pumps for periods
when they are routed to flares or combustion as specified in paragraph
(c)(4)(i) or (ii) of this section, as applicable. If emissions from a
natural gas driven pneumatic pump were vented directly to the
atmosphere for part of the year and routed to a flare, combustion, or
vapor recovery for another part of the year, then calculate vented
emissions for the portion of the year when venting occurs using the
applicable method in paragraph (c)(1), (2), or (3) of this section for
the period when venting occurs (including periods when emissions
bypassed a flare), and calculate emissions for the portion of the year
when the emissions are routed to a flare or combustion unit using the
method in paragraph (c)(4) of this section. During periods when
emissions from a pump are routed to a vapor recovery system without
subsequently being routed to combustion, paragraphs (c)(1) through (3)
and (c)(4)(i) and (ii) of this section do not apply and no emissions
calculations are required. Notwithstanding the calculation and
[[Page 42245]]
emissions reporting requirements as specified in this paragraph (c)(4)
of this section, the number of natural gas pneumatic pumps routed to
flares, combustion, or vapor recovery systems must be reported as
specified in Sec. 98.236(c)(2)(iii) and (iv).
(i) If any natural gas driven pneumatic pumps were routed to a
flare, you must calculate CH4, CO2, and
N2O emissions for the flare stack as specified in paragraph
(n) of this section and report emissions from the flare as specified in
Sec. 98.236(n).
(ii) If emissions from any natural gas driven pneumatic pumps were
routed to combustion, you must calculate emissions for the combustion
equipment as specified in paragraph (z) of this section and report
emissions from the combustion equipment as specified in Sec.
98.236(z).
(d) Acid gas removal unit (AGR) vents and Nitrogen removal unit
(NRU) vents. For AGR vents (including processes such as amine,
membrane, molecular sieve or other absorbents and adsorbents),
calculate emissions for CH4 and CO2 vented
directly to the atmosphere or emitted through a sulfur recovery plant,
using any of the calculation methods described in paragraphs (d)(1)
through (4) of this section, and also comply with paragraphs (d)(5)
through (12) of this section, as applicable. For NRU vents, calculate
emissions for CH4 vented directly to the atmosphere using
any of the calculation methods described in paragraphs (d)(1) through
(4) of this section, and also comply with paragraphs (d)(5) through
(11) of this section, as applicable. If any AGR vents or NRU vents are
routed to a flare, you must calculate CH4, CO2,
and N2O emissions for the flare stack as specified in
paragraph (n) of this section and report emissions from the flare as
specified in Sec. 98.236(n). If any AGR vents or NRU vents are routed
through an engine (e.g., permeate from a membrane or de-adsorbed gas
from a pressure swing adsorber used as fuel supplement) (i.e., routed
to combustion), you must calculate CH4, CO2, and
N2O emissions as specified in subpart C of this part or as
specified in paragraph (z) of this section, as applicable.
(1) Calculation Method 1. If you operate and maintain a continuous
emissions monitoring system (CEMS) that has both a CO2
concentration monitor and volumetric flow rate monitor, you must
calculate CO2 emissions under this subpart by following the
Tier 4 Calculation Method and all associated calculation, quality
assurance, reporting, and recordkeeping requirements for Tier 4 in
subpart C of this part (General Stationary Fuel Combustion Sources).
Alternatively, you may follow the manufacturer's instructions or
industry standard practice. If a CO2 concentration monitor
and volumetric flow rate monitor are not available, you may elect to
install a CO2 concentration monitor and a volumetric flow
rate monitor that comply with all of the requirements specified for the
Tier 4 Calculation Method in subpart C of this part (General Stationary
Fuel Combustion Sources).
(2) Calculation Method 2. Except as specified in paragraph (d)(4)
of this section, for CO2 emissions, if a CEMS is not
available but a vent meter is installed, use the CO2
composition and annual volume of vent gas to calculate emissions using
equation W-3 to this section. Except as specified in paragraph (d)(4)
of this section, for CH4 emissions, if a vent meter is
installed, including the volumetric flow rate monitor on a CEMS for
CO2, use the CH4 composition and annual volume of
vent gas to calculate emissions using equation W-3 to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.046
Where:
Ea,i = Annual total volumetric GHGi (either
CO2 or CH4) emissions at actual conditions, in
cubic feet per year.
Va = Total annual volume of vent gas flowing out of the
AGR or NRU in cubic feet per year at actual conditions as determined
by flow meter using methods set forth in Sec. 98.234(b).
Alternatively, you may follow the manufacturer's instructions or
industry standard practice for calibration of the vent meter.
Voli = Annual average volumetric fraction of GHGi (either
CO2 or CH4) content in vent gas flowing out of
the AGR or NRU as determined in paragraph (d)(7) of this section.
(3) Calculation Method 3. If a CEMS for CO2 or a vent
meter is not installed, you may use the inlet and/or outlet gas flow
rate of the AGR or NRU to calculate emissions for CH4 and
CO2 using equation W-4A, W-4B, or W-4C to this section. If
inlet gas flow rate and CH4 and CO2 content of
the vent gas are known, use equation W-4A to this section. If outlet
gas flow rate and CH4 and CO2 content of the vent
gas are known, use equation W-4B to this section. If inlet gas flow
rate and outlet gas flow rate are known, use equation W-4C to this
section. If the calculated annual total volumetric emissions (Ea,i) are
less than or equal to 0 cubic feet per year, you may not use this
calculation method for either CH4 or CO2.
[GRAPHIC] [TIFF OMITTED] TR14MY24.047
[GRAPHIC] [TIFF OMITTED] TR14MY24.048
[GRAPHIC] [TIFF OMITTED] TR14MY24.049
Where:
Ea,i = Annual total volumetric GHGi (either
CH4 or CO2) emissions at actual conditions, in
cubic feet per year.
Vin = Total annual volume of natural gas flow into the
AGR or NRU in cubic feet per year at actual conditions as determined
[[Page 42246]]
using methods specified in paragraph (d)(5) of this section.
Vout = Total annual volume of natural gas flow out of the
AGR or NRU in cubic feet per year at actual conditions as determined
using methods specified in paragraph (d)(5) of this section.
VolI,i = Annual average volumetric fraction of
GHGi (either CH4 or CO2) content in
natural gas flowing into the AGR or NRU as determined in paragraph
(d)(7) of this section.
VolO,i = Annual average volumetric fraction of
GHGi (either CH4 or CO2) content in
natural gas flowing out of the AGR or NRU as determined in paragraph
(d)(8) of this section.
VolEM,i = Annual average volumetric fraction of
GHGi (either CH4 or CO2) content in
the vent gas flowing out of the AGR or NRU as determined in
paragraph (d)(6) of this section.
(4) Calculation Method 4. If CEMS for CO2 or a vent
meter is not installed, you may calculate CH4 and
CO2 emissions from an AGR or NRU using any standard
simulation software package, such as AspenTech HYSYS[supreg], or API
4679 AMINECalc, that uses the Peng-Robinson equation of state and
speciates CH4 and CO2 emissions. A minimum of the
parameters listed in paragraph (d)(4)(i) through (x) of this section,
as applicable, must be used to characterize emissions. If paragraph
(d)(4)(i) through (x) of this section indicates that an applicable
parameter must be measured, collect measurements reflective of
representative operating conditions over the time period covered by the
simulation. Determine all other applicable parameters in paragraph
(d)(4)(i) through (x) of this section by engineering estimate and
process knowledge based on best available data and, if necessary,
adjust parameters to represent the operating conditions over the time
period covered by the simulation. Determine the number of simulations
and associated time periods such that the simulations cover the entire
reporting year (i.e., if you calculate emissions using one simulation,
use representative parameters for the operating conditions over the
calendar year; if you use periodic simulations to cover the calendar
year, use parameters for the operating conditions over each
corresponding appropriate portion of the calendar year). You may also
use this method for CO2 emissions from an AGR if a vent
meter is installed but a CEMS is not, or for CH4 emissions
from an AGR if a vent meter is installed (including the volumetric flow
rate monitor on a CEMS for CO2), in which case you must
determine the difference between the annual volume of vent gas measured
by the vent meter and the simulated annual volume of vent gas according
to paragraph (d)(9) of this section.
(i) Natural gas feed temperature, pressure, and flow rate (must be
measured).
(ii) Acid gas content of feed natural gas (must be measured).
(iii) Acid gas content of outlet natural gas.
(iv) CH4 content of feed natural gas (must be measured).
(v) CH4 content of outlet natural gas.
(vi) For NRU, nitrogen content of feed natural gas (must be
measured).
(vii) For NRU, nitrogen content of outlet natural gas.
(viii) Unit operating hours, excluding downtime for maintenance or
standby.
(ix) Exit temperature of natural gas.
(x) For AGR, solvent type, pressure, temperature, circulation rate,
and composition.
(5) Flow rate of inlet or outlet. For Calculation Method 3,
determine the gas flow rate of the inlet when using equation W-4A or W-
4C to this section or the gas flow rate of the outlet when using
equation W-4B or W-4C to this section for the natural gas stream of an
AGR or NRU using a meter according to methods set forth in Sec.
98.234(b). If you do not have a continuous flow meter, either install a
continuous flow meter or use an engineering calculation to determine
the flow rate.
(6) Composition of vent gas. For Calculation Method 2 or
Calculation Method 3 when using equation W-4A or W-4B to this section,
if a continuous gas analyzer is not available on the vent stack, either
install a continuous gas analyzer or take quarterly gas samples from
the vent gas stream for each quarter that the AGR or NRU is operating
to determine Voli in equation W-3 to this section or
VolEM,i in equation W-4A or W-4B to this section, according
to the methods set forth in Sec. 98.234(b).
(7) Composition of inlet gas stream. For Calculation Method 3, if a
continuous gas analyzer is installed on the inlet gas stream, then the
continuous gas analyzer results must be used. If a continuous gas
analyzer is not available, either install a continuous gas analyzer or
take quarterly gas samples from the inlet gas stream for each quarter
that the AGR or NRU is operating to determine VolI,i in equation W-4A,
W-4B, or W-4C to this section, according to the methods set forth in
Sec. 98.234(b).
(8) Composition of outlet gas stream. For Calculation Method 3,
determine annual average volumetric fraction of GHGi (either
CH4 or CO2) content in natural gas flowing out of
the AGR or NRU using one of the methods specified in paragraphs
(d)(8)(i) through (iii) of this section.
(i) If a continuous gas analyzer is installed on the outlet natural
gas stream, then the continuous gas analyzer results must be used. If a
continuous gas analyzer is not available, you may install a continuous
gas analyzer.
(ii) If a continuous gas analyzer is not available or installed,
quarterly gas samples may be taken from the outlet natural gas stream
for each quarter that the AGR or NRU is operating to determine
VolO,i in equation W-4A, W-4B, or W-4C to this section,
according to the methods set forth in Sec. 98.234(b).
(iii) If a continuous gas analyzer is not available or installed,
you may use the outlet pipeline quality specification for
CO2 in natural gas and the outlet quality specification for
CH4 in natural gas.
(9) Comparison of annual volume of vent gas. If a vent meter is
installed but you wish to use Calculation Method 4 rather than
Calculation Method 2 for an AGR, use equation W-4D to this section to
determine the difference between the annual volume of vent gas measured
by the vent meter and the simulated annual volume of vent gas.
[GRAPHIC] [TIFF OMITTED] TR14MY24.050
Where:
PD = Percent difference between vent gas volumes, %.
Va,meter = Total annual volume of vent gas flowing out of
the AGR in cubic feet per year at actual conditions as determined by
flow meter using methods set forth in Sec. 98.234(b).
Alternatively, you may follow the manufacturer's instructions or
industry standard practice for calibration of the vent meter.
Va,sim = Total annual volume of vent gas flowing out of
the AGR in cubic feet per year at actual conditions as determined
[[Page 42247]]
by a standard simulation software package consistent with paragraph
(d)(4) of this section.
(10) Volumetric emissions. Calculate annual volumetric
CH4 and CO2 emissions at standard conditions
using calculations in paragraph (t) of this section.
(11) Emissions vented directly to atmosphere from AGRs or NRUs
routed to vapor recovery systems or flares. If the AGR vent or NRU vent
has a vapor recovery system or routes emissions to a flare, calculate
annual emissions vented directly to atmosphere from the AGR vent or NRU
vent during periods of time when emissions were not routed to the vapor
recovery system or flare as specified in paragraph (d)(11)(i) and (ii)
of this section. If emissions are routed to a flare but the flare is
unlit, calculate emissions in accordance with the methodology specified
in paragraph (n) of this section and report emissions from the flare as
specified in Sec. 98.236(n).
(i) Calculate vented emissions as specified in paragraph (d)(1),
(2), (3), or (4) of this section, which represents the emissions from
the AGR vent or NRU vent prior to the vapor recovery system or flare.
Calculate an average hourly vented emissions rate by dividing the
vented emissions by the number of hours that the AGR or NRU was in
operation.
(ii) To calculate vented emissions during periods when the AGR vent
or NRU vent was not routing emissions to a vapor recovery system or a
flare, multiply the average hourly vented emissions rate determined in
paragraph (d)(11)(i) of this section by the number of hours that the
AGR or NRU vented directly to the atmosphere. Determine the number of
hours that the AGR or NRU vented directly to atmosphere by subtracting
the hours that the AGR or NRU was connected to a vapor recovery system
or flare (based on engineering estimate and best available data) from
the total operating hours for the AGR or NRU in the calendar year. You
must take into account periods with reduced capture efficiency of the
vapor recovery system or flare.
(12) Mass emissions. Calculate annual mass CH4 and
CO2 emissions using calculations in paragraph (v) of this
section.
(e) Dehydrator vents. For dehydrator vents, calculate annual
CH4 and CO2 emissions using the applicable
calculation methods described in paragraphs (e)(1) through (5) of this
section. For glycol dehydrators that have an annual average daily
natural gas throughput that is greater than or equal to 0.4 million
standard cubic feet per day, use Calculation Method 1 in paragraph
(e)(1) of this section. For glycol dehydrators that have an annual
average of daily natural gas throughput that is greater than 0 million
standard cubic feet per day and less than 0.4 million standard cubic
feet per day, use either Calculation Method 1 in paragraph (e)(1) of
this section or Calculation Method 2 in paragraph (e)(2) of this
section. If you are required to use a software program consistent with
the requirements of paragraph (e)(1) of this section for compliance
with federal or state regulations, air permit requirements, or annual
emissions inventory reporting for the current reporting year, you must
use Calculation Method 1 to calculate annual CH4 and
CO2 emissions. If emissions from dehydrator vents are routed
to a vapor recovery system, you must calculate the emissions according
to paragraph (e)(4) of this section. If emissions from dehydrator vents
are routed to a regenerator firebox/fire tubes, you must calculate
CH4, CO2, and N2O annual emissions as specified
in paragraph (e)(5) of this section. If any dehydrator vents are routed
to a flare, you must calculate CH4, CO2, and N2O
emissions for the flare stack as specified in paragraph (n) of this
section and report emissions from the flare as specified in Sec.
98.236(n).
(1) Calculation Method 1. Calculate annual mass emissions from
glycol dehydrators by using a software program, such as AspenTech
HYSYS[supreg], Bryan Research & Engineering ProMax@, or GRI-GLYCalcTM,
that uses the Peng-Robinson equation of state to calculate the
equilibrium coefficient, speciates CH4 and CO2
emissions from dehydrators, and has provisions to include regenerator
control devices, a separator flash tank, stripping gas, and a gas
injection pump or gas assist pump. If you elect to use ProMax@, you
must use version 5.0 or above. Emissions must be modeled from both the
still vent and, if applicable, the flash tank vent. A minimum of the
parameters listed in paragraph (e)(1)(i) through (xi) of this section,
as applicable, must be used to characterize emissions. If paragraph
(e)(1)(i) through (xi) of this section indicates that an applicable
parameter must be measured, collect measurements reflective of
representative operating conditions for the time period covered by the
simulation. Sample and analyze composition at least once every five
years. Samples must be collected within six months of the startup or by
January 1, 2030, whichever date is later. Until such a time that a
sample is collected, determine composition by using one of the existing
methods. Determine all other applicable parameters in paragraph
(e)(1)(i) through (xi) of this section by engineering estimate and
process knowledge based on best available data and, if necessary,
adjust parameters to represent the operating conditions over the time
period covered by the simulation. Determine the number of simulations
and associated time periods such that the simulations cover the entire
reporting year (i.e., if you calculate emissions using one simulation,
use representative parameters for the operating conditions over the
calendar year; if you use periodic simulations to cover the calendar
year, use parameters for the operating conditions over each
corresponding appropriate portion of the calendar year). If more than
one simulation is performed, input parameters should be remeasured if
no longer representative of operating conditions.
(i) Feed natural gas flow rate (based on measured data).
(ii) Feed natural gas water content (must be measured).
(iii) Outlet natural gas water content.
(iv) Absorbent circulation pump type (e.g., natural gas pneumatic/
air pneumatic/electric).
(v) Absorbent circulation rate.
(vi) Absorbent type (e.g., triethylene glycol (TEG), diethylene
glycol (DEG) or ethylene glycol (EG)).
(vii) Use of stripping gas.
(viii) Use of flash tank separator (and disposition of recovered
gas).
(ix) Hours operated.
(x) Wet natural gas temperature and pressure at the absorber inlet
(must be measured).
(xi) Wet natural gas composition. Measure this parameter using one
of the methods described in paragraphs (e)(1)(xi)(A) and (B) of this
section.
(A) Use an appropriate standard method published by a consensus-
based standards organization if such a method exists or you may use an
industry standard practice as specified in Sec. 98.234(b) to sample
and analyze wet natural gas composition.
(B) If only composition data for dry natural gas is available,
assume the wet natural gas is saturated.
(2) . Calculate annual volumetric emissions from glycol
dehydrators using equation W-5 to this section, and then calculate the
collective CH4 and CO2 mass emissions from the
volumetric emissions using the procedures in paragraph (v) of this
section:
[[Page 42248]]
[GRAPHIC] [TIFF OMITTED] TR14MY24.051
Where:
Es,i = Annual total volumetric GHG emissions (either
CO2 or CH4) at standard conditions in cubic
feet.
EFi = Population emission factors for glycol dehydrators
in thousand standard cubic feet per dehydrator per year. Use 73.4
for CH4 and 3.21 for CO2 at 60 [deg]F and 14.7
psia.
Count = Total number of glycol dehydrators that have an annual
average daily natural gas throughput that is greater than 0 million
standard cubic feet per day and less than 0.4 million standard cubic
feet per day for which you elect to use this Calculation Method 2.
1000 = Conversion of EFi in thousand standard cubic feet to standard
cubic feet.
(3) Calculation Method 3. For dehydrators of any size that use
desiccant, you must calculate emissions from the amount of gas vented
from the vessel when it is depressurized for the desiccant refilling
process using equation W-6 to this section. From volumetric natural gas
emissions, calculate both CH4 and CO2 volumetric
and mass emissions using the procedures in paragraphs (u) and (v) of
this section. Desiccant dehydrator emissions covered in this paragraph
do not have to be calculated separately using the method specified in
paragraph (i) of this section for blowdown vent stacks.
[GRAPHIC] [TIFF OMITTED] TR14MY24.052
Where:
Es,n = Annual natural gas emissions at standard
conditions in cubic feet.
H = Height of the dehydrator vessel (ft).
D = Inside diameter of the vessel (ft).
P1 = Atmospheric pressure (psia).
P2 = Pressure of the gas (psia).
[pi] = pi (3.14).
%G = Percent of packed vessel volume that is gas.
N = Number of dehydrator openings in the calendar year.
100 = Conversion of %G to fraction.
(4) Emissions vented directly to atmosphere from dehydrators routed
to a vapor recovery system, flare, or regenerator firebox/fire tubes.
If the dehydrator(s) has a vapor recovery system, routes emissions to a
flare, or routes emissions to a regenerator firebox/fire tubes and you
use Calculation Method 1 or Calculation Method 2 in paragraph (e)(1) or
(2) of this section, calculate annual emissions vented directly to
atmosphere from the dehydrator(s) during periods of time when emissions
were not routed to the vapor recovery system, flare, or regenerator
firebox/fire tubes as specified in paragraphs (e)(4)(i) and (ii) of
this section. If the dehydrator(s) has a vapor recovery system or
routes emissions to a flare and you use Calculation Method 3 in
paragraph (e)(3) of this section, calculate annual emissions vented
directly to atmosphere from the dehydrator(s) during periods of time
when emissions were not routed to the vapor recovery system or flare as
specified in paragraph (e)(4)(iii) of this section.
(i) When emissions from dehydrator(s) are calculated using
Calculation Method 1 or 2, calculate vented emissions as specified in
paragraph (e)(1) or (2) of this section, which represents the emissions
from the dehydrator prior to the vapor recovery system or flare.
Calculate an average hourly vented emissions rate by dividing the
vented emissions by the number of hours that the dehydrator was in
operation.
(ii) To calculate total emissions vented directly to atmosphere
during periods when the dehydrator was not routing emissions to a vapor
recovery system, flare, or regenerator firebox/fire tubes for
dehydrator(s) with emissions calculated using Calculation Method 1 or
2, multiply the average hourly vented emissions rate determined in
paragraph (e)(4)(i) of this section by the number of hours that the
dehydrator vented directly to the atmosphere. Determine the number of
hours that the dehydrator vented directly to atmosphere by subtracting
the hours that the dehydrator was connected to a vapor recovery system,
flare, or regenerator firebox/fire tubes (based on engineering estimate
and best available data) from the total operating hours for the
dehydrator in the calendar year. You must take into account periods
with reduced capture efficiency of the vapor recovery system, flare, or
regenerator firebox/fire tubes. If emissions are routed to a flare but
the flare is unlit, calculate emissions in accordance with the
methodology specified in paragraph (n) of this section and report
emissions from the flare as specified in Sec. 98.236(n).
(iii) When emissions from dehydrator(s) are calculated using
Calculation Method 3, calculate total annual emissions vented directly
to atmosphere from the dehydrator(s) during periods of time when
emissions were not routed to the vapor recovery system, flare, or
regenerator firebox/fire tubes by determining of the number of
depressurization events (including portions of an event) that vented to
atmosphere based on engineering estimate and best available data. You
must take into account periods with reduced capture efficiency of the
vapor recovery system or flare. If emissions are routed to a flare but
the flare is unlit, calculate emissions in accordance with the
methodology specified in paragraph (n) of this section and report
emissions from the flare as specified in Sec. 98.236(n).
(5) Combustion emissions from routing to regenerator firebox/fire
tubes or other non-flare combustion unit. If any glycol dehydrator
emissions are routed to a regenerator firebox/fire tubes or other non-
flare combustion unit, calculate emissions from these devices
attributable to dehydrator flash tank vents or still vents as specified
in paragraphs (e)(5)(i) through (iii) of this section. If any desiccant
dehydrator emissions are routed to a non-flare combustion unit,
calculate combusted emissions as specified in paragraphs (e)(5)(i)
through (iii) of this section. If you operate a CEMS to monitor the
emissions from the regenerator firebox/fire tubes or other non-flare
combustion unit, calculate emissions as specified in paragraph
(e)(5)(iv) of this section.
(i) Determine the volume of the total emissions that is routed to a
regenerator firebox/fire tubes or other non-flare combustion unit as
specified in paragraph (e)(5)(i)(A) or (B) of this section.
(A) Measure the flow from the dehydrator(s) to the regenerator
firebox/fire tubes or other non-flare combustion unit using a
continuous flow measurement device. If you continuously measure flow to
the
[[Page 42249]]
regenerator firebox/fire tubes or other non-flare combustion unit, you
must use the measured volumes to calculate emissions from the
regenerator firebox/fire tubes or other non-flare combustion unit.
(B) Using engineering estimates based on best available data,
determine the volume of the total emissions estimated in paragraph
(e)(1), (2), or (3) of this section, as applicable, that is routed to
the regenerator firebox/fire tubes or other non-flare combustion unit.
(ii) Determine composition of the gas routed to a regenerator
firebox/fire tubes or other non-flare combustion unit as specified in
paragraph (e)(5)(ii)(A) or (B) of this section.
(A) Use the appropriate vent emissions as determined in paragraph
(e)(1) or (2) of this section.
(B) Measure the composition of the gas from the dehydrator(s) to
the regenerator firebox/fire tubes or other non-flare combustion unit
using a continuous composition analyzer. If you continuously measure
gas composition, then those measured data must be used to calculate
dehydrator emissions from the regenerator firebox/fire tubes.
(iii) Determine GHG volumetric emissions at actual conditions from
the regenerator firebox/fire tubes or other non-flare combustion unit
using equations W-39A, W-39B, and W-40 to this section. Calculate GHG
volumetric emissions at standard conditions using calculations in
paragraph (t) of this section. Calculate both GHG mass emissions from
volumetric emissions using calculations in paragraph (v) of this
section.
(iv) If you operate and maintain a CEMS that has both a
CO2 concentration monitor and volumetric flow rate monitor
for the combustion gases from the regenerator firebox/fire tubes or
other non-flare combustion unit, you must calculate only CO2
emissions for the regenerator firebox/fire tubes. You must follow the
Tier 4 Calculation Method and all associated calculation, quality
assurance, reporting, and recordkeeping requirements for Tier 4 in
subpart C of this part (General Stationary Fuel Combustion Sources). If
a CEMS is used to calculate emissions from a regenerator firebox/fire
tubes or other non-flare combustion unit, the requirements specified in
paragraphs (e)(5)(ii) and (iii) of this section are not required.
(f) Well venting for liquids unloadings. Calculate annual
volumetric natural gas emissions from well venting for liquids
unloading when the well is unloaded to the atmosphere using one of the
calculation methods described in paragraph (f)(1), (2), or (3) of this
section. Calculate annual CH4 and CO2 volumetric
and mass emissions using the method described in paragraph (f)(4) of
this section. If emissions from well venting for liquids unloading are
routed to a flare, you must calculate CH4, CO2,
and N2O annual emissions as specified in paragraph (n) of
this section and report emissions from the flare as specified in Sec.
98.236(n).
(1) Calculation Method 1. Calculate emissions from manual and
automated unloadings at wells with plunger lifts and wells without
plunger lifts separately. For at least one well of each unique well
tubing diameter group and pressure group combination in each sub-basin
category (see Sec. 98.238 for the definitions of tubing diameter
group, pressure group, and sub-basin category), where gas wells are
vented directly to the atmosphere to expel liquids accumulated in the
tubing, install a recording flow meter on the vent line used to vent
gas from the well (e.g., on the vent line off the wellhead separator or
atmospheric storage tank) according to methods set forth in Sec.
98.234(b). Calculate the total emissions from well venting to the
atmosphere for liquids unloading using equation W-7A to this section.
Equation W-7A to this section must be used for each unloading type
combination (automated plunger lift unloadings, manual plunger lift
unloadings, automated unloadings without plunger lifts and manual
unloadings without plunger lifts) for any tubing diameter group and
pressure group combination in each sub-basin.
[GRAPHIC] [TIFF OMITTED] TR14MY24.053
Where:
Ea = Annual natural gas emissions for each well of the
same tubing diameter group and pressure group combination in the
sub-basin at actual conditions, a, in cubic feet. Calculate
emissions from wells with automated plunger lift unloadings, wells
with manual plunger lift unloadings, wells with automated unloadings
without plunger lifts and wells with manual unloadings without
plunger lifts separately.
FR = Average flow rate in cubic feet per hour for all measured wells
of the same tubing diameter group and pressure group combination in
a sub-basin, over the duration of the liquids unloading, under
actual conditions as determined in paragraph (f)(1)(i) of this
section.
Tp = Cumulative amount of time in hours of venting for
each well, p, of the same tubing diameter group and pressure group
combination in a sub-basin during the year. If the available venting
data do not contain a record of the date of the venting events and
data are not available to provide the venting hours for the specific
time period of January 1 to December 31, you may calculate an
annualized vent time, Tp, using equation W-7B to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.054
Where:
HRp = Cumulative amount of time in hours of venting for
each well, p, during the monitoring period.
MPp = Time period, in days, of the monitoring period for
each well, p. A minimum of 300 days in a calendar year are required.
The next period of data collection must start immediately following
the end of data collection for the previous reporting year.
Dp = Time period, in days during which the well, p, was
in production (365 if the well was in production for the entire
year).
(i) Determine the well vent average flow rate (``FR'' in equation
W-7A to this section) as specified in paragraphs (f)(1)(i)(A) through
(C) of this section for at least one well in a unique well tubing
diameter group and pressure group combination in each sub-basin
category. Calculate emissions from wells with automated plunger lift
unloadings, wells with manual plunger lift unloadings, wells with
automated unloadings without plunger lifts and wells with manual
unloadings without plunger lifts separately.
(A) Calculate the average flow rate per hour of venting for each
unique tubing
[[Page 42250]]
diameter group and pressure group combination in each sub-basin
category by dividing the recorded total annual flow by the recorded
time (in hours) for all measured liquid unloading events with venting
to the atmosphere.
(B) Apply the average hourly flow rate calculated under paragraph
(f)(1)(i)(A) of this section to each well in the same pressure group
that have the same tubing diameter group, for the number of hours of
each well is venting to the atmosphere.
(C) Calculate a new average flow rate every other calendar year
starting with the first calendar year of data collection. For a new
producing sub-basin category, calculate an average flow rate beginning
in the first year of production.
(ii) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
(2) Calculation Method 2. Calculate the total emissions for each
well from manual and automated well venting to the atmosphere for
liquids unloading without plunger lift assist using equation W-8 to
this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.055
Where:
Es = Annual natural gas emissions for each well at
standard conditions, s, in cubic feet per year
Np = Total number of unloading events in the monitoring
period per well, p.
0.37x10-3 = {3.14 (pi)/4{time} /{14.7*144{time} (psia
converted to pounds per square feet).
CDp = Casing internal diameter for well, p, in inches or
the tubing diameter for well, p, when stoppage packers are used in
the annulus to restrict flow of gas up the annulus to the surface.
WDp = Vertical well depth from either the top of the well
or the lowest packer to the bottom of the well or the top of the
fluid column, for well, p, in feet. For horizontal wells the bottom
of the well is the point at which the vertical borehole pivots to a
horizontal direction.
SPp = For well, p, shut-in pressure or surface pressure
for wells with tubing production, or casing pressure for each well
with no packers, in pounds per square inch absolute (psia). If
casing pressure is not available for the well, you may determine the
casing pressure by multiplying the tubing pressure of the well with
a ratio of casing pressure to tubing pressure from a well in the
same sub-basin for which the casing pressure is known. The tubing
pressure must be measured during gas flow to a flow-line. The shut-
in pressure, surface pressure, or casing pressure must be determined
just prior to liquids unloading when the well production is impeded
by liquids loading or closed to the flow-line by surface valves.
SFRp = Average flow-line rate of gas for well, p, at
standard conditions in cubic feet per hour. Use equation W-33 to
this section to calculate the average flow-line rate at standard
conditions.
HRp,q = Hours that well, p, was left open to the
atmosphere during each unloading event, q.
1.0 = Hours for average well to blowdown casing volume at shut-in
pressure.
q = Unloading event.
Zp,q = If HRp,q is less than 1.0 then Zp,q is equal to 0.
If HRp,q is greater than or equal to 1.0 then Zp,q is equal to 1.
(3) Calculation Method 3. Calculate the total emissions for each
sub-basin from well venting to the atmosphere for liquids unloading
with plunger lift assist using equation W-9 to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.056
Where:
Es = Annual natural gas emissions for each well at
standard conditions, s, in cubic feet per year.
Np = Total number of unloading events in the monitoring
period per well, p.
0.37x10-3 = {3.14 (pi)/4{time} /{14.7*144{time} (psia
converted to pounds per square feet).
TDp = Tubing internal diameter for well, p, in inches.
WDp = Tubing depth to plunger bumper or to the top of the
fluid column for well, p, in feet.
SPp = Flow-line pressure for well p in pounds per square
inch absolute (psia), using engineering estimate based on best
available data.
SFRp = Average flow-line rate of gas for well, p, at
standard conditions in cubic feet per hour. Use equation W-33 to
this section to calculate the average flow-line rate at standard
conditions.
HRp,q = Hours that well, p, was left open to the
atmosphere during each unloading event, q.
0.5 = Hours for average well to blowdown tubing volume at flow-line
pressure.
q = Unloading event.
Zp,q = If HRp,q is less than 0.5 then
Zp,q is equal to 0. If HRp,q is greater than
or equal to 0.5 then Zp,q is equal to 1.
(4) Volumetric and mass emissions. Calculate CH4 and
CO2 volumetric and mass emissions from volumetric natural
gas emissions using calculations in paragraphs (u) and (v) of this
section.
(g) Well venting during completions and workovers with hydraulic
fracturing. Calculate annual volumetric natural gas emissions from gas
well and oil well venting during completions and workovers involving
hydraulic fracturing using equation W-10A or equation W-10B to this
section. Equation W-10A to this section applies to well venting when
the gas flowback rate is measured from a specified number of example
completions or workovers in a sub-basin and well type combination and
equation W-10B to this section applies when the gas flowback vent
volume is measured for each completion or workover in a sub-basin and
well type combination. Completion and workover activities are separated
into two periods, an initial period when flowback is routed to open
pits or tanks and a subsequent period when gas content is sufficient to
route the flowback to a separator or when the gas content is sufficient
to allow measurement by the devices specified in paragraph (g)(1) of
this section, regardless of whether a separator is actually utilized.
If you elect to use equation W-10A to this section, you must follow the
procedures specified in paragraph (g)(1) of this section. If you elect
to use equation W-10B to this section, you must use a recording flow
meter installed on the vent line, downstream of a separator and ahead
of
[[Page 42251]]
a flare or vent, to measure the gas flowback. To calculate emissions
during the initial period, you must calculate the gas flowback rate in
the initial flowback period as described in equation W-10B to this
section. Alternatively, you may use a multiphase flow meter placed on
the flow line downstream of the wellhead and ahead of the separator to
directly measure gas flowback during the initial period when flowback
is routed to open pits or tanks. If you use a multiphase flow meter,
measurements must be taken from initiation of flowback to the beginning
of the period of time when sufficient quantities of gas are present to
enable separation. For either equation, emissions must be calculated
separately for completions and workovers, for each sub-basin, and for
each well type combination identified in paragraph (g)(2) of this
section. You must calculate CH4 and CO2
volumetric and mass emissions as specified in paragraph (g)(3) of this
section. If emissions from well venting during completions and
workovers with hydraulic fracturing are routed to a flare, you must
calculate CH4, CO2, and N2O annual
emissions as specified in paragraph (n) of this section, report
emissions from the flare as specified in Sec. 98.236(n), and report
additional information specified in Sec. 98.236(g), as applicable.
[GRAPHIC] [TIFF OMITTED] TR14MY24.057
[GRAPHIC] [TIFF OMITTED] TR14MY24.058
Where:
Es,n = Annual volumetric natural gas emissions in
standard cubic feet from gas venting during well completions or
workovers following hydraulic fracturing for each well.
CW = Total number of completions or workovers using hydraulic
fracturing.
Tp,s = Cumulative amount of time of flowback, after
sufficient quantities of gas are present to enable separation, where
gas vented for each completion or workover, in hours, during the
reporting year. This may include non-contiguous periods of venting.
Tp,i = Cumulative amount of time of flowback to open
tanks/pits, from when gas is first detected until sufficient
quantities of gas are present to enable separation, for each
completion or workover, in hours, during the reporting year. This
may include non-contiguous periods of routing to open tanks/pits but
does not include periods when the oil well ceases to produce fluids
to the surface.
FRMs = Ratio of average gas flowback, during the period
when sufficient quantities of gas are present to enable separation,
of well completions and workovers from hydraulic fracturing to 30-
day production rate for the sub-basin and well type combination,
calculated using procedures specified in paragraph (g)(1)(iii) of
this section.
FRMi = Ratio of initial gas flowback rate during well
completions and workovers from hydraulic fracturing to 30-day gas
production rate for the sub-basin and well type combination,
calculated using procedures specified in paragraph (g)(1)(iv) of
this section, for the period of flow to open tanks/pits.
PRs,p = Average gas production flow rate during the first
30 days of production after each completion of a newly drilled well
or well workover using hydraulic fracturing in standard cubic feet
per hour that was measured in the sub-basin and well type
combination. If applicable, PRs,p may be calculated for oil wells
using procedures specified in paragraph (g)(1)(vii) of this section.
EnFs,p = Volume of N2 injected gas in cubic feet at
standard conditions that was injected into the reservoir during an
energized fracture job or during flowback during each completion or
workover, as determined by using an appropriate meter according to
methods described in Sec. 98.234(b), or by using receipts of gas
purchases that are used for the energized fracture job or injection
during flowback. Convert to standard conditions using paragraph (t)
of this section. If the fracture process did not inject gas into the
reservoir or if the injected gas is CO2 then EnFs,p is 0.
FVs,p = Flow volume of vented gas for each completion or
workover, in standard cubic feet measured using a recording flow
meter (digital or analog) on the vent line to measure gas flowback
during the separation period of the completion or workover according
to methods set forth in Sec. 98.234(b).
FRp,i = Flow rate vented of each completion or workover,
in standard cubic feet per hour during the initial period when
flowback is routed to open pits or tanks from initiation of flowback
to the beginning of the period of time when sufficient quantities of
gas are present to enable separation, measured using a recording
flow meter (digital or analog) on the vent line to measure the
flowback, at the beginning of the period of time when sufficient
quantities of gas are present to enable separation, of the
completion or workover according to methods set forth in Sec.
98.234(b). Alternatively, flow rate during the initial period may be
measured using a multiphase flow meter installed upstream of the
separator capable of accurately measuring gas flow prior to
separation.
Zp,i = If a multiphase flow meter is used to measure
flowback during the initial period, then Zp,i is equal to
1. If flowback is measured using a recording flow meter (digital or
analog) on the vent line to measure the flowback, at the beginning
of the period of time when sufficient quantities of gas are present
to enable separation, then Zp,i is equal to 0.5.
(1) If you elect to use equation W-10A to this section on gas
wells, you must use Calculation Method 1 as specified in paragraph
(g)(1)(i) of this section. If you are unable to measure the gas
flowback rates using a recording flow meter for gas well completions or
workovers as described in Calculation Method 1, for example due to
field conditions, operating conditions, or health and safety
considerations, you may use Calculation Method 2 as specified in
paragraph (g)(1)(ii) of this section to determine the value of
FRMs and FRMi. These values must be based on the
flow rate for flowback gases, once sufficient gas is present to enable
separation. The number of measurements or calculations required to
estimate FRMs and FRMi must be determined
individually for completions and workovers per sub-basin and well type
combination as follows: Complete measurements or calculations for at
least one completion or workover for less than or equal to 25
completions or workovers for each well type combination within a sub-
basin; complete measurements or calculations for at least two
completions or workovers for 26 to 50 completions or workovers for each
sub-basin and well type combination; complete
[[Page 42252]]
measurements or calculations for at least three completions or
workovers for 51 to 100 completions or workovers for each sub-basin and
well type combination; complete measurements or calculations for at
least four completions or workovers for 101 to 250 completions or
workovers for each sub-basin and well type combination; and complete
measurements or calculations for at least five completions or workovers
for greater than 250 completions or workovers for each sub-basin and
well type combination.
(i) Calculation Method 1. You must use equation W-12A to this
section as specified in paragraph (g)(1)(iii) of this section to
determine the value of FRMs. You must use equation W-12B to
this section as specified in paragraph (g)(1)(iv) of this section to
determine the value of FRMi. The procedures specified in
paragraphs (g)(1)(v) and (vi) of this section also apply. When making
gas flowback measurements for use in equations W-12A and W-12B to this
section, you must use a recording flow meter (digital or analog)
installed on the vent line, downstream of a separator and ahead of a
flare or vent, to measure the gas flowback rates in units of standard
cubic feet per hour according to methods set forth in Sec. 98.234(b).
Alternatively, you may use a multiphase flow meter placed on the flow
line downstream of the wellhead and ahead of the separator to directly
measure gas flowback during the initial period when flowback is routed
to open pits or tanks. If you use a multiphase flow meter, measurements
must be taken from initiation of flowback to the beginning of the
period of time when sufficient quantities of gas are present to enable
separation.
(ii) Calculation Method 2 (for gas wells). You must use equation W-
12A to this section as specified in paragraph (g)(1)(iii) of this
section to determine the value of FRMs. You must use
equation W-12B to this section as specified in paragraph (g)(1)(iv) of
this section to determine the value of FRMi. The procedures
specified in paragraphs (g)(1)(v) and (vi) also apply. When calculating
the flowback rates for use in equations W-12A and W-12B to this section
based on well parameters, you must record the well flowing pressure
immediately upstream (and immediately downstream in subsonic flow) of a
well choke according to methods set forth in Sec. 98.234(b) to
calculate the well flowback. The upstream pressure must be surface
pressure and reservoir pressure cannot be assumed. The downstream
pressure must be measured after the choke and atmospheric pressure
cannot be assumed. Calculate flowback rate using equation W-11A to this
section for subsonic flow or equation W-11B to this section for sonic
flow. You must use best engineering estimates based on best available
data along with equation W-11C to this section to determine whether the
predominant flow is sonic or subsonic. If the value of R in equation W-
11C to this section is greater than or equal to 2, then flow is sonic;
otherwise, flow is subsonic. Convert calculated FRa values
from actual conditions upstream of the restriction orifice to standard
conditions (FRs,p and FRi,p) for use in equations
W-12A and W-12B to this section using equation W-33 to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.059
Where:
FRa = Flowback rate in actual cubic feet per hour, under
actual subsonic flow conditions.
A = Cross sectional open area of the restriction orifice
(m2).
P1 = Pressure immediately upstream of the choke (psia).
Tu = Temperature immediately upstream of the choke
(degrees Kelvin).
P2 = Pressure immediately downstream of the choke (psia).
3430 = Constant with units of m2/(sec2 * K).
1.27*105 = Conversion from m3/second to
ft3/hour.
[GRAPHIC] [TIFF OMITTED] TR14MY24.060
Where:
FRa = Flowback rate in actual cubic feet per hour, under
actual sonic flow conditions.
A = Cross sectional open area of the restriction orifice
(m2).
Tu = Temperature immediately upstream of the choke
(degrees Kelvin).
187.08 = Constant with units of m2/(sec2 * K).
1.27*105 = Conversion from m3/second to
ft3/hour.
[GRAPHIC] [TIFF OMITTED] TR14MY24.061
Where:
R = Pressure ratio.
P1 = Pressure immediately upstream of the choke (psia).
P2 = Pressure immediately downstream of the choke (psia).
(iii) For equation W-10A to this section, calculate FRMs using
equation W-12A to this section.
[[Page 42253]]
[GRAPHIC] [TIFF OMITTED] TR14MY24.062
Where:
FRMs = Ratio of average gas flowback rate, during the
period of time when sufficient quantities of gas are present to
enable separation, of well completions and workovers from hydraulic
fracturing to 30-day gas production rate for each sub-basin and well
type combination.
FRs,p = Measured average gas flowback rate from
Calculation Method 1 described in paragraph (g)(1)(i) of this
section or calculated average flowback rate from Calculation Method
2 described in paragraph (g)(1)(ii) of this section, during the
separation period in standard cubic feet per hour for well(s) p for
each sub-basin and well type combination. Convert measured and
calculated FRa values from actual conditions upstream of
the restriction orifice (FRa) to standard conditions
(FRs,p) for each well p using equation W-33 to this
section. You may not use flow volume as used in equation W-10B to
this section converted to a flow rate for this parameter.
PRs,p = Average gas production flow rate during the first
30 days of production after completions of newly drilled wells or
well workovers using hydraulic fracturing, in standard cubic feet
per hour for each well, p, that was measured in the sub-basin and
well type combination. For oil wells for which production is not
measured continuously during the first 30 days of production, the
average flow rate may be based on individual well production tests
conducted within the first 30 days of production. Alternatively, if
applicable, PRs,p may be calculated for oil wells using
procedures specified in paragraph (g)(1)(vii) of this section.
N = Number of measured or calculated well completions or workovers
using hydraulic fracturing in a sub-basin and well type combination.
(iv) For equation W-10A to this section, calculate FRMi using
equation W-12B to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.063
Where:
FRMi = Ratio of initial gas flowback rate during well
completions and workovers from hydraulic fracturing to 30-day gas
production rate for the sub-basin and well type combination, for the
period of flow to open tanks/pits.
FRi,p = Initial measured gas flowback rate from
Calculation Method 1 described in paragraph (g)(1)(i) of this
section or initial calculated flow rate from Calculation Method 2
described in paragraph (g)(1)(ii) of this section in standard cubic
feet per hour for well(s), p, for each sub-basin and well type
combination. Measured and calculated FRi,p values must be
based on flow conditions at the beginning of the separation period
and must be expressed at standard conditions or measured using a
multiphase flow meter installed upstream of the separator capable of
accurately measuring gas flow prior to separation.
PRs,p = Average gas production flow rate during the first
30-days of production after completions of newly drilled wells or
well workovers using hydraulic fracturing, in standard cubic feet
per hour of each well, p, that was measured in the sub-basin and
well type combination. For oil wells for which production is not
measured continuously during the first 30 days of production, the
average flow rate may be based on individual well production tests
conducted within the first 30 days of production. Alternatively, if
applicable, PRs,p may be calculated for oil wells using
procedures specified in paragraph (g)(1)(vii) of this section.
N = Number of measured or calculated well completions or workovers
using hydraulic fracturing in a sub-basin and well type combination.
(v) For equation W-10A to this section, the ratio of gas flowback
rate during well completions and workovers from hydraulic fracturing to
30-day gas production rate are applied to all well completions and well
workovers, respectively, in the sub-basin and well type combination for
the total number of hours of flowback and for the first 30 day average
gas production rate for each of these wells.
(vi) For equations W-12A and W-12B to this section, calculate new
flowback rates for well completions and well workovers in each sub-
basin and well type combination once every two years starting in the
first calendar year of data collection.
(vii) For oil wells where the gas production rate is not metered
and you elect to use equation W-10A to this section, calculate the
average gas production rate (PRs,p) using equation W-12C to
this section. If GOR cannot be determined from your available data,
then you must use one of the procedures specified in paragraph
(g)(1)(vii)(A) or (B) of this section to determine GOR. If GOR from
each well is not available, use the GOR from a cluster of wells in the
same sub-basin category.
[GRAPHIC] [TIFF OMITTED] TR14MY24.064
Where:
PRs,p = Average gas production flow rate during the first
30 days of production after completions of newly drilled wells or
well workovers using hydraulic fracturing in standard cubic feet per
hour of well p, in the sub-basin and well type combination.
GORp = Average gas to oil ratio during the first 30 days
of production after completions of newly drilled wells or workovers
using hydraulic fracturing in
[[Page 42254]]
standard cubic feet of gas per barrel of oil for each well p, that
was measured in the sub-basin and well type combination; oil here
refers to hydrocarbon liquids produced of all API gravities.
Vp = Volume of oil produced during the first 30 days of
production after completions of newly drilled wells or well
workovers using hydraulic fracturing in barrels of each well p, that
was measured in the sub-basin and well type combination.
720 = Conversion from 30 days of production to hourly production
rate.
(A) You may use an appropriate standard method published by a
consensus-based standards organization if such a method exists.
(B) You may use an industry standard practice as described in Sec.
98.234(b).
(2) For paragraphs (g) introductory text and (g)(1) of this
section, measurements and calculations are completed separately for
workovers and completions per sub-basin and well type combination. A
well type combination is a unique combination of the parameters listed
in paragraphs (g)(2)(i) through (iv) of this section.
(i) Vertical or horizontal (directional drilling).
(ii) With flaring or without flaring.
(iii) Reduced emission completion/workover or not reduced emission
completion/workover.
(iv) Oil well or gas well.
(3) Calculate both CH4 and CO2 volumetric and
mass emissions from total natural gas volumetric emissions using
calculations in paragraphs (u) and (v) of this section.
(h) Gas well venting during completions and workovers without
hydraulic fracturing. Calculate annual volumetric natural gas emissions
from each gas well venting during workovers without hydraulic
fracturing using equation W-13A to this section. Calculate annual
volumetric natural gas emissions from each gas well venting during
completions without hydraulic fracturing using equation W-13B to this
section. You must convert annual volumetric natural gas emissions to
CH4 and CO2 volumetric and mass emissions as
specified in paragraph (h)(1) of this section. If emissions from gas
well venting during completions and workovers without hydraulic
fracturing are routed to a flare, you must calculate CH4,
CO2, and N2O annual emissions as specified in
paragraph (n) of this section, report emissions from the flare as
specified in Sec. 98.236(n), and report additional information
specified in Sec. 98.236(h), as applicable.
[GRAPHIC] [TIFF OMITTED] TR14MY24.065
[GRAPHIC] [TIFF OMITTED] TR14MY24.066
Where:
Es,wo = Annual volumetric natural gas emissions in
standard cubic feet from gas well venting during well workovers
without hydraulic fracturing.
Nwo = Number of workovers per well that do not involve
hydraulic fracturing in the reporting year.
EFwo = Emission factor for non-hydraulic fracture well
workover venting in standard cubic feet per workover. Use 3,114
standard cubic feet natural gas per well workover without hydraulic
fracturing.
Es,p = Annual volumetric natural gas emissions in
standard cubic feet from gas well venting during well completions
without hydraulic fracturing.
Vp = Average daily gas production rate in standard cubic
feet per hour for each well, p, undergoing completion without
hydraulic fracturing. This is the total annual gas production volume
divided by total number of hours the well produced to the flow-line.
For completed wells that have not established a production rate, you
may use the average flow rate from the first 30 days of production.
In the event that the well is completed less than 30 days from the
end of the calendar year, the first 30 days of the production
straddling the current and following calendar years shall be used.
Tp = Time that gas is vented directly to the atmosphere
for each well, p, undergoing completion without hydraulic
fracturing, in hours during the year.
(1) Calculate both CH4 and CO2 volumetric
emissions from natural gas volumetric emissions using calculations in
paragraph (u) of this section. Calculate both CH4 and
CO2 mass emissions from volumetric emissions vented to
atmosphere using calculations in paragraph (v) of this section.
(2) [Reserved]
(i) Blowdown vent stacks. Calculate CO2 and
CH4 blowdown vent stack emissions from the depressurization
of equipment to reduce system pressure for planned or emergency
shutdowns resulting from human intervention or to take equipment out of
service for maintenance as specified in either paragraph (i)(2) or (3)
of this section. You may use the method in paragraph (i)(2) of this
section for some blowdown vent stacks at your facility and the method
in paragraph (i)(3) of this section for other blowdown vent stacks at
your facility. For industry segments other than natural gas
distribution, equipment with a unique physical volume of less than 50
cubic feet as determined in paragraph (i)(1) of this section are not
subject to the requirements in paragraphs (i)(2) through (4) of this
section. Natural gas distribution blowdowns with a unique physical
volume of less than 500 cubic feet as determined in paragraph (i)(1) of
this section are not subject to the requirements in paragraphs (i)(2)
through (4) of this section. The requirements in this paragraph (i) do
not apply to blowdown vent stack emissions from depressurizing to a
flare, over-pressure relief, operating pressure control venting,
blowdown of non-GHG gases, and desiccant dehydrator blowdown venting
before reloading. If emissions from blowdown vent stacks are routed to
a flare, you must calculate CH4, CO2, and
N2O annual emissions as specified in paragraph (n) of this
section and report emissions from the flare as specified in Sec.
98.236(n).
(1) Method for calculating unique physical volumes or distribution
pipeline physical volumes. You must calculate each unique physical
volume (including pipelines, compressor case or cylinders, manifolds,
suction bottles, discharge bottles, and vessels) between isolation
valves, in cubic feet, by using engineering estimates based on best
available data. For natural gas distribution pipelines without
isolation valves, calculate the unique physical volume of the
distribution pipeline section that was isolated from operation by
methods other than isolation valves, in cubic feet, by using
engineering estimates based on best available data (e.g., diameter of
the pipeline and length of isolated section).
(2) Method for determining emissions from blowdown vent stacks
according to equipment or event type. If you elect to determine
emissions according to each equipment or event type, using unique
physical volumes as calculated in paragraph (i)(1) of this section, you
must calculate emissions as specified in paragraph (i)(2)(i) of this
section and either paragraph (i)(2)(ii) of this section or, if
applicable, paragraph (i)(2)(iii) of
[[Page 42255]]
this section for each equipment or event type. Categorize equipment and
event types for each industry segment as specified in paragraph
(i)(2)(iv) of this section.
(i) Calculate the total annual natural gas emissions from each
unique physical volume that is blown down using either equation W-14A
or W-14B to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.067
Where:
Es,n = Annual natural gas emissions at standard
conditions from each unique physical volume that is blown down, in
cubic feet.
N = Number of occurrences of blowdowns for each unique physical
volume in the calendar year.
V = Unique physical volume, in cubic feet, as calculated in
paragraph (i)(1) of this section.
C = Purge factor is 1 if the unique physical volume is not purged,
or 0 if the unique physical volume is purged using non-GHG gases.
Ts = Temperature at standard conditions (60 [deg]F).
Ta = Temperature at actual conditions in the unique
physical volume ([deg]F). For emergency blowdowns at onshore
petroleum and natural gas production, onshore petroleum and natural
gas gathering and boosting facilities, onshore natural gas
transmission pipeline facilities, and natural gas distribution
facilities, engineering estimates based on best available
information may be used to determine the temperature.
Ps = Absolute pressure at standard conditions (14.7
psia).Pa = Absolute pressure at actual conditions in the
unique physical volume (psia). For emergency blowdowns at onshore
petroleum and natural gas production, onshore petroleum and natural
gas gathering and boosting facilities, onshore natural gas
transmission pipeline facilities, and natural gas distribution
facilities, engineering estimates based on best available
information may be used to determine the pressure.
Za = Compressibility factor at actual conditions for
natural gas. You may use either a default compressibility factor of
1, or a site-specific compressibility factor based on actual
temperature and pressure conditions.
[GRAPHIC] [TIFF OMITTED] TR14MY24.068
Where:
Es,n = Annual natural gas emissions at standard
conditions from each unique physical volume that is blown down, in
cubic feet.
p = Individual occurrence of blowdown for the same unique physical
volume.
N = Number of occurrences of blowdowns for each unique physical
volume in the calendar year.
Vp = Unique physical volume, in cubic feet, for each
blowdown ``p.''
Ts = Temperature at standard conditions (60
[deg]F).Ta,p = Temperature at actual conditions in the
unique physical volume ([deg]F) for each blowdown ``p''. For
emergency blowdowns at onshore petroleum and natural gas production,
onshore petroleum and natural gas gathering and boosting facilities,
onshore natural gas transmission pipeline facilities, and natural
gas distribution facilities, engineering estimates based on best
available information may be used to determine the temperature.
Ps = Absolute pressure at standard conditions (14.7
psia).
Pa,b,p = Absolute pressure at actual conditions in the
unique physical volume (psia) at the beginning of the blowdown
``p''. For emergency blowdowns at onshore petroleum and natural gas
production, onshore petroleum and natural gas gathering and boosting
facilities, onshore natural gas transmission pipeline facilities,
and natural gas distribution facilities, engineering estimates based
on best available information may be used to determine the pressure
at the beginning of the blowdown.
Pa,e,p = Absolute pressure at actual conditions in the
unique physical volume (psia) at the end of the blowdown ``p''; 0 if
blowdown volume is purged using non-GHG gases. For emergency
blowdowns at onshore petroleum and natural gas production, onshore
petroleum and natural gas gathering and boosting facilities, onshore
natural gas transmission pipeline facilities, and natural gas
distribution facilities, engineering estimates based on best
available information may be used to determine the pressure at the
end of the blowdown.
Za = Compressibility factor at actual conditions for
natural gas. You may use either a default compressibility factor of
1, or a site-specific compressibility factor based on actual
temperature and pressure conditions.
(ii) Except as allowed in paragraph (i)(2)(iii) of this section,
calculate annual CH4 and CO2 volumetric and mass
emissions from each unique physical volume that is blown down by using
the annual natural gas emission value as calculated in either equation
W-14A or equation W-14B to this section and the calculation method
specified in paragraph (i)(4) of this section. Calculate the total
annual CH4 and CO2 emissions for each equipment
or event type by summing the annual CH4 and CO2
mass emissions for all unique physical volumes associated with the
equipment or event type.
(iii) For onshore natural gas transmission compression facilities
and LNG import and export equipment, as an alternative to using the
procedures in paragraph (i)(2)(ii) of this section, you may elect to
sum the annual natural gas emissions as calculated using either
equation W-14A or equation W-14B to this section for all unique
physical volumes associated with the equipment type or event type.
Calculate the total annual CH4 and CO2 volumetric
and mass emissions for each equipment type or event type using the sums
of the total annual natural gas emissions for each equipment type and
the calculation method specified in paragraph (i)(4) of this section.
(iv) Categorize blowdown vent stack emission events as specified in
paragraphs (i)(2)(iv)(A) and (B) of this section, as applicable.
(A) For the onshore petroleum and natural gas production, onshore
natural gas processing, onshore natural gas transmission compression,
underground natural gas storage, LNG storage, LNG import and export
equipment, and onshore petroleum and natural gas gathering and boosting
industry segments, equipment or event types must be grouped into the
following seven categories: Facility piping (i.e.,
[[Page 42256]]
physical volumes associated with piping for which the entire physical
volume is located within the facility boundary), pipeline venting
(i.e., physical volumes associated with pipelines for which a portion
of the physical volume is located outside the facility boundary and the
remainder, including the blowdown vent stack, is located within the
facility boundary), compressors, scrubbers/strainers, pig launchers and
receivers, emergency shutdowns (this category includes emergency
shutdown blowdown emissions regardless of equipment type), and all
other equipment with a physical volume greater than or equal to 50
cubic feet. If a blowdown event resulted in emissions from multiple
equipment types and the emissions cannot be apportioned to the
different equipment types, then categorize the blowdown event as the
equipment type that represented the largest portion of the emissions
for the blowdown event.
(B) For the onshore natural gas transmission pipeline and natural
gas distribution industry segments, pipeline segments or event types
must be grouped into the following eight categories: Pipeline integrity
work (e.g., the preparation work of modifying facilities, ongoing
assessments, maintenance or mitigation), traditional operations or
pipeline maintenance, equipment replacement or repair (e.g., valves),
pipe abandonment, new construction or modification of pipelines
including commissioning and change of service, operational precaution
during activities (e.g. excavation near pipelines), emergency shutdowns
including pipeline incidents as defined in 49 CFR 191.3, and all other
pipeline segments with a physical volume greater than or equal to 50
cubic feet. If a blowdown event resulted in emissions from multiple
categories and the emissions cannot be apportioned to the different
categories, then categorize the blowdown event in the category that
represented the largest portion of the emissions for the blowdown
event.
(3) Method for determining emissions from blowdown vent stacks
using a flow meter. In lieu of determining emissions from blowdown vent
stacks as specified in paragraph (i)(2) of this section, you may use a
flow meter and measure blowdown vent stack emissions for any unique
physical volumes determined according to paragraph (i)(1) of this
section to be greater than or equal to 50 cubic feet. If you choose to
use this method, you must measure the natural gas emissions from the
blowdown(s) through the monitored stack(s) using a flow meter according
to methods in Sec. 98.234(b) and calculate annual CH4 and
CO2 volumetric and mass emissions measured by the meters
according to paragraph (i)(4) of this section.
(4) Method for converting from natural gas emissions to GHG
volumetric and mass emissions. Calculate both CH4 and
CO2 volumetric and mass emissions using the methods
specified in paragraphs (u) and (v) of this section.
(j) Hydrocarbon liquids and produced water storage tanks. Calculate
CH4 and CO2 emissions from atmospheric pressure
storage tanks receiving hydrocarbon liquids and CH4
emissions from atmospheric pressure storage tanks receiving produced
water, from onshore petroleum and natural gas production facilities,
onshore petroleum and natural gas gathering and boosting facilities
(including stationary liquid storage not owned or operated by the
reporter), and onshore natural gas processing facilities as specified
in this paragraph (j). For wells, gas-liquid separators, or onshore
petroleum and natural gas gathering and boosting or onshore natural gas
processing non-separator equipment (e.g., stabilizers, slug catchers)
with annual average daily throughput of hydrocarbon liquids greater
than or equal to 10 barrels per day, calculate annual CH4
and CO2 using Calculation Method 1 or 2 as specified in
paragraphs (j)(1) and (2) of this section. For wells, gas-liquid
separators, or non-separator equipment with annual average daily
throughput of hydrocarbon liquids greater than 0 barrels per day and
less than 10 barrels per day, calculate annual CH4 and
CO2 emissions using Calculation Method 1, 2, or 3 as
specified in paragraphs (j)(1) through (3) of this section. Annual
average daily throughput of hydrocarbon liquids should be calculated
using the flow out of the separator, well, or non-separator equipment
determined over the actual days of operation. For atmospheric pressure
storage tanks receiving produced water, calculate annual CH4
emissions using Calculation Method 1, 2, or 3 as specified in
paragraphs (j)(1) through (3) of this section. If you are required to
use the flash emissions modeling software in paragraph (j)(1) of this
section for compliance with federal or state regulations, air permit
requirements, or annual inventory reporting for the current reporting
year, you must use Calculation Method 1 to calculate annual
CH4 and, if applicable, CO2 emissions. For
atmospheric pressure storage tanks routing emissions to a vapor
recovery system or a flare, calculate annual emissions vented directly
to atmosphere as specified in paragraph (j)(4) of this section. If you
use Calculation Method 1 or Calculation Method 2 for gas-liquid
separators sending hydrocarbon liquids to atmospheric pressure storage
tanks, you must also calculate emissions that may have occurred due to
hydrocarbon liquid dump valves not closing properly using the method
specified in paragraph (j)(5) of this section. If emissions from
atmospheric pressure storage tanks are routed to a flare, you must
calculate CH4, CO2, and N2O emissions
for the flare stack as specified in paragraph (n) of this section and
report emissions from the flare as specified in Sec. 98.236(n).
(1) Calculation Method 1. For atmospheric pressure storage tanks
receiving hydrocarbon liquids, calculate annual CH4 and
CO2 emissions, and for atmospheric pressure tanks receiving
produced water, calculate annual CH4 emissions, using
operating conditions in the well, last gas-liquid separator, or last
non-separator equipment before liquid transfer to storage tanks.
Calculate flashing emissions with a software program, such as AspenTech
HYSYS[supreg], Bryan Research & Engineering ProMax[supreg], or, for
atmospheric pressure storage tanks receiving hydrocarbon liquids from
gas-liquid separator or non-separator equipment, API 4697 E&P Tank,
that uses the Peng-Robinson equation of state, models flashing
emissions, and speciates CH4 and CO2 emissions
that will result when the hydrocarbon liquids or produced water from
the well, separator, or non-separator equipment enter an atmospheric
pressure storage tank. If you elect to use ProMax[supreg], you must use
version 5.0 or above. A minimum of the parameters listed in paragraphs
(j)(1)(i) through (vii) of this section, as applicable, must be used to
characterize emissions. If paragraphs (j)(1)(i) through (vii) of this
section indicate that an applicable parameter must be measured, collect
measurements reflective of representative operating conditions for the
time period covered by the simulation and at least at the frequency
specified. Determine all other applicable parameters in paragraphs
(j)(1)(i) through (vii) of this section by engineering estimate and
process knowledge based on best available data and, if necessary,
adjust parameters to represent the operating conditions over the time
period covered by the simulation. Determine the number of simulations
and associated time periods such that the simulations cover the entire
reporting year (i.e., if you calculate emissions using one simulation,
use representative parameters for the operating conditions
[[Page 42257]]
over the calendar year; if you use periodic simulations to cover the
calendar year, use parameters for the operating conditions over each
corresponding appropriate portion of the calendar year). If more than
one simulation is performed, input parameters should be remeasured if
no longer representative of operating conditions.
(i) Well, separator, or non-separator equipment temperature (must
be measured at least annually if required as an input for the model).
(ii) Well, separator, or non-separator equipment pressure (must be
measured at least annually if required as an input for the model).
(iii) [Reserved]
(iv) Sales or stabilized hydrocarbon liquids or produced water
production rate (must be measured at least annually if required as an
input for the model).
(v) Ambient air temperature.
(vi) Ambient air pressure.
(vii) Sales or stabilized hydrocarbon liquids API gravity, and
well, separator, or non-separator equipment hydrocarbon liquids or
produced water composition and Reid vapor pressure (must be measured if
required as an input for the model). Use an appropriate standard method
published by a consensus-based standards organization if such a method
exists or you may use an industry standard practice as specified in
Sec. 98.234(b) to sample and analyze sales or stabilized hydrocarbon
liquids for API gravity, and hydrocarbon liquids or produced water
composition and Reid vapor pressure. You must sample and analyze sales
or stabilized oil for API gravity, and hydrocarbon liquids or produced
water for composition and Reid vapor pressure within six months of
equipment start-up or by January 1, 2030, whichever is later, and at
least once every five years thereafter. Until such time that a sample
is collected, determine API gravity by engineering estimate and process
knowledge based on best available data, and determine composition and
Reid vapor pressure by using one of the methods described in paragraphs
(j)(1)(vii)(A) through (C) of this section. For produced water, you may
instead elect to use a representative sales oil or stabilized
hydrocarbon liquid API gravity and a hydrocarbon liquid composition and
Reid vapor pressure, and assume oil entrainment of 1 percent or
greater.
(A) If separator or non-separator equipment hydrocarbon liquids
composition and Reid vapor pressure default data are provided with the
software program, select the default values that most closely match
your separator or non-separator equipment pressure first, and API
gravity secondarily.
(B) If separator or non-separator equipment hydrocarbon liquids
composition and Reid vapor pressure data are available through your
previous analysis, select the latest available analysis that is
representative of hydrocarbon liquids from the sub-basin category for
onshore petroleum and natural gas production or from the county for
onshore petroleum and natural gas gathering and boosting.
(C) Analyze a representative sample of separator or non-separator
equipment hydrocarbon liquids in each sub-basin category for onshore
petroleum and natural gas production or each county for onshore
petroleum and natural gas gathering and boosting for hydrocarbon
liquids composition and Reid vapor pressure using an appropriate
standard method published by a consensus-based standards organization.
(2) Calculation Method 2. For atmospheric pressure storage tanks
receiving hydrocarbon liquids, calculate annual CH4 and
CO2 emissions and for atmospheric pressure tanks receiving
produced water, calculate annual CH4 emissions, using
operating conditions in the well, last gas-liquid separator, or last
non-separator equipment before liquid transfer to storage tanks and the
methods in paragraph (j)(2)(i) of this section.
(i) Assume that all of the CH4 and, if applicable,
CO2 in solution at well, separator, or non-separator
equipment temperature and pressure is emitted from hydrocarbon liquids
or produced water sent to atmospheric pressure storage tanks. You may
use an appropriate standard method published by a consensus-based
standards organization if such a method exists or you may use an
industry standard practice as described in Sec. 98.234(b) to sample
and analyze hydrocarbon liquids or produced water composition at well,
separator, or non-separator pressure and temperature. You must sample
and analyze hydrocarbon liquids or produced water composition within
six months of equipment start-up or by January 1, 2030, whichever is
later, and at least once every five years thereafter. Until such time
that a sample is collected, determine produced water composition by
engineering estimate and process knowledge based on best available
data, and determine hydrocarbon liquids composition by using one of the
methods described in paragraphs (j)(1)(vii)(A) through (C) of this
section. For produced water, you may instead elect to use a
representative hydrocarbon liquid composition and assume oil
entrainment of 1 percent or greater.
(ii) [Reserved]
(3) Calculation Method 3. Calculate CH4 and
CO2 emissions from atmospheric pressure storage tanks
receiving hydrocarbon liquids as specified in paragraph (j)(3)(i) of
this section. Calculate CH4 emissions from atmospheric
pressure storage tanks receiving produced water as specified in
paragraph (j)(3)(ii) of this section.
(i) Calculate CH4 and CO2 emissions from
atmospheric pressure storage tanks receiving hydrocarbon liquids using
equation W-15A to this section:
[GRAPHIC] [TIFF OMITTED] TR14MY24.069
Where:
Es,i = Annual total volumetric GHG emissions (either
CO2 or CH4) at standard conditions in cubic
feet.
EFi = Population emission factor for separators, wells,
or non-separator equipment in thousand standard cubic feet per
separator, well, or non-separator equipment per year, for crude oil
use 4.2 for CH4 and 2.8 for CO2 at 60 [deg]F
and 14.7 psia, and for gas condensate use 17.6 for CH4
and 2.8 for CO2 at 60 [deg]F and 14.7 psia.
Count = Total number of separators, wells, or non-separator
equipment with annual average daily throughput greater than 0
barrels per day and less than 10 barrels per day. Count only
separators, wells, or non-separator equipment that feed hydrocarbon
liquids directly to the atmospheric pressure storage tank for which
you elect to use this Calculation Method 3.
1,000 = Conversion from thousand standard cubic feet to standard
cubic feet.
(ii) Calculate CH4 emissions from atmospheric pressure
storage tanks receiving produced water using equation W-15B to this
section:
[[Page 42258]]
[GRAPHIC] [TIFF OMITTED] TR14MY24.070
Where:
MassCH4 = Annual total CH4 emissions in metric
tons.
EFCH4 = Population emission factor for produced water in
metric tons CH4 per thousand barrels produced water per
year. For produced water streams from separators, wells, or non-
separator equipment with pressure less than or equal to 50 psi, use
0.0015. For produced water streams from separators, wells, or non-
separator equipment with pressure greater than 50 but less than or
equal to 250 psi, use 0.0142. For produced water streams from
separators, wells, or non-separator equipment with pressure greater
than 250 psi, use 0.0508. Pressure should be representative of
separators, wells, or non-separator equipment that feed produced
water directly to the atmospheric pressure storage tank.
FR = Annual flow rate of produced water to atmospheric pressure
storage tanks, in barrels.
0.001 = Conversion from barrels to thousand barrels.
(4) Emissions vented directly to atmosphere from atmospheric
pressure storage tanks routed to vapor recovery systems or flares. If
the atmospheric pressure storage tank receiving your hydrocarbon
liquids or produced water has a vapor recovery system or routes
emissions to a flare, calculate annual emissions vented directly to
atmosphere from the storage tank during periods of time when emissions
were not routed to the vapor recovery system or flare as specified in
paragraph (j)(4)(i) of this section. Determine recovered mass as
specified in paragraph (j)(4)(ii) of this section.
(i) For an atmospheric pressure storage tank that routes any
emissions to a vapor recovery system or a flare, calculate vented
emissions as specified in paragraphs (j)(4)(i)(A) through (E) of this
section.
(A) Calculate vented emissions as specified in paragraph (j)(1),
(2), or (3) of this section, which represents the emissions from the
atmospheric storage tank prior to the vapor recovery system or flare.
Calculate an average hourly vented emissions rate by dividing the
vented emissions by the number of hours that the tank was in operation.
(B) To calculate vented emissions during periods when the tank was
not routing emissions to a vapor recovery system or a flare, multiply
the average hourly vented emissions rate determined in paragraph
(j)(4)(i)(A) of this section by the number of hours that the tank
vented directly to the atmosphere. Determine the number of hours that
the tank vented directly to atmosphere by subtracting the hours that
the tank was connected to a vapor recovery system or flare (based on
engineering estimate and best available data) from the total operating
hours for the tank in the calendar year. If emissions are routed to a
flare but the flare is unlit, calculate emissions in accordance with
the methodology specified in paragraph (n) of this section and report
emissions from the flare as specified in Sec. 98.236(n).
(C) During periods when a thief hatch is open and emissions from
the tank are routed to a vapor recovery system or a flare, assume the
capture efficiency of the vapor recovery system or a flare is 0
percent. A thief hatch is open if it is fully or partially open such
there is a visible gap between the hatch cover and the hatch portal. To
calculate vented emissions during such periods, multiply the average
hourly vented emissions rate determined in paragraph (j)(4)(i)(A) of
this section by the number of hours that the thief hatch is open.
Determine the number of hours that the thief hatch is open or not
properly seated as specified in paragraph (j)(7) of this section.
(D) Calculate vented emissions not captured by the vapor recovery
system or a flare due to causes other than open thief hatches based on
best available data, including any data from operating pressure sensors
on atmospheric pressure storage tanks.
(E) Calculate total emissions vented directly to atmosphere as the
sum of the emissions calculated as specified in paragraphs (j)(4)(i)(B)
through (D) of this section.
(ii) Using engineering estimates based on best available data,
determine the portion of the total emissions estimated in paragraphs
(j)(1) through (3) of this section that is recovered using a vapor
recovery system. You must take into account periods with reduced
capture efficiency of the vapor recovery system (e.g., when a thief
hatch is open) when calculating mass recovered as specified in
paragraphs (j)(4)(i)(C) and (D) of this section.
(5) Gas-liquid separator dump valves. If you use Calculation Method
1 or Calculation Method 2 in paragraph (j)(1) or (2) of this section,
calculate emissions from occurrences of gas-liquid separator liquid
dump valves that did not close properly during the calendar year by
using equation W-16 to this section. Determine the total time a dump
valve did not close properly in the calendar year (Tdv) as specified in
paragraph (j)(5)(i) of this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.071
Where:
Es,i,dv = Annual volumetric GHG emissions (either
CO2 or CH4) at standard conditions in cubic
feet from atmospheric pressure storage tanks that resulted from the
dump valve on an associated gas-liquid separator that did not close
properly.
CFdv = Correction factor for tank emissions for time
period Tdv is 2.87 for crude oil production. Correction
factor for tank emissions for time period Tdv is 4.37 for
gas condensate production.
Es,i = Annual volumetric GHG emissions (either
CO2 or CH4) as determined in paragraphs (j)(1)
and (2) and, if applicable, (j)(4) of this section, in standard
cubic feet per year, from atmospheric pressure storage tanks with
dump valves on an associated gas-liquid separator that did not close
properly.
8,760 = Conversion to hourly emissions.
Tdv = Total time a dump valve did not close properly in
the calendar year as determined in paragraph (j)(5)(i) of this
section, in hours.
(i) If a parametric monitor is operating on a controlled
atmospheric pressure storage tank or gas-liquid separator, you must use
data obtained from the parametric monitor to determine periods when the
gas-liquid separator liquid dump valve is stuck in an open or partially
open position. An applicable operating parametric monitor must be
capable of logging data whenever a gas-liquid separator liquid dump
valve is stuck in an open or partially open position, as well as when
the gas-liquid separator liquid dump valve is subsequently closed. If
an applicable parametric monitor is not operating, including during
periods of time when the parametric monitor is malfunctioning, you must
perform a visual inspection of each gas-liquid separator liquid dump
valve to determine if the valve is stuck in an
[[Page 42259]]
open or partially open position, in accordance with paragraph
(j)(5)(i)(A) and (B) of this section.
(A) Audio, visual and olfactory inspections must be conducted at
least once in a calendar year.
(B) If stuck gas-liquid separator liquid dump valve is identified,
the dump valve must be counted as being open since the beginning of the
calendar year, or from the previous audio, visual, and olfactory
inspection that did not identify the dump valve as being stuck in the
open position in the same calendar year. If the dump valve is fixed
following visual inspection, the time period for which the dump valve
was stuck open will end upon being repaired. If a stuck dump valve is
identified and not repaired, the time period for which the dump valve
was stuck open must be counted as having occurred through the rest of
the calendar year.
(ii) [Reserved]
(6) Mass emissions. Calculate both CH4 and
CO2 mass emissions from natural gas volumetric emissions
using calculations in paragraph (v) of this section.
(7) Thief hatches. If a thief hatch sensor is operating on a
controlled atmospheric pressure storage tank, you must use data
obtained from the thief hatch sensor to determine periods when the
thief hatch is open. An applicable operating thief hatch sensor must be
capable of logging data whenever a thief hatch is open, as well as when
the thief hatch is subsequently closed. If a thief hatch sensor is not
operating but a tank pressure sensor is operating on a controlled
atmospheric pressure storage tank, you must use data obtained from the
pressure sensor to determine periods when the thief hatch is open. An
applicable operating pressure sensor must be capable of logging tank
pressure data. If neither an applicable thief hatch sensor nor an
applicable pressure sensor is operating, including during periods of
time when the sensors are malfunctioning, for longer than 30 days, you
must perform a visual inspection of each thief hatch on a controlled
atmospheric pressure storage tank in accordance with paragraph
(j)(7)(i) through (iii) of this section.
(i) For thief hatches on controlled atmospheric pressure storage
tanks subject to the standards in Sec. 60.5395b of this chapter, or an
applicable approved state plan or applicable Federal plan in part 62 of
this chapter, visual inspections must be conducted at least as frequent
as the required audio, visual, and olfactory inspections described in
Sec. 60.5416b or the applicable approved state plan or applicable
Federal plan in part 62. If the time between required audio, visual,
and olfactory inspections described in Sec. 60.5416b or the applicable
approved state plan or applicable Federal plan in part 62 is greater
than one year, visual inspections must be conducted at least annually.
(ii) For thief hatches on controlled atmospheric pressure storage
tanks not subject to the standards in Sec. 60.5395b of this chapter,
or an applicable approved state plan or applicable Federal plan in part
62 of this chapter, visual inspections must be conducted at least once
in a calendar year.
(iii) If one visual inspection is conducted in the calendar year
and an open thief hatch is found, assume the thief hatch was open for
the entire calendar year or the entire period that the sensor(s) was
not operating or malfunctioning. If multiple visual inspections are
conducted in the calendar year, assume a thief hatch found open in the
first visual inspection was open since the beginning of the year until
the date of the visual inspection; assume a thief hatch found open in
the last visual inspection of the year was open from the preceding
visual inspection through the end of the year; assume a thief hatch
found open in a visual inspection between the first and last visual
inspections of the year was open since the preceding visual inspection
until the date of the visual inspection.
(k) Condensate storage tanks. For vent stacks connected to one or
more condensate storage tanks, either water or hydrocarbon, without
vapor recovery, flares, or other controls, in onshore natural gas
transmission compression or underground natural gas storage, calculate
CH4 and CO2 annual emissions from compressor
scrubber dump valve leakage as specified in paragraphs (k)(1) through
(4) of this section. If emissions from compressor scrubber dump valve
leakage are routed to a flare, you must calculate CH4,
CO2, and N2O annual emissions as specified in
paragraph (n) of this section and report emissions from the flare as
specified in Sec. 98.236(n).
(1) Except as specified in paragraph (k)(1)(iv) of this section,
you must monitor the tank vapor vent stack annually for emissions using
one of the methods specified in paragraphs (k)(1)(i) through (iii) of
this section.
(i) Use an optical gas imaging instrument according to methods set
forth in Sec. 98.234(a)(1).
(ii) Measure the tank vent directly using a flow meter or high
volume sampler according to methods in Sec. 98.234(b) or (d) for a
duration of 5 minutes.
(iii) Measure the tank vent using a calibrated bag according to
methods in Sec. 98.234(c) for a duration of 5 minutes or until the bag
is full, whichever is shorter.
(iv) You may annually monitor leakage through compressor scrubber
dump valve(s) into the tank using an acoustic leak detection device
according to methods set forth in Sec. 98.234(a)(5).
(2) If the tank vapors from the vent stack are continuous for 5
minutes, or the optical gas imaging instrument or acoustic leak
detection device detects a leak, then you must use one of the methods
in either paragraph (k)(2)(i) or (ii) of this section.
(i) Use a flow meter, such as a turbine meter, calibrated bag, or
high volume sampler to estimate tank vapor volumes from the vent stack
according to methods set forth in Sec. 98.234(b) through (d). If you
do not have a continuous flow measurement device, you may install a
flow measuring device on the tank vapor vent stack. If the vent is
directly measured for five minutes under paragraph (k)(1)(ii) or (iii)
of this section to detect continuous leakage, this serves as the
measurement.
(ii) Use an acoustic leak detection device on each scrubber dump
valve connected to the tank according to the method set forth in Sec.
98.234(a)(5).
(3) If a leaking dump valve is identified, the leak must be counted
as having occurred since the beginning of the calendar year, or from
the previous test that did not detect leaking in the same calendar
year. If the leaking dump valve is fixed following leak detection, the
leak duration will end upon being repaired. If a leaking dump valve is
identified and not repaired, the leak must be counted as having
occurred through the rest of the calendar year.
(4) Use the requirements specified in paragraphs (k)(4)(i) and (ii)
of this section to quantify annual emissions.
(i) Use the appropriate gas composition in paragraph (u)(2)(iii) of
this section.
(ii) Calculate CH4 and CO2 volumetric and
mass emissions at standard conditions using calculations in paragraphs
(t), (u), and (v) of this section, as applicable to the monitoring
equipment used.
(l) Well testing venting and flaring. Calculate CH4 and
CO2 annual emissions from well testing venting as specified
in paragraphs (l)(1) through (5) of this section. If emissions from
well testing venting are routed to a flare, you must calculate
CH4, CO2, and N2O annual emissions as
specified in paragraph (n) of this section, report emissions from the
flare as specified in Sec. 98.236(n), and report additional
[[Page 42260]]
information specified in Sec. 98.236(l), as applicable.
(1) Determine the gas to oil ratio (GOR) of the hydrocarbon
production from oil well(s) tested. Determine the production rate from
gas well(s) tested.
(2) If GOR cannot be determined from your available data, then you
must measure quantities reported in this section according to one of
the procedures specified in paragraph (l)(2)(i) or (ii) of this section
to determine GOR.
(i) You may use an appropriate standard method published by a
consensus-based standards organization if such a method exists.
(ii) You may use an industry standard practice as described in
Sec. 98.234(b).
(3) Estimate venting emissions using equation W-17A to this section
(for oil wells) or equation W-17B to this section (for gas wells) for
each well tested during the reporting year.
[GRAPHIC] [TIFF OMITTED] TR14MY24.072
[GRAPHIC] [TIFF OMITTED] TR14MY24.073
Where:
Ea,n = Annual volumetric natural gas emissions from well
testing for each well being tested in cubic feet under actual
conditions.
GOR = Gas to oil ratio in cubic feet of gas per barrel of oil for
each well being tested; oil here refers to hydrocarbon liquids
produced of all API gravities.
FR = Average annual flow rate in barrels of oil per day for the oil
well being tested.
PR = Average annual production rate in actual cubic feet per day for
the gas well being tested.
D = Number of days during the calendar year that the well is tested.
(4) Calculate natural gas volumetric emissions at standard
conditions using calculations in paragraph (t) of this section.
(5) Calculate both CH4 and CO2 volumetric and
mass emissions from natural gas volumetric emissions using calculations
in paragraphs (u) and (v) of this section.
(m) Associated gas venting and flaring. Calculate CH4
and CO2 annual emissions from associated gas venting not in
conjunction with well testing (refer to paragraph (l) of this section)
as specified in paragraphs (m)(1) through (3) of this section. If
emissions from associated gas venting are routed to a flare, you must
calculate CH4, CO2, and N2O annual
emissions as specified in paragraph (n) of this section, report
emissions from the flare as specified in Sec. 98.236(n), and report
additional information specified in Sec. 98.236(m), as applicable.
(1) If you measure the gas flow to a vent using a continuous flow
measurement device, you must use the measured flow volumes to calculate
vented associated gas emissions.
(2) If you do not measure the gas flow to a vent using a continuous
flow measurement device, you must follow the procedures in paragraphs
(m)(2)(i) through (iii) of this section.
(i) Determine the GOR of the hydrocarbon production from each well
whose associated natural gas is vented or flared. If GOR from each well
is not available, use the GOR from a cluster of wells in the same sub-
basin category.
(ii) If GOR cannot be determined from your available data, then you
must use one of the procedures specified in paragraph (m)(2)(ii)(A) or
(B) of this section to determine GOR.
(A) You may use an appropriate standard method published by a
consensus-based standards organization if such a method exists.
(B) You may use an industry standard practice as described in Sec.
98.234(b).
(iii) Estimate venting emissions using equation W-18 to this
section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.074
Where:
Es,n,p = Annual volumetric natural gas emissions at each
well from associated gas venting at standard conditions, in cubic
feet.
GORp = Gas to oil ratio, for well p, in standard cubic
feet of gas per barrel of oil determined according to paragraphs
(m)(2)(i) through (iii) of this section; oil here refers to
hydrocarbon liquids produced of all API gravities.
Vp = Volume of oil produced, for well p, in barrels in
the calendar year only during time periods in which associated gas
was vented or flared.
SGp = Volume of associated gas sent to sales and volume
of associated gas used for other purposes at the facility site,
including powering engines, separators, safety systems and/or
combustion equipment and not flared or vented, for well p, in
standard cubic feet of gas in the calendar year only during time
periods in which associated gas was vented or flared.
(3) Calculate both CH4 and CO2 volumetric and
mass emissions from volumetric natural gas emissions using calculations
in paragraph (u) and (v) of this section.
(n) Flare stack emissions. Except as specified in paragraph (n)(9)
of this section, calculate CO2, CH4, and
N2O emissions from each flare stack as specified in
paragraphs (n)(1) through (8) of this section. For each flare,
disaggregate the total flared emissions to applicable source types as
specified in paragraph (n)(10) of this section.
(1) Destruction efficiency and combustion efficiency. To calculate
CH4 emissions for flares, use the applicable default
destruction and combustion efficiencies specified in paragraphs
(n)(1)(i) through (iii) of this section or alternative destruction and
combustion efficiencies determined in accordance with paragraph
(n)(1)(v) of this section. If you change the method with which you
determine the default destruction and combustion efficiencies during a
year, then use the applicable destruction and combustion efficiencies
in paragraphs (n)(1)(i) through (iii) and paragraph (n)(1)(v) of this
section for each portion of the year during which a different default
destruction and combustion efficiency was used, and calculate an annual
time-weighted average destruction and combustion efficiency to report
for the flare.
(i) Tier 1. Use a default destruction efficiency of 98 percent and
a default combustion efficiency of 96.5 percent if you follow the
performance test requirements specified in paragraph
[[Page 42261]]
(n)(1)(i)(A) of this section and the operating limit requirements
specified in paragraph (n)(1)(i)(B) of this section, or the operating
limit requirements specified in paragraph (n)(1)(i)(C) of this section,
as applicable. You must also keep the applicable records in Sec.
63.655(i)(2), (3), and (9) of this chapter. If you fail to fully
conform with all cited provisions for a period of 15 consecutive days,
you must utilize the Tier 3 default destruction and combustion
efficiency values until such time that full conformance is achieved.
You must document these periods and maintain records as specified in
Sec. 98.237 of the date when the non-conformance began, and the date
when full conformance is re-established.
(A) The applicable testing requirements in Sec. 63.645(a), (b),
(c), (d), and (i) of this chapter, including Sec. 63.116 (a)(2), (3),
(b), and (c) of this chapter. When Sec. 63.645 refers to ``organic
HAP,'' the terms ``methane'' and ``CO2'' shall apply for the
purposes of this subpart.
(B) The applicable monitoring requirements in Sec. 63.644(a), (b),
(d), and (e) of this chapter. The data to submit in a Notification of
Compliance Status report in Sec. 63.644(d) of this chapter shall be
maintained as records for the purposes of this section (n)(1)(i), and
references to violations in Sec. 63.644(e) of this chapter do not
apply for the purposes of this section (n)(1)(i).
(C) The requirements in Sec. 63.670 (a) through (n), Sec.
63.670(p), and Sec. 63.671 of this chapter.
(ii) Tier 2. Use a default destruction efficiency of 95 percent and
a default combustion efficiency of 93.5 percent if you follow the
requirements specified in either paragraph (n)(1)(ii)(A), (B), (C), or
(D) of this section. If you fail to fully conform with all cited
provisions for a period of 15 consecutive days, you must utilize the
Tier 3 default destruction and combustion efficiency values until such
time that full conformance is achieved. You must document these periods
and maintain records as specified in Sec. 98.237 of the date when the
non-conformance began, and the date when full conformance is re-
established.
(A) The requirements in Sec. 60.5412b(a)(1) of this chapter, along
with the applicable testing requirements in Sec. 60.5413b of this
chapter, the applicable continuous compliance requirements in Sec.
60.5415b(f) of this chapter, and the applicable continuous monitoring
requirements in Sec. 60.5417b of this chapter. You must also keep the
applicable records in Sec. 60.5420b(c)(11) of this chapter.
(B) The requirements in Sec. 60.5412b(a)(3) of this chapter, the
applicable continuous compliance requirements in Sec. 60.5415b(f) of
this chapter, and the applicable continuous monitoring requirements in
Sec. 60.5417b(b) of this chapter. You must also keep the applicable
records in Sec. 60.5420b(c)(11) of this chapter.
(C) If using an enclosed combustion device tested by the
manufacturer in accordance with Sec. 60.5413b(d) of this chapter, the
requirements in Sec. 60.5413b(b)(5)(iii) and (e) of this chapter, the
applicable continuous compliance requirements in Sec. 60.5415b(f) of
this chapter, and the applicable continuous monitoring requirements in
Sec. 60.5417b of this chapter. You must also keep the applicable
records in Sec. 60.5420b(c)(11) of this chapter.
(D) If you are subject to an approved state plan or applicable
Federal plan in part 62 of this chapter that requires the reduction of
methane by 95 percent, you may follow all applicable requirements of
the approved state plan or applicable Federal plan in part 62 of this
chapter, including the testing, continuous compliance, continuous
monitoring, and recordkeeping requirements.
(iii) Tier 3. Use a default destruction efficiency of 92 percent
and a default combustion efficiency of 90.5 percent if you do not meet
the requirements specified in either paragraph (n)(1)(i) or (ii) of
this section.
(iv) Alternative test method. If you are utilizing the tier 2
default efficiencies in paragraph (n)(2)(ii) of this section and are
not subject to 40 CFR subpart OOOOb or an applicable approved state or
applicable federal plan under part 62 of this chapter that requires 95
percent reduction in methane emissions, you may conduct a performance
test using EPA OTM-52 (incorporated by reference, see Sec. 98.7) as an
alternative to conducting a performance test using the methods
specified in Sec. 60.5413b of this chapter, or in an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter. If the combustion efficiency obtained using OTM-52 is equal to
or greater than 93.5 percent, then use a default destruction efficiency
of 95 percent and a default combustion efficiency of 93.5 percent. If
you utilize OTM-52 for the testing, you must comply with all the
applicable monitoring, compliance, and recordkeeping requirements
identified in paragraph (n)(1)(ii) of this section.
(v) Alternative destruction and combustion efficiencies. You may
use a directly measured combustion efficiency instead of the default
combustion efficiencies specified in paragraphs (n)(1)(i) through (iii)
of this section if you follow the provisions of paragraph (n)(1)(v)(A)
through (E) of this section.
(A) Measure the combustion efficiency in accordance with an
alternative test method approved in accordance with Sec. 60.5412b(d)
of this chapter or an applicable approved state plan or applicable
Federal plan in part 62 of this chapter.
(B) Conduct monitoring as specified in Sec. Sec. 60.5415b(f)(1)(x)
and (xi) and 60.5417b(i) of this chapter, or an applicable approved
state plan or applicable Federal plan in part 62 of this chapter.
(C) Adhere to all conditions in the monitoring plan you prepare as
specified in Sec. 60.5417b(i)(2) of this chapter or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter at all times.
(D) You must use a destruction efficiency equal to the combustion
efficiency plus 1.5.
(E) If you fail to fully conform with your plan for a period of 15
or more consecutive days, you must utilize the Tier 3 default
destruction and combustion efficiency values until such time that full
conformance is achieved. You must document these periods and maintain
records as specified in Sec. 98.237 of the date when the non-
conformance began, and the date when full conformance is re-
established.
(2) Pilot. Continuously monitor for the presence of a pilot flame
or combustion flame as specified in paragraph (n)(2)(i) of this section
or visually inspect for the presence of a pilot flame or combustion
flame as specified in paragraph (n)(2)(ii) of this section, as
applicable.. If you comply with tier 2, you must also use data
collected according to paragraph (n)(2)(iii) of this section in your
calculations of time the flare was unlit and the fraction of gas routed
to the flare during periods when the flare was unlit. If you
continuously monitor, then periods when the flare is unlit must be
determined based on those data, except when contradicted by data
collected according to paragraph (n)(2)(iii) of this section. Determine
the fraction of the total volume that is routed to the flare during
unlit periods as specified in paragraph (n)(2)(iv) of this section.
(i) At least once every five minutes monitor for the presence of a
pilot flame or combustion flame using a device (including, but not
limited to, a thermocouple, ultraviolet beam sensor, infrared sensor,
video surveillance system, or advanced remote monitoring method)
capable of detecting that the pilot or combustion flame is present at
all times.
(A) Monitoring for the presence of a flare flame in accordance with
[[Page 42262]]
Sec. 60.5417b satisfies the requirement of this paragraph (n)(2).
(B) You may use multiple or redundant monitoring devices. When a
discrepancy occurs between multiple devices, you must either visually
confirm or use video surveillance output to confirm that the flame is
present as soon as practicable after detecting the discrepancy to
ensure that at least one device is operating properly. If you confirm
that at least one device is operating properly, you may rely on the
properly operating device(s) to monitor the flame.
(C) 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 part 98.
(D) Track the length of time over all periods when the flare is
unlit and calculate the fraction of the total flow to the flare that
was routed to the flare when the flare was unlit as specified in
paragraph (n)(2)(iv) of this section.
(E) If all continuous monitoring devices are out of service for
more than one week, then visually inspect for the presence of a pilot
flame or combustion flame at least once per week for the first 4 weeks
that the monitoring devices are out of service or until at least one
repaired or new device is operational, whichever period is shorter. If
all continuous monitoring devices are out of service for less than one
week, then at least one visual inspection must be conducted during the
outage. If a flame is not detected during a weekly visual inspection,
assume the pilot has been unlit since the previous inspection or the
last time the continuous monitoring device detected a flame, and assume
that the pilot remains unlit until a subsequent inspection or
continuous monitoring device detects a flame. If the monitoring device
outage lasts more than 4 weeks, then you may switch to conducting
inspections at least once per month in accordance with paragraph
(n)(2)(ii) of this section.
(ii) As an alternative to continuous monitoring as specified in
paragraph (n)(2)(i) of this section, if you comply with tier 3 in
paragraph (n)(1)(iii) of this section, at least once per month visually
inspect for the presence of a pilot flame or combustion flame. You may
also conduct visual inspections when using an alternative test method
in accordance with paragraph (n)(1)(iv) of this section that allows
visual inspections. If a flame is not detected, track the time since
the previous inspection until a subsequent inspection detects a flame,
and use this time in your calculation of the fraction of the total flow
to the flare that was routed to the flare when the flare was unlit as
specified in paragraph (n)(2)(iv) of this section. Use the sum of the
measured flows, as determined from measurements obtained under
paragraph (n)(1) of this section, during all time periods when the
pilot was determined to be unlit, to calculate the fraction of the
total annual volume that is routed to the flare when it is unlit.
(iii) For a flare subject to 40 CFR part 60 subpart OOOOb, or an
applicable approved state plan or applicable Federal plan in part 62 of
this chapter, a flare inspection conducted using an OGI camera during a
fugitive emissions survey in accordance with Sec. 60.5415b(f)(1)(x)
constitutes a pilot flame inspection under this subpart. If a flame is
not detected, track the time from the previous inspection until a
subsequent inspection or continuous monitoring device detects a flame
and use this time in your calculation of the fraction of the total flow
to the flare that was routed to the flare when the flare was unlit as
specified in paragraph (n)(2)(iv) of this section.
(iv) If you measure total flow to the flare in accordance with
paragraph (n)(3)(i) of this section, calculate the fraction of the
total annual volume that is routed to the flare when it is unlit using
the actual flow during the unlit time periods that are tracked
according to paragraph (n)(2)(i)(D), (ii), or (iii) of this section. If
you determine flows of individual streams routed to the flare in
accordance with paragraph (n)(3)(ii) of this section, use the stream-
specific average flow rates for the streams routed to the flare during
unlit times to calculate the fraction of the total annual volume that
is routed to the flare when it is unlit.
(3) Flow determination. Calculate total flow to the flare as
specified in paragraph (n)(3)(i) of this section or determine flow of
each individual stream that is routed to the flare as specified in
paragraph (n)(3)(ii) of this section. Use engineering calculations
based on best available data and company records to calculate pilot gas
flow to add to the total gas flow to the flare.
(i) Use a continuous parameter monitoring system to measure flow of
gas to the flare downstream of any sweep, purge, or auxiliary gas
addition. You may use either flow meters or indirectly calculate flow
using other parameter monitoring systems combined with engineering
calculations, such as line pressure, line size, and burner nozzle
dimensions. If you use a continuous parameter monitoring system, you
must use the measured flow in calculating the total flow volume to the
flare. The continuous parameter monitoring system must measure data
values at least once every hour.
(ii) Determine flow to the flare from individual sources, including
sweep, purge, auxiliary fuel, and collective flow from offsite sources
that route gas to the flare using any combination of the methods in
paragraphs (n)(3)(ii)(A) and (B) of this section, as applicable. Adjust
the volumes determined as specified in paragraphs (n)(3)(ii)(A) and (B)
of this section by any estimated bypass volumes diverted from entering
the flare and leaks from the closed vent system in accordance with
paragraphs (n)(3)(ii)(C) and (D) of this section. Do not adjust the
volumes routed to the flare for volumes diverted through bypass lines
located upstream of the flow measurement or determination location.
(A) Use a continuous flow meter to measure the flow of gas from
individual sources (or combination of sources) that route gas to the
flare. If the emission streams for multiple sources are routed to a
manifold before being combined with other emission streams, you may
conduct the measurement in the manifold instead of from each source
that is routed to the manifold. If you use a continuous flow meter, you
must use the measured flow in calculating the total flow volume to the
flare. The continuous flow meter must measure data values at least once
every hour.
(B) If flow from a source is not measured using a continuous flow
meter, then use methods specified in paragraphs (n)(3)(ii)(B)(1)
through (8) of this section, as applicable.
(1) Determine flow of emission streams routed to flares from acid
gas removal units using Calculation Method 3 or Calculation Method 4 as
specified in paragraph (d)(3) or (4) of this section. Use the method
specified in paragraph (n)(3)(ii)(B)(8) of this section to determine
the volume of non-GHG constituents in a stream from an acid gas removal
unit or nitrogen removal unit and add to the volume of GHGs to
determine the total volume to the flare.
(2) Determine flow of emission streams routed to flares from
dehydrators using an applicable method specified in paragraph (e) of
this section. When using Calculation Method 2 to determine volume of
GHGs from small glycol dehydrators, also use the method specified in
paragraph (n)(3)(ii)(B)(8) of this section to determine the volume of
non-GHG constituents in the stream to the flare
[[Page 42263]]
and add to the volume of GHGs to determine the total volume to the
flare.
(3) Determine flow of emission streams routed to flares from
completions and workovers with hydraulic fracturing using a method
specified in paragraph (g) of this section.
(4) Determine flow of emission streams routed to flares from
completions and workovers without hydraulic fracturing using a method
specified in paragraph (h) of this section.
(5) Determine flow of emission streams routed to flares from
hydrocarbon liquids and produced water storage tanks using a method
specified in paragraph (j) of this section. When using Calculation
Method 2 or Calculation Method 3 to calculate the volume of GHGs, use
the method specified in paragraph (n)(3)(ii)(B)(8) of this section to
determine the volume of non-GHG constituents in the stream to the flare
and add to the volume of GHGs to determine the total volume to the
flare.
(6) Determine flow of emission streams routed to flares from well
testing using an applicable method specified in paragraph (l) of this
section.
(7) Determine flow of associated gas emission streams routed to
flares using the method specified in paragraph (m)(2) of this section.
(8) Use engineering calculations based on process knowledge,
company records, and best available data to calculate flow for sources
other than those described in paragraphs (n)(3)(ii)(B)(1) through (7)
of this section and to calculate volume of non-GHG constituents in
streams for which the method used in paragraphs (n)(3)(ii)(B)(1), (2),
and (5) of this section calculates only the GHG flow.
(C) If the closed vent system that routes emissions to the flare
contains one or more bypass devices that could be used to divert all or
a portion of the gases from entering the flare, then you must determine
when flow is diverted through the bypass and estimate the volume that
bypasses the flare. The bypass volume may be determined based on
engineering calculations, process knowledge, and best available data.
Use the estimated bypass volume to adjust the volumes determined in
accordance with paragraph (n)(3)(ii)(A) or (B) of this section to
determine the flow to the flare. For bypass volumes that are diverted
directly to atmosphere, use the estimated volume in the calculation and
reporting of vented emissions from the applicable source(s).
(D) If you determine a component in the closed vent system is
leaking, you must adjust the flow determined in accordance with
paragraph (n)(3)(ii)(A) or (B) of this section by the estimated volume
of the leak to determine the flow to the flare. Estimate the leak
volume based on engineering calculations, process knowledge, and best
available data. Report the estimated leak volume as vented emissions
from the applicable source(s).
(4) Gas composition. Determine the composition of the inlet gas to
the flare as specified in either paragraph (n)(4)(i) or (ii) of this
section, or determine composition of the individual streams that are
combined and routed to the flare as specified in paragraph (n)(4)(iii)
of this section. Use representative compositions of pilot gas
determined by engineering calculation based on process knowledge and
best available data.
(i) Use a continuous gas composition analyzer on the inlet gas to
the flare burner downstream of any purge, sweep, or auxiliary fuel
addition to measure annual average mole fractions of methane, ethane,
propane, butane, pentanes plus, and CO2. If you use a
continuous gas composition analyzer on the total inlet stream to the
flare, you must use the measured annual average mole fractions to
calculate total emissions from the flare. The continuous gas
composition analyzer must measure data values at least once every hour.
(ii) Take samples of the inlet gas to the flare burner downstream
of any purge, sweep, or auxiliary fuel addition at least annually in
which gas is routed to the flare and analyze for methane, ethane,
propane, butane, pentanes plus, and CO2 constituents.
Determine the annual average concentration of each constituent as the
annual average of all valid measurements for that constituent during
the year and you must use those data to calculate flared emissions.
(iii) When composition is not determined at the inlet to the flare
as specified in either paragraph (i) or (ii) of this section, then
determine annual average compositions for streams from individual
sources (or combinations of sources), including sweep, purge, and
auxiliary fuel, routed to the flare using any combination of the
methods specified in paragraphs (n)(4)(iii)(A) and (B) of this section,
as applicable.
(A) Use a continuous gas composition analyzer to measure annual
average mole fractions of methane, ethane, propane, butane, pentanes
plus, and CO2 constituents. If emission streams for multiple
sources are routed to a manifold before being combined with other
emission streams, you may measure gas composition in the manifold
instead of from each source that is routed to the manifold. If you use
a continuous gas composition analyzer, you must use the measured annual
average mole fractions to calculate flared emissions for the stream.
The continuous gas composition analyzer must measure data values at
least once every hour.
(B) If composition is not measured in accordance with paragraph
(n)(4)(iii)(A) of this section, then use methods specified in
paragraphs (n)(4)(iii)(B)(1) through (7) of this section to determine
composition, as applicable. When paragraphs (n)(4)(iii)(B)(1) through
(5) reference continuous gas composition analyzer requirements in
paragraph (u)(2) of this section, the requirements in paragraph
(n)(4)(iii)(A) apply for the purposes of this paragraph (n)(4)(iii)(B).
When paragraphs (n)(4)(iii)(B)(1) through (5) reference paragraph
(u)(2) of this section, the language ``your most recent available
analysis'' in paragraph (u)(2)(i) of this section means ``annual
samples'' for the purposes of this paragraph (n)(4)(iii)(B).
(1) Determine the total annual average GHG composition of streams
from acid gas removal units based on either process simulation as
specified in paragraph (d)(4) of this section or quarterly sampling in
accordance with paragraphs (d)(6) and (10) of this section, and
determine the composition of ethane, propane, butane, and pentanes plus
as specified in paragraph (n)(4)(iii)(B)(5) of this section.
(2) Determine the total annual average composition of streams from
glycol dehydrators using Calculation Method 1 as specified in paragraph
(e)(1) of this section or determine the annual average GHG composition
as specified in paragraph (u)(2) of this section for the applicable
industry segment. Determine annual average GHG composition of streams
from desiccant dehydrators as specified in paragraph (u)(2) of this
section. If you determine GHG composition in accordance with paragraph
(u)(2) of this section, also determine the composition of ethane,
propane, butane, and pentanes plus as specified in paragraph
(n)(4)(iii)(B)(5) of this section.
(3) Determine the total annual average composition of streams from
hydrocarbon liquids and produced water storage tanks using Calculation
Method 1 in accordance with paragraph (j)(1) of this section or
determine the annual average GHG composition as specified in paragraph
(u)(2)(i) of this section. If you determine annual average GHG
composition as specified in paragraph (u)(2)(i) of this section, then
also determine the composition of
[[Page 42264]]
ethane, propane, butane, and pentanes plus as specified in paragraph
(n)(4)(iii)(B)(5) of this section.
(4) For onshore natural gas processing facilities, determine GHG
mole fractions for all emission sources downstream of the de-methanizer
overhead or dew point control based on samples of facility-specific
residue gas to transmission pipeline systems taken at least once per
year according to methods set forth in Sec. 98.234(b), and determine
GHG mole fractions for all emission sources upstream of the de-
methanizer or dew point control based on samples of feed natural gas
taken at least once per year according to methods set forth in Sec.
98.234(b). For onshore natural gas processing plants that solely
fractionate a liquid stream, use the GHG mole fraction in feed natural
gas liquid streams as determined from samples taken at least once per
year. If multiple samples of a stream are taken in a year, use the
arithmetic average GHG composition.
(5) Except as specified in paragraph (n)(4)(iii)(B)(6) of this
section, for streams from any source type other than those identified
in paragraphs (n)(4)(iii)(B)(1) through (4) of this section, and for
purge gas, sweep gas, and auxiliary fuel, determine the annual average
GHG composition as specified in paragraph (u)(2) of this section for
the applicable industry segment, and determine the composition of
ethane, propane, butane, and pentanes plus as specified in paragraph
(n)(4)(iii)(B)(7) of this section.
(6) When the stream going to the flare is a hydrocarbon product
stream, such as methane, ethane, propane, butane, pentanes-plus, or
mixed light hydrocarbons, you may use a representative composition from
the source for the stream determined by engineering calculation based
on process knowledge and best available data.
(7) When only the GHG composition is determined in accordance with
paragraph (u)(2) of this section, determine the annual average
composition of ethane, propane, butane, and pentanes plus in the stream
using a representative composition based on process knowledge and best
available data.
(5) Calculate CH4 and CO2 emissions. Calculate GHG volumetric
emissions from flaring at standard conditions using equations W-19 and
W-20 to this section and as specified in paragraphs (n)(5)(i) through
(iv) of this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.075
[GRAPHIC] [TIFF OMITTED] TR14MY24.076
Where:
Es,CH4 = Annual CH4 emissions from flare stack
in cubic feet, at standard conditions.
Es,CO2 = Annual CO2 emissions from flare stack
in cubic feet, at standard conditions.
Vs = Volume of gas sent to flare in standard cubic feet,
during the year as determined in paragraph (n)(3) of this section.
[eta]D = Flare destruction efficiency, expressed as fraction of
hydrocarbon compounds in gas that is destroyed by a burning flare,
but may or may not be completely oxidized to CO2.
[eta]C = Flare combustion efficiency, expressed as fraction of
hydrocarbon compounds in gas that is oxidized to CO2 by a
burning flare.
XCH4 = Annual average mole fraction of CH4 in
the feed gas to the flare or in each of the streams routed to the
flare as determined in paragraph (n)(4) of this section.
XCO2 = Annual average mole fraction of CO2 in
the feed gas to the flare or in each of the streams routed to the
flare as determined in paragraph (n)(4) of this section.
ZU = Fraction of the feed gas sent to an un-lit flare determined
from both the total time the flare was unlit as determined by
monitoring the pilot flame or combustion flame as specified in
paragraph (n)(2) of this section and the volume of gas routed to the
flare during periods when the flare was unlit based on the flow
determined in accordance with paragraph (n)(3) of this section.
ZL = Fraction of the feed gas sent to a burning flare
(equal to 1--ZU).
Yj = Annual average mole fraction of hydrocarbon
constituents j (such as methane, ethane, propane, butane, and
pentanes-plus) in the feed gas to the flare or in each of the
streams routed to the flare as determined in paragraph (n)(4) of
this section.
Rj = Number of carbon atoms in the hydrocarbon
constituent j in the feed gas to the flare: 1 for methane, 2 for
ethane, 3 for propane, 4 for butane, and 5 for pentanes-plus).
(i) If you measure the gas flow at the flare inlet as specified in
paragraph (n)(3)(i) of this section and you measure gas composition for
the inlet gas to the flare as specified in paragraph (n)(4)(i) or (ii)
of this section, then use those data in equations W-19 and W-20 to this
section to calculate total emissions from the flare.
(ii) If you determine the flow from each source as specified in
paragraph (n)(3)(ii) of this section and you measure gas composition
for the inlet gas to the flare as specified in paragraph (n)(4)(i) or
(ii) of this section, then sum the flows for each stream to calculate
the total annual gas flow to the flare. Use that total annual flow with
the annual average concentration of each constituent as calculated in
paragraph (n)(4)(i) or (ii) of this section in equations W-19 and W-20
to this section to calculate total emissions from the flare.
(iii) If you determine the flow from each source as specified in
paragraph (n)(3)(ii) of this section and you determine gas composition
for the emission stream from each source as specified in paragraph
(n)(4)(iii) of this section, then calculate total emissions from the
flare as specified in either paragraph (n)(5)(iii)(A) or (B) of this
section.
(A) Use each set of stream-specific flow and annual average
concentration data in equations W-19 and W-20 to this section to
calculate stream-specific flared emissions for each stream, and then
sum the results from each stream-specific calculation to calculate the
total emissions from the flare.
(B) Sum the flows from each source to calculate the total gas flow
into the flare and use the source-specific flows and source-specific
annual average concentrations to determine flow-weighted annual average
concentrations of CO2 and hydrocarbon constituents in the
combined gas stream into the flare. Use the calculated total gas flow
and the calculated flow-weighted annual average concentrations for the
inlet gas stream to the flare in equations W-19 and W-20 to this
section to calculate the total emissions from the flare.
[[Page 42265]]
(iv) You may not combine measurement of the inlet gas flow to the
flare as specified in paragraph (n)(3)(i) of this section with
measurement of the gas composition of the streams from each source as
specified in paragraph (n)(4)(iii) of this section.
(6) Convert volume at actual conditions to volume at standard
conditions. Convert GHG volumetric emissions to standard conditions
using calculations in paragraph (t) of this section.
(7) Convert volumetric emissions to mass emissions. Calculate both
CH4 and CO2 mass emissions from volumetric
emissions using calculation in paragraph (v) of this section.
(8) Calculate N2O emissions. Calculate N2O emissions
from flare stacks using equation W-40 to this section. Determine the
values of parameters ``HHV'' and ``Fuel'' in equation W-40 to this
section as specified in paragraphs (n)(8)(i) through (iv) of this
section, as applicable.
(i) Directly measure the annual average higher heating value in the
inlet stream to the flare using either a continuous gas composition
analyzer or a calorimeter. Use this flare-specific annual average
higher heating value for the parameter ``HHV'' in equation W-40 to this
section, and use either the total inlet flow to the flare measured as
specified in paragraph (n)(3)(i) of this section or the sum of the
flows of individual streams routed to the flare as determined in
paragraph (n)(3)(ii) of this section for the parameter ``Fuel'' in
equation W-40 to this section to calculate the total N2O
emissions from the flare.
(ii) Calculate the annual average higher heating value in the inlet
stream to the flare using annual average gas compositions of the inlet
stream measured in accordance with paragraph (n)(4)(i) or (ii) of this
section. Use this flare-specific annual average higher heating value
for the parameter ``HHV'' in equation W-40 to this section, and use
either the total inlet flow to the flare measured as specified in
paragraph (n)(3)(i) of this section or the sum of the flows of
individual streams routed to the flare as determined in paragraph
(n)(3)(ii) of this section for the parameter ``Fuel'' in equation W-40
to this section to calculate the total N2O emissions from
the flare.
(iii) Directly measure the annual average higher heating values in
the individual streams routed to the flare using either a continuous
gas composition analyzer or a calorimeter. Calculate the total
N2O emissions from the flare as specified in either
paragraph (n)(8)(iii)(A) or (B) of this section.
(A) Use the stream-specific annual average higher heating values
for the parameter ``HHV'' in equation W-40 to this section, use the
stream-specific flows as determined in paragraph (n)(3)(ii) of this
section for the parameter ``Fuel'' in equation W-40 to this section in
separate stream-specific calculations of N2O emissions using
equation W-40 to this section, and sum the resulting values to
calculate the total N2O emissions from the flare.
(B) Use the stream-specific annual average higher heating values
and flows to calculate a flow-weighted annual average higher heating
value to use as the parameter ``HHV'' in equation W-40 to this section
and the sum of the individual stream flows routed to the flare as
determined in paragraph (n)(3)(ii) of this section for the parameter
``Fuel'' in equation W-40 to this section to calculate total
N2O emissions from the flare.
(iv) Calculate annual average higher heating values for the
individual streams routed to the flare using gas compositions
determined in accordance with paragraph (n)(4)(iii) of this section.
Calculate the total N2O emissions from the flare as
specified in either paragraph (n)(8)(iv)(A) or (B) of this section.
(A) Use the stream-specific annual average higher heating values
and the stream-specific flows in separate stream-specific calculations
of N2O emissions using equation W-40 to this section and sum
the resulting values to calculate the total N2O emissions
from the flare.
(B) Use the stream-specific annual average higher heating values
and flows to calculate a flow-weighted annual average higher heating
value to use as the parameter ``HHV'' in equation W-40 to this section
and the sum of the individual stream flows routed to the flare as
determined in paragraph (n)(3)(ii) of this section for the parameter
``Fuel'' in equation W-40 to this section to calculate total
N2O emissions from the flare.
(9) CEMS. If you operate and maintain a CEMS that has both a
CO2 concentration monitor and volumetric flow rate monitor
for the combustion gases from the flare, you must calculate
CO2 emissions for the flare using the CEMS. You must follow
the Tier 4 Calculation Method and all associated calculation, quality
assurance, reporting, and recordkeeping requirements for Tier 4 in
subpart C of this part (General Stationary Fuel Combustion Sources). If
a CEMS is used to calculate flare stack CO2 emissions, you
must also comply with all other requirements specified in paragraphs
(n)(1) through (8) of this section, except that calculation of
CO2 emissions using equation W-20 to this section is not
required.
(10) Disaggregation. Disaggregate the total emissions from the
flare as calculated in paragraphs (n)(7) and (8) of this section or
paragraph (n)(9) of this section, as applicable, to each source type
listed in paragraphs (n)(10)(i) through (viii) of this section, as
applicable to the industry segment, that routed emissions to the flare.
If emissions from the flare are calculated in accordance with paragraph
(n)(5)(iii) of this section using stream-specific flow and composition,
including combined streams that contain emissions from only a single
source type, use the source-specific emissions calculated using these
data to calculate the disaggregated emissions per source type. If the
total emissions from the flare are calculated using total flow and/or
total annual average composition of the total inlet stream to the
flare, or if flow or composition are determined for a combined stream
that contains emissions from more than one source type, then use
engineering calculations and best available data to disaggregate the
total emissions to the applicable source types.
(i) Acid gas removal units.
(ii) Dehydrators.
(iii) Completions and workovers with hydraulic fracturing.
(iv) Completions and workovers without hydraulic fracturing.
(v) Hydrocarbon liquids and produced water storage tanks.
(vi) Well testing.
(vii) Associated gas.
(viii) Other (collectively).
(o) Centrifugal compressor venting. If you are required to report
emissions from centrifugal compressor venting as specified in Sec.
98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct
volumetric emission measurements specified in paragraph (o)(1) of this
section using methods specified in paragraphs (o)(2) through (5) of
this section; perform calculations specified in paragraphs (o)(6)
through (9) of this section; and calculate CH4 and
CO2 mass emissions as specified in paragraph (o)(11) of this
section. If you are required to report emissions from centrifugal
compressor venting at an onshore petroleum and natural gas production
facility as specified in Sec. 98.232(c)(19) or an onshore petroleum
and natural gas gathering and boosting facility as specified in Sec.
98.232(j)(8), you must calculate volumetric emissions as specified in
paragraph (o)(10) of this section and calculate CH4 and
CO2 mass emissions as specified in paragraph (o)(11) of this
section. If emissions from a compressor source are routed to a
[[Page 42266]]
flare, paragraphs (o)(1) through (11) of this section do not apply and
instead you must calculate CH4, CO2, and
N2O emissions as specified in paragraph (n) of this section
and report emissions from the flare as specified in Sec. 98.236(n). If
emissions from a compressor source are routed to combustion, paragraphs
(o)(1) through (11) of this section do not apply and instead you must
calculate and report emissions as specified in subpart C of this part
or paragraph (z) of this section, as applicable. If emissions from a
compressor source are routed to a vapor recovery system, paragraphs
(o)(1) through (11) of this section do not apply.
(1) General requirements for conducting volumetric emission
measurements. You must conduct volumetric emission measurements on each
centrifugal compressor as specified in this paragraph. Compressor
sources (as defined in Sec. 98.238) without manifolded vents must use
a measurement method specified in paragraph (o)(1)(i) or (ii) of this
section. Manifolded compressor sources (as defined in Sec. 98.238)
must use a measurement method specified in paragraph (o)(1)(i), (ii),
(iii), or (iv) of this section.
(i) Centrifugal compressor source as found measurements. Measure
venting from each compressor according to either paragraph
(o)(1)(i)(A), (B), or (C) of this section at least once annually, based
on the compressor mode (as defined in Sec. 98.238) in which the
compressor was found at the time of measurement, except as specified in
paragraph (o)(1)(i)(D) of this section. If additional measurements
beyond the required annual testing are performed (including duplicate
measurements or measurement of additional operating modes), then all
measurements satisfying the applicable monitoring and QA/QC that is
required by this paragraph (o) must be used in the calculations
specified in this section.
(A) For a compressor measured in operating-mode, you must measure
volumetric emissions from blowdown valve leakage through the blowdown
vent as specified in paragraph (o)(2)(i) of this section, measure
volumetric emissions from wet seal oil degassing vents as specified in
paragraph (o)(2)(ii) of this section if the compressor has wet seal oil
degassing vents, and measure volumetric emissions from dry seal vents
as specified in paragraph (o)(2)(iii) of this section if the compressor
has dry seals.
(B) For a compressor measured in not-operating-depressurized-mode,
you must measure volumetric emissions from isolation valve leakage as
specified in paragraph (o)(2)(i) of this section. If a compressor is
not operated and has blind flanges in place throughout the reporting
period, measurement is not required in this compressor mode.
(C) For a compressor measured in standby-pressurized-mode, you must
measure volumetric emissions from blowdown valve leakage through the
blowdown vent as specified in paragraph (o)(2)(i) of this section,
measure volumetric emissions from wet seal oil degassing vents as
specified in paragraph (o)(2)(ii) of this section if the compressor has
wet seal oil degassing vents, and measure volumetric emissions from dry
seal vents as specified in paragraph (o)(2)(iii) of this section if the
compressor has dry seals.
(D) An annual as found measurement is not required in the first
year of operation for any new compressor that begins operation after as
found measurements have been conducted for all existing compressors.
For only the first year of operation of new compressors, calculate
emissions according to paragraph (o)(6)(ii) of this section.
(ii) Centrifugal compressor source continuous monitoring. Instead
of measuring the compressor source according to paragraph (o)(1)(i) of
this section for a given compressor, you may elect to continuously
measure volumetric emissions from a compressor source as specified in
paragraph (o)(3) of this section.
(iii) Manifolded centrifugal compressor source as found
measurements. For a compressor source that is part of a manifolded
group of compressor sources (as defined in Sec. 98.238), instead of
measuring the compressor source according to paragraph (o)(1)(i), (ii),
or (iv) of this section, you may elect to measure combined volumetric
emissions from the manifolded group of compressor sources by conducting
measurements at the common vent stack as specified in paragraph (o)(4)
of this section. The measurements must be conducted at the frequency
specified in paragraphs (o)(1)(iii)(A) and (B) of this section.
(A) A minimum of one measurement must be taken for each manifolded
group of compressor sources in a calendar year.
(B) The measurement may be performed while the compressors are in
any compressor mode.
(iv) Manifolded centrifugal compressor source continuous
monitoring. For a compressor source that is part of a manifolded group
of compressor sources, instead of measuring the compressor source
according to paragraph (o)(1)(i), (ii), or (iii) of this section, you
may elect to continuously measure combined volumetric emissions from
the manifolded group of compressor sources as specified in paragraph
(o)(5) of this section.
(2) Methods for performing as found measurements from individual
centrifugal compressor sources. If conducting measurements for each
compressor source, you must determine the volumetric emissions from
blowdown valves and isolation valves as specified in paragraph
(o)(2)(i) of this section, the volumetric emissions from wet seal oil
degassing vents as specified in paragraph (o)(2)(ii) of this section,
and the volumetric emissions from dry seal vents as specified in
paragraph (o)(2)(iii) of this section.
(i) For blowdown valves on compressors in operating-mode or in
standby-pressurized-mode and for isolation valves on compressors in
not-operating-depressurized-mode, determine the volumetric emissions
using one of the methods specified in paragraphs (o)(2)(i)(A) through
(D) of this section.
(A) Determine the volumetric flow at standard conditions from the
blowdown vent using calibrated bagging or high volume sampler according
to methods set forth in Sec. 98.234(c) and Sec. 98.234(d),
respectively.
(B) Determine the volumetric flow at standard conditions from the
blowdown vent using a temporary meter such as a vane anemometer
according to methods set forth in Sec. 98.234(b).
(C) Use an acoustic leak detection device according to methods set
forth in Sec. 98.234(a)(5).
(D) You may choose to use any of the methods set forth in Sec.
98.234(a) to screen for emissions. If emissions are detected using the
methods set forth in Sec. 98.234(a), then you must use one of the
methods specified in paragraph (o)(2)(i)(A) through (C) of this
section. If emissions are not detected using the methods in Sec.
98.234(a), then you may assume that the volumetric emissions are zero.
For the purposes of this paragraph, when using any of the methods in
Sec. 98.234(a), emissions are detected whenever a leak is detected
according to the methods.
(ii) For wet seal oil degassing vents in operating-mode or in
standby-pressurized-mode, determine volumetric flow at standard
conditions, using one of the methods specified in paragraphs
(o)(2)(ii)(A) through (C) of this section. You must quantitatively
measure the volumetric flow for wet seal oil degassing vent; you may
not use screening methods set forth in
[[Page 42267]]
Sec. 98.234(a) to screen for emissions for the wet seal oil degassing
vent.
(A) Use a temporary meter such as a vane anemometer or permanent
flow meter according to methods set forth in Sec. 98.234(b).
(B) Use calibrated bags according to methods set forth in Sec.
98.234(c).
(C) Use a high volume sampler according to methods set forth in
Sec. 98.234(d).
(iii) For dry seal vents in operating-mode or in standby-
pressurized-mode, determine volumetric flow at standard conditions from
each dry seal vent using one of the methods specified in paragraphs
(o)(2)(iii)(A) through (D) of this section. The measurement should be
conducted on the compressor side dry seal. If a compressor has more
than one dry seal vent, determine the aggregate dry seal vent
volumetric flow for the compressor as the sum of the volumetric flows
determined for each dry seal vent on the compressor.
(A) Use a temporary meter such as a vane anemometer or permanent
flow meter according to methods set forth in Sec. 98.234(b).
(B) Use calibrated bags according to methods set forth in Sec.
98.234(c).
(C) Use a high volume sampler according to methods set forth in
Sec. 98.234(d).
(D) You may choose to use any of the methods set forth in Sec.
98.234(a)(1) through (3) to screen for emissions. If emissions are
detected using one of these specified methods, then you must use one of
the methods specified in paragraph (o)(2)(iii)(A) through (C) of this
section. If emissions are not detected using the methods in Sec.
98.234(a)(1) through (3), then you may assume that the volumetric
emissions are zero. For the purposes of this paragraph, when using any
of the methods in Sec. 98.234(a), emissions are detected whenever a
leak is detected according to the methods. Acoustic leak detection is
only applicable for through-valve leakage and is not applicable for
screening dry seal vents.
(3) Methods for continuous measurement from individual centrifugal
compressor sources. If you elect to conduct continuous volumetric
emission measurements for an individual compressor source as specified
in paragraph (o)(1)(ii) of this section, you must measure volumetric
emissions as specified in paragraphs (o)(3)(i) and (ii) of this
section.
(i) Continuously measure the volumetric flow for the individual
compressor source at standard conditions using a permanent meter
according to methods set forth in Sec. 98.234(b).
(ii) If compressor blowdown emissions are included in the metered
emissions specified in paragraph (o)(3)(i) of this section, the
compressor blowdown emissions may be included with the reported
emissions for the compressor source and do not need to be calculated
separately using the method specified in paragraph (i) of this section
for blowdown vent stacks.
(4) Methods for performing as found measurements from manifolded
groups of centrifugal compressor sources. If conducting measurements
for a manifolded group of compressor sources, you must measure
volumetric emissions as specified in paragraphs (o)(4)(i) and (ii) of
this section.
(i) Measure at a single point in the manifold downstream of all
compressor inputs and, if practical, prior to comingling with other
non-compressor emission sources.
(ii) Determine the volumetric flow at standard conditions from the
common stack using one of the methods specified in paragraphs
(o)(4)(ii)(A) through (F) of this section.
(A) A temporary meter such as a vane anemometer according the
methods set forth in Sec. 98.234(b).
(B) Calibrated bagging according to methods set forth in Sec.
98.234(c).
(C) A high volume sampler according to methods set forth Sec.
98.234(d).
(D) [Reserved]
(E) You may choose to use any of the methods set forth in Sec.
98.234(a)(1) through (3) to screen for emissions. If emissions are
detected using one of these methods, then you must use one of the
methods specified in paragraph (o)(4)(ii)(A) through (D) of this
section. If emissions are not detected using the methods in Sec.
98.234(a)(1) through (3), then you may assume that the volumetric
emissions are zero. For the purposes of this paragraph, when using any
of the methods in Sec. 98.234(a), emissions are detected whenever a
leak is detected according to the method. Acoustic leak detection is
only applicable for through-valve leakage and is not applicable for
screening a manifolded group of compressor sources.
(F) If one of the screening methods specified in Sec. 98.234(a)(1)
through (3) identifies a leak in a manifolded group of centrifugal
compressor sources, you may use acoustic leak detection, according to
Sec. 98.234(a)(5), to identify the source of the leak. You must use
one of the methods specified in paragraphs (o)(4)(ii)(A) through (D) of
this section to quantify emissions from the identified source.
(5) Methods for continuous measurement from manifolded groups of
centrifugal compressor sources. If you elect to conduct continuous
volumetric emission measurements for a manifolded group of compressor
sources as specified in paragraph (o)(1)(iv) of this section, you must
measure volumetric emissions as specified in paragraphs (o)(5)(i)
through (iii) of this section.
(i) Measure at a single point in the manifold downstream of all
compressor inputs and, if practical, prior to comingling with other
non-compressor emission sources.
(ii) Continuously measure the volumetric flow for the manifolded
group of compressor sources at standard conditions using a permanent
meter according to methods set forth in Sec. 98.234(b).
(iii) If compressor blowdown emissions are included in the metered
emissions specified in paragraph (o)(5)(ii) of this section, the
compressor blowdown emissions may be included with the reported
emissions for the manifolded group of compressor sources and do not
need to be calculated separately using the method specified in
paragraph (i) of this section for blowdown vent stacks.
(6) Method for calculating volumetric GHG emissions from as found
measurements for individual centrifugal compressor sources. For
compressor sources measured according to paragraph (o)(1)(i) of this
section, you must calculate annual GHG emissions from the compressor
sources as specified in paragraphs (o)(6)(i) through (iv) of this
section.
(i) Using equation W-21 to this section, calculate the annual
volumetric GHG emissions for each centrifugal compressor mode-source
combination specified in paragraphs (o)(1)(i)(A) through (C) of this
section that was measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TR14MY24.077
[[Page 42268]]
Where:
Es,i,m = Annual volumetric GHGi (either
CH4 or CO2) emissions for measured compressor
mode-source combination m, at standard conditions, in cubic feet.
MTs,m = Volumetric gas emissions for measured compressor
mode-source combination m, in standard cubic feet per hour, measured
according to paragraph (o)(2) of this section. If multiple
measurements are performed for a given mode-source combination m,
use the average of all measurements.
Tm = Total time the compressor is in the mode-source
combination for which Es,i,m is being calculated in the reporting
year, in hours.
GHGi,m = Mole fraction of GHGi in the vent gas
for measured compressor mode-source combination m; use the
appropriate gas compositions in paragraph (u)(2) of this section.
m = Compressor mode-source combination specified in paragraph
(o)(1)(i)(A), (B), or (C) of this section that was measured for the
reporting year.
(ii) Using equation W-22 to this section, calculate the annual
volumetric GHG emissions from each centrifugal compressor mode-source
combination specified in paragraphs (o)(1)(i)(A) through (C) of this
section that was not measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TR14MY24.078
Where:
Es,i,m = Annual volumetric GHGi (either
CH4 or CO2) emissions for unmeasured
compressor mode-source combination m, at standard conditions, in
cubic feet.
EFs,m = Reporter emission factor for compressor mode-
source combination m, in standard cubic feet per hour, as calculated
in paragraph (o)(6)(iii) of this section.
Tm = Total time the compressor was in the unmeasured
mode-source combination m, for which Es,i,m is being calculated in
the reporting year, in hours.
GHGi,m = Mole fraction of GHGi in the vent gas
for unmeasured compressor mode-source combination m; use the
appropriate gas compositions in paragraph (u)(2) of this section.
m = Compressor mode-source combination specified in paragraph
(o)(1)(i)(A), (B), or (C) of this section that was not measured in
the reporting year.
(iii) Using equation W-23 to this section, develop an emission
factor for each compressor mode-source combination specified in
paragraphs (o)(1)(i)(A) through (C) of this section. These emission
factors must be calculated annually and used in equation W-22 to this
section to determine volumetric emissions from a centrifugal compressor
in the mode-source combinations that were not measured in the reporting
year.
EFs,m = Reporter emission factor to be used in equation
W-22 to this section for compressor mode-source combination m, in
standard cubic feet per hour. The reporter emission factor must be
based on all compressors measured in compressor mode-source
combination m in the current reporting year and the preceding two
reporting years.
MTs,m,p = Average volumetric gas emission measurement for
compressor mode-source combination m, for compressor p, in standard
cubic feet per hour, calculated using all volumetric gas emission
measurements (MTs,m in equation W-21 to this section) for
compressor mode-source combination m for compressor p in the current
reporting year and the preceding two reporting years.
Countm = Total number of compressors measured in
compressor mode-source combination m in the current reporting year
and the preceding two reporting years.
m = Compressor mode-source combination specified in paragraph
(o)(1)(i)(A), (B), or (C) of this section.
(iv) The reporter emission factor in equation W-23 to this section
may be calculated by using all measurements from a single owner or
operator instead of only using measurements from a single facility. If
you elect to use this option, the reporter emission factor must be
applied to all reporting facilities for the owner or operator.
(7) Method for calculating volumetric GHG emissions from continuous
monitoring of individual centrifugal compressor sources. For compressor
sources measured according to paragraph (o)(1)(ii) of this section, you
must use the continuous volumetric emission measurements taken as
specified in paragraph (o)(3) of this section and calculate annual
volumetric GHG emissions associated with the compressor source using
equation W-24A to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.079
Where:
Es,i,v = Annual volumetric GHGi (either
CH4 or CO2) emissions from compressor source
v, at standard conditions, in cubic feet.
Qs,v = Volumetric gas emissions from compressor source v,
for reporting year, in standard cubic feet.
GHGi,v = Mole fraction of GHGi in the vent gas
for compressor source v; use the appropriate gas compositions in
paragraph (u)(2) of this section.
(8) Method for calculating volumetric GHG emissions from as found
measurements of manifolded groups of centrifugal compressor sources.
For manifolded groups of compressor sources measured according to
paragraph (o)(1)(iii) of this section, you must calculate annual
volumetric GHG emissions using equation W-24B to this section. If the
centrifugal compressors included in the manifolded group of compressor
sources share the manifold with reciprocating compressors, you must
follow the procedures in either this paragraph (o)(8) or paragraph
(p)(8) of this section to calculate emissions from the manifolded group
of compressor sources.
[GRAPHIC] [TIFF OMITTED] TR14MY24.080
Where:
Es,i,g = Annual volumetric GHGi (either
CH4 or CO2) emissions for manifolded group of
compressor sources g, at standard conditions, in cubic feet.
Tg = Total time the manifolded group of compressor
sources g had potential for emissions in the reporting year, in
hours. Include all time during which at least one compressor source
in the manifolded group of compressor sources g was in a mode-source
combination specified in either paragraph (o)(1)(i)(A),
(o)(1)(i)(B), (o)(1)(i)(C), (p)(1)(i)(A), (p)(1)(i)(B), or
(p)(1)(i)(C) of this section. Default of
[[Page 42269]]
8760 hours may be used. MTs,g,avg = Average volumetric
gas emissions of all measurements performed in the reporting year
according to paragraph (o)(4) of this section for the manifolded
group of compressor sources g, in standard cubic feet per hour.
GHGi,g = Mole fraction of GHGi in the vent gas
for manifolded group of compressor sources g; use the appropriate
gas compositions in paragraph (u)(2) of this section.
(9) Method for calculating volumetric GHG emissions from continuous
monitoring of manifolded group of centrifugal compressor sources. For a
manifolded group of compressor sources measured according to paragraph
(o)(1)(iv) of this section, you must use the continuous volumetric
emission measurements taken as specified in paragraph (o)(5) of this
section and calculate annual volumetric GHG emissions associated with
each manifolded group of compressor sources using equation W-24C to
this section. If the centrifugal compressors included in the manifolded
group of compressor sources share the manifold with reciprocating
compressors, you must follow the procedures in either this paragraph
(o)(9) or paragraph (p)(9) of this section to calculate emissions from
the manifolded group of compressor sources.
[GRAPHIC] [TIFF OMITTED] TR14MY24.081
Where:
Es,i,g = Annual volumetric GHGi (either
CH4 or CO2) emissions from manifolded group of
compressor sources g, at standard conditions, in cubic feet.
Qs,g = Volumetric gas emissions from manifolded group of
compressor sources g, for reporting year, in standard cubic feet.
GHGi,g = Mole fraction of GHGi in the vent gas
for measured manifolded group of compressor sources g; use the
appropriate gas compositions in paragraph (u)(2) of this section.
(10) Method for calculating volumetric GHG emissions from wet seal
oil degassing vents at an onshore petroleum and natural gas production
facility or an onshore petroleum and natural gas gathering and boosting
facility. You must calculate volumetric emissions from centrifugal
compressors at an onshore petroleum and natural gas production facility
or an onshore petroleum and natural gas gathering and boosting facility
as specified in paragraphs (o)(10)(i) through (iv), as applicable.
(i) For all centrifugal compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility that are subject to the centrifugal
compressor standards in Sec. 60.5380b of this chapter or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter for dry seals and self-contained wet seals, you must conduct
the volumetric emission measurements as required by Sec.
60.5380b(a)(5) of this chapter or an applicable approved state plan or
applicable Federal plan in part 62 of this chapter, conduct all
additional volumetric emission measurements specified in paragraph
(o)(1) of this section using methods specified in paragraphs (o)(2)
through (5) of this section (based on the compressor mode (as defined
in Sec. 98.238) in which the compressor was found at the time of
measurement), and calculate emissions as specified in paragraphs (o)(6)
through (9) of this section. Conduct all measurements required by this
paragraph (o)(10)(i) at the frequency specified by Sec. 60.5380b(a)(4)
of this chapter or an applicable approved state plan or applicable
Federal plan in part 62 of this chapter. For any reporting year in
which measuring at the frequency specified by Sec. 60.5380b(a)(4) of
this chapter results in measurement not being required for a subject
compressor, calculate emissions for all mode-source combinations as
specified in paragraph (o)(6)(ii) of this section.
(ii) For all centrifugal compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility that are not subject to the centrifugal
compressor standards in Sec. 60.5380b of this chapter or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter for dry seals and self-contained wet seals, you may elect to
conduct the volumetric emission measurements specified in paragraph
(o)(1) of this section using methods specified in paragraphs (o)(2)
through (5) of this section (based on the compressor mode (as defined
in Sec. 98.238) in which the compressor was found at the time of
measurement), and calculate emissions as specified in paragraphs (o)(6)
through (9) of this section.
(iii) For all centrifugal compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility for which paragraph (o)(10)(i) of this
section does not apply and you do not elect to conduct the volumetric
measurements specified in paragraph (o)(1) of this section, you must
calculate total atmospheric wet seal oil degassing vent emissions from
all centrifugal compressors at either an onshore petroleum and natural
gas production facility or an onshore petroleum and natural gas
gathering and boosting facility using equation W-25A to this section.
Emissions from centrifugal compressor wet seal oil degassing vents that
are routed to a flare, combustion, or vapor recovery system are not
required to be determined under this paragraph (o).
[GRAPHIC] [TIFF OMITTED] TR14MY24.082
Where:
Es,i = Annual volumetric GHGi (either
CH4 or CO2) emissions from all centrifugal
compressors, at standard conditions, in cubic feet.
Count = Total number of centrifugal compressors with wet seal oil
degassing vents that are vented directly to the atmosphere.
Es,i,p = Annual volumetric GHGi (either
CH4 or CO2) emissions for centrifugal
compressor p, at standard conditions, in cubic feet, calculated
using equation W-25B to this section.
(iv) For all centrifugal compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility for which paragraph (o)(10)(i) of this
section does not apply,
[[Page 42270]]
and you do not elect to conduct the volumetric measurements specified
in paragraph (o)(1) of this section, you must calculate wet seal oil
degassing vent emissions from each centrifugal compressor using
equation W-25B to this section. Emissions from centrifugal compressor
wet seal oil degassing vents that are routed to a flare, combustion, or
vapor recovery system are not required to be determined under this
paragraph (o).
[GRAPHIC] [TIFF OMITTED] TR14MY24.083
Where:
Es,i,p = Annual volumetric GHGi (either
CH4 or CO2) emissions for centrifugal
compressor p, at standard conditions, in cubic feet.
EFs,p = Emission factor for centrifugal compressor p, in
standard cubic feet per year. Use 1.2 x 107 standard cubic feet per
year per compressor for CH4 and 5.30 x 105 standard cubic
feet per year per compressor for CO2 at 60 [deg]F and
14.7 psia.
Tp = Total time centrifugal compressor p was in operating
mode, for which Es,i,p is being calculated in the reporting year, in
hours.
Ttotal = Total hours per year. Use 8784 in leap years and
use 8760 in all other years.
GHGi,p = Mole fraction of GHG (either CH4 or
CO2) in the vent gas for centrifugal compressor p in
operating mode; use the appropriate gas compositions in paragraph
(u)(2) of this section.
GHGEF = Mole fraction of GHG (either CH4 or
CO2) used in the determination of EFs,p. Use
0.95 for CH4 and 0.05 for CO2.
(11) Method for converting from volumetric to mass emissions. You
must calculate both CH4 and CO2 mass emissions
from volumetric emissions using calculations in paragraph (v) of this
section.
(p) Reciprocating compressor venting. If you are required to report
emissions from reciprocating compressor venting as specified in Sec.
98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct
volumetric emission measurements specified in paragraph (p)(1) of this
section using methods specified in paragraphs (p)(2) through (5) of
this section; perform calculations specified in paragraphs (p)(6)
through (9) of this section; and calculate CH4 and
CO2 mass emissions as specified in paragraph (p)(11) of this
section. If you are required to report emissions from reciprocating
compressor venting at an onshore petroleum and natural gas production
facility as specified in Sec. 98.232(c)(11) or an onshore petroleum
and natural gas gathering and boosting facility as specified in Sec.
98.232(j)(9), you must calculate volumetric emissions as specified in
paragraph (p)(10) of this section and calculate CH4 and
CO2 mass emissions as specified in paragraph (p)(11) of this
section. If emissions from a compressor source are routed to a flare,
paragraphs (p)(1) through (11) of this section do not apply and instead
you must calculate CH4, CO2, and N2O
emissions as specified in paragraph (n) of this section and report
emissions from the flare as specified in Sec. 98.236(n). If emissions
from a compressor source are routed to combustion, paragraphs (p)(1)
through (11) of this section do not apply and instead you must
calculate and report emissions as specified in subpart C of this part
or paragraph (z) of this section, as applicable. If emissions from a
compressor source are routed to a vapor recovery system, paragraphs
(p)(1) through (11) of this section do not apply.
(1) General requirements for conducting volumetric emission
measurements. You must conduct volumetric emission measurements on each
reciprocating compressor as specified in this paragraph. Compressor
sources (as defined in Sec. 98.238) without manifolded vents must use
a measurement method specified in paragraph (p)(1)(i) or (ii) of this
section. Manifolded compressor sources (as defined in Sec. 98.238)
must use a measurement method specified in paragraph (p)(1)(i), (ii),
(iii), or (iv) of this section.
(i) Reciprocating compressor source as found measurements. Measure
venting from each compressor according to either paragraph
(p)(1)(i)(A), (B), or (C) of this section at least once annually, based
on the compressor mode (as defined in Sec. 98.238) in which the
compressor was found at the time of measurement, except as specified in
paragraph (p)(1)(i)(D) of this section. If additional measurements
beyond the required annual testing are performed (including duplicate
measurements or measurement of additional operating modes), then all
measurements satisfying the applicable monitoring and QA/QC that is
required by this paragraph (p) must be used in the calculations
specified in this section.
(A) For a compressor measured in operating-mode, you must measure
volumetric emissions from blowdown valve leakage through the blowdown
vent as specified in paragraph (p)(2)(i) of this section, and measure
volumetric emissions from reciprocating rod packing as specified in
paragraph (p)(2)(ii) or (iii) of this section, as applicable.
(B) For a compressor measured in not-operating-depressurized-mode,
you must measure volumetric emissions from isolation valve leakage as
specified in paragraph (p)(2)(i) of this section. If a compressor is
not operated and has blind flanges in place throughout the reporting
period, measurement is not required in this compressor mode.
(C) For a compressor measured in standby-pressurized-mode, you must
measure volumetric emissions from blowdown valve leakage through the
blowdown vent as specified in paragraph (p)(2)(i) of this section and
measure volumetric emissions from reciprocating rod packing as
specified in paragraph (p)(2)(ii) or (iii) of this section, as
applicable.
(D) An annual as found measurement is not required in the first
year of operation for any new compressor that begins operation after as
found measurements have been conducted for all existing compressors.
For only the first year of operation of new compressors, calculate
emissions according to paragraph (p)(6)(ii) of this section.
(ii) Reciprocating compressor source continuous monitoring. Instead
of measuring the compressor source according to paragraph (p)(1)(i) of
this section for a given compressor, you may elect to continuously
measure volumetric emissions from a compressor source as specified in
paragraph (p)(3) of this section.
(iii) Manifolded reciprocating compressor source as found
measurements. For a compressor source that is part of a manifolded
group of compressor sources (as defined in Sec. 98.238), instead of
measuring the compressor source according to paragraph (p)(1)(i), (ii),
or (iv) of this section, you may elect to measure combined volumetric
emissions from the manifolded group of compressor sources by conducting
measurements at the common vent stack as specified in paragraph (p)(4)
of this section. The measurements must be conducted at the
[[Page 42271]]
frequency specified in paragraphs (p)(1)(iii)(A) and (B) of this
section.
(A) A minimum of one measurement must be taken for each manifolded
group of compressor sources in a calendar year.
(B) The measurement may be performed while the compressors are in
any compressor mode.
(iv) Manifolded reciprocating compressor source continuous
monitoring. For a compressor source that is part of a manifolded group
of compressor sources, instead of measuring the compressor source
according to paragraph (p)(1)(i), (ii), or (iii) of this section, you
may elect to continuously measure combined volumetric emissions from
the manifolded group of compressors sources as specified in paragraph
(p)(5) of this section.
(2) Methods for performing as found measurements from individual
reciprocating compressor sources. If conducting measurements for each
compressor source, you must determine the volumetric emissions from
blowdown valves and isolation valves as specified in paragraph
(p)(2)(i) of this section. You must determine the volumetric emissions
from reciprocating rod packing as specified in paragraph (p)(2)(ii) or
(iii) of this section, as applicable.
(i) For blowdown valves on compressors in operating-mode or
standby-pressurized-mode, and for isolation valves on compressors in
not-operating-depressurized-mode, determine the volumetric emissions
using one of the methods specified in paragraphs (p)(2)(i)(A) through
(D) of this section.
(A) Determine the volumetric flow at standard conditions from the
blowdown vent using calibrated bagging or high volume sampler according
to methods set forth in Sec. 98.234(c) and (d), respectively.
(B) Determine the volumetric flow at standard conditions from the
blowdown vent using a temporary meter such as a vane anemometer,
according to methods set forth in Sec. 98.234(b).
(C) Use an acoustic leak detection device according to methods set
forth in Sec. 98.234(a)(5).
(D) You may choose to use any of the methods set forth in Sec.
98.234(a) to screen for emissions. If emissions are detected using the
methods set forth in Sec. 98.234(a), then you must use one of the
methods specified in paragraphs (p)(2)(i)(A) through (C) of this
section. If emissions are not detected using the methods in Sec.
98.234(a), then you may assume that the volumetric emissions are zero.
For the purposes of this paragraph, when using any of the methods in
Sec. 98.234(a), emissions are detected whenever a leak is detected
according to the method.
(ii) For reciprocating rod packing equipped with an open-ended vent
line on compressors in operating-mode or standby-pressurized-mode,
determine the volumetric emissions using one of the methods specified
in paragraphs (p)(2)(ii)(A) through (C) of this section.
(A) Determine the volumetric flow at standard conditions from the
open-ended vent line using calibrated bagging or high volume sampler
according to methods set forth in Sec. 98.234(c) and (d),
respectively.
(B) Determine the volumetric flow at standard conditions from the
open-ended vent line using a temporary meter such as a vane anemometer,
according to methods set forth in Sec. 98.234(b).
(C) You may choose to use any of the methods set forth in Sec.
98.234(a)(1) through (3) to screen for emissions. If emissions are
detected using one of these specified methods, then you must use one of
the methods specified in paragraphs (p)(2)(ii)(A) and (B) of this
section. If emissions are not detected using the methods in Sec.
98.234(a)(1) through (3), then you may assume that the volumetric
emissions are zero. For the purposes of this paragraph (p)(2)(ii)(C),
when using any of the methods in Sec. 98.234(a), emissions are
detected whenever a leak is detected according to the method. Acoustic
leak detection is only applicable for through-valve leakage and is not
applicable for screening or measuring rod packing emissions.
(iii) For reciprocating rod packing not equipped with an open-ended
vent line on compressors in operating-mode, you must determine the
volumetric emissions using the method specified in paragraphs
(p)(2)(iii)(A) and (B) of this section.
(A) You must use the methods described in Sec. 98.234(a)(1)
through (3) to conduct annual leak detection of equipment leaks from
the packing case into an open distance piece, or for compressors with a
closed distance piece, conduct annual detection of gas emissions from
the rod packing vent, distance piece vent, compressor crank case
breather cap, or other vent emitting gas from the rod packing. Acoustic
leak detection is only applicable for through-valve leakage and is not
applicable for screening rod packing emissions.
(B) You must measure emissions found in paragraph (p)(2)(iii)(A) of
this section using an appropriate meter, calibrated bag, or high volume
sampler according to methods set forth in Sec. 98.234(b), (c), and
(d), respectively.
(3) Methods for continuous measurement from individual
reciprocating compressor sources. If you elect to conduct continuous
volumetric emission measurements for an individual compressor source as
specified in paragraph (p)(1)(ii) of this section, you must measure
volumetric emissions as specified in paragraphs (p)(3)(i) and
(p)(3)(ii) of this section.
(i) Continuously measure the volumetric flow for the individual
compressor sources at standard conditions using a permanent meter
according to methods set forth in Sec. 98.234(b).
(ii) If compressor blowdown emissions are included in the metered
emissions specified in paragraph (p)(3)(i) of this section, the
compressor blowdown emissions may be included with the reported
emissions for the compressor source and do not need to be calculated
separately using the method specified in paragraph (i) of this section
for blowdown vent stacks.
(4) Methods for performing as found measurements from manifolded
groups of reciprocating compressor sources. If conducting measurements
for a manifolded group of compressor sources, you must measure
volumetric emissions as specified in paragraphs (p)(4)(i) and (ii) of
this section.
(i) Measure at a single point in the manifold downstream of all
compressor inputs and, if practical, prior to comingling with other
non-compressor emission sources.
(ii) Determine the volumetric flow at standard conditions from the
common stack using one of the methods specified in paragraph
(p)(4)(ii)(A) through (F) of this section.
(C) A high volume sampler according to methods set forth in Sec.
98.234(d).
(D) [Reserved]
(E) You may choose to use any of the methods set forth in Sec.
98.234(a)(1) through (3) to screen for emissions. If emissions are
detected using one of these specified methods, then you must use one of
the methods specified in paragraphs (p)(4)(ii)(A) through (D) of this
section. If emissions are not detected using the methods in Sec.
98.234(a)(1) through (3), then you may assume that the volumetric
emissions are zero. For the purposes of this paragraph, when using any
of the methods in Sec. 98.234(a), emissions are detected whenever a
leak is detected according to the method. Acoustic leak detection is
only applicable for through-valve leakage and is not applicable for
screening a manifolded group of compressor sources.
(F) If one of the screening methods specified in Sec. 98.234(a)(1)
through (3)
[[Page 42272]]
identifies a leak in a manifolded group of reciprocating compressor
sources, you may use acoustic leak detection, according to Sec.
98.234(a)(5), to identify the source of the leak. You must use one of
the methods specified in paragraphs (p)(4)(ii)(A) through (D) of this
section to quantify the emissions from the identified source.
(5) Methods for continuous measurement from manifolded groups of
reciprocating compressor sources. If you elect to conduct continuous
volumetric emission measurements for a manifolded group of compressor
sources as specified in paragraph (p)(1)(iv) of this section, you must
measure volumetric emissions as specified in paragraphs (p)(5)(i)
through (iii) of this section.
(i) Measure at a single point in the manifold downstream of all
compressor inputs and, if practical, prior to comingling with other
non-compressor emission sources.
(ii) Continuously measure the volumetric flow for the manifolded
group of compressor sources at standard conditions using a permanent
meter according to methods set forth in Sec. 98.234(b).
(iii) If compressor blowdown emissions are included in the metered
emissions specified in paragraph (p)(5)(ii) of this section, the
compressor blowdown emissions may be included with the reported
emissions for the manifolded group of compressor sources and do not
need to be calculated separately using the method specified in
paragraph (i) of this section for blowdown vent stacks.
(6) Method for calculating volumetric GHG emissions from as found
measurements for individual reciprocating compressor sources. For
compressor sources measured according to paragraph (p)(1)(i) of this
section, you must calculate GHG emissions from the compressor sources
as specified in paragraphs (p)(6)(i) through (iv) of this section.
(i) Using equation W-26 to this section, calculate the annual
volumetric GHG emissions for each reciprocating compressor mode-source
combination specified in paragraphs (p)(1)(i)(A) through (C) of this
section that was measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TR14MY24.084
Where:
Es,i,m = Annual volumetric GHGi (either
CH4 or CO2) emissions for measured compressor
mode-source combination m, at standard conditions, in cubic feet.
MTs,m = Volumetric gas emissions for measured compressor
mode-source combination m, in standard cubic feet per hour, measured
according to paragraph (p)(2) of this section. If multiple
measurements are performed for a given mode-source combination m,
use the average of all measurements.
Tm = Total time the compressor is in the mode-source
combination m, for which Es,i,m is being calculated in the reporting
year, in hours.
GHGi,m = Mole fraction of GHGi in the vent gas
for measured compressor mode-source combination m; use the
appropriate gas compositions in paragraph (u)(2) of this section.
m = Compressor mode-source combination specified in paragraph
(p)(1)(i)(A), (B), or (C) of this section that was measured for the
reporting year.
(ii) Using equation W-27 to this section, calculate the annual
volumetric GHG emissions from each reciprocating compressor mode-source
combination specified in paragraphs (p)(1)(i)(A) through (C) of this
section that was not measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TR14MY24.085
Where:
Es,i,m = Annual volumetric GHGi (either
CH4 or CO2) emissions for unmeasured
compressor mode-source combination m, at standard conditions, in
cubic feet.
EFs,m = Reporter emission factor for compressor mode-
source combination m, in standard cubic feet per hour, as calculated
in paragraph (p)(6)(iii) of this section.
Tm = Total time the compressor was in the unmeasured
mode-source combination m, for which Es,i,m is being calculated in
the reporting year, in hours.
GHGi,m = Mole fraction of GHGi in the vent gas
for unmeasured compressor mode-source combination m; use the
appropriate gas compositions in paragraph (u)(2) of this section.
m = Compressor mode-source combination specified in paragraph
(p)(1)(i)(A), (p)(1)(i)(B), or (p)(1)(i)(C) of this section that was
not measured for the reporting year.
(iii) Using equation W-28 to this section, develop an emission
factor for each compressor mode-source combination specified in
paragraphs (p)(1)(i)(A) through (C) of this section. These emission
factors must be calculated annually and used in equation W-27 to this
section to determine volumetric emissions from a reciprocating
compressor in the mode-source combinations that were not measured in
the reporting year.
[GRAPHIC] [TIFF OMITTED] TR14MY24.086
Where:
EFs,m = Reporter emission factor to be used in equation
W-27 to this section for compressor mode-source combination m, in
standard cubic feet per hour. The reporter emission factor must be
based on all compressors measured in compressor mode-source
combination m in the current reporting year and the preceding two
reporting years.
MTs,m,p = Average volumetric gas emission measurement for
compressor mode-source combination m, for compressor p, in standard
cubic feet per hour, calculated using all volumetric gas emission
measurements (MTs,m in equation W-26 to this section) for
compressor mode-source combination m for compressor p in the current
reporting year and the preceding two reporting years.
[[Page 42273]]
Countm = Total number of compressors measured in
compressor mode-source combination m in the current reporting year
and the preceding two reporting years.
m = Compressor mode-source combination specified in paragraph
(p)(1)(i)(A), (B), or (C) of this section.
(iv) The reporter emission factor in equation W-28 to this section
may be calculated by using all measurements from a single owner or
operator instead of only using measurements from a single facility. If
you elect to use this option, the reporter emission factor must be
applied to all reporting facilities for the owner or operator.
(7) Method for calculating volumetric GHG emissions from continuous
monitoring of individual reciprocating compressor sources. For
compressor sources measured according to paragraph (p)(1)(ii) of this
section, you must use the continuous volumetric emission measurements
taken as specified in paragraph (p)(3) of this section and calculate
annual volumetric GHG emissions associated with the compressor source
using equation W-29A to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.087
Where:
Es,i,v = Annual volumetric GHGi (either
CH4 or CO2) emissions from compressor source
v, at standard conditions, in cubic feet.
Qs,v = Volumetric gas emissions from compressor source v,
for reporting year, in standard cubic feet.
GHGi,v = Mole fraction of GHGi in the vent gas
for compressor source v; use the appropriate gas compositions in
paragraph (u)(2) of this section.
(8) Method for calculating volumetric GHG emissions from as found
measurements of manifolded groups of reciprocating compressor sources.
For manifolded groups of compressor sources measured according to
paragraph (p)(1)(iii) of this section, you must calculate annual GHG
emissions using equation W-29B to this section. If the reciprocating
compressors included in the manifolded group of compressor sources
share the manifold with centrifugal compressors, you must follow the
procedures in either this paragraph (p)(8) or paragraph (o)(8) of this
section to calculate emissions from the manifolded group of compressor
sources.
[GRAPHIC] [TIFF OMITTED] TR14MY24.088
Where:
Es,i,g = Annual volumetric GHGi (either
CH4 or CO2) emissions for manifolded group of
compressor sources g, at standard conditions, in cubic feet.
Tg = Total time the manifolded group of compressor
sources g had potential for emissions in the reporting year, in
hours. Include all time during which at least one compressor source
in the manifolded group of compressor sources g was in a mode-source
combination specified in either paragraph (o)(1)(i)(A),
(o)(1)(i)(B), (o)(1)(i)(C), (p)(1)(i)(A), (p)(1)(i)(B), or
(p)(1)(i)(C) of this section. Default of 8760 hours may be used.
MTs,g,avg = Average volumetric gas emissions of all
measurements performed in the reporting year according to paragraph
(p)(4) of this section for the manifolded group of compressor
sources g, in standard cubic feet per hour.
GHGi,g = Mole fraction of GHGi in the vent gas
for manifolded group of compressor sources g; use the appropriate
gas compositions in paragraph (u)(2) of this section.
(9) Method for calculating volumetric GHG emissions from continuous
monitoring of manifolded group of reciprocating compressor sources. For
a manifolded group of compressor sources measured according to
paragraph (p)(1)(iv) of this section, you must use the continuous
volumetric emission measurements taken as specified in paragraph (p)(5)
of this section and calculate annual volumetric GHG emissions
associated with each manifolded group of compressor sources using
equation W-29C to this section. If the reciprocating compressors
included in the manifolded group of compressor sources share the
manifold with centrifugal compressors, you must follow the procedures
in either this paragraph (p)(9) or paragraph (o)(9) of this section to
calculate emissions from the manifolded group of compressor sources.
[GRAPHIC] [TIFF OMITTED] TR14MY24.089
Where:
Es,i,g = Annual volumetric GHGi (either
CH4 or CO2) emissions from manifolded group of
compressor sources g, at standard conditions, in cubic feet.
Qs,g = Volumetric gas emissions from manifolded group of
compressor sources g, for reporting year, in standard cubic feet.
GHGi,g = Mole fraction of GHGi in the vent gas
for measured manifolded group of compressor sources g; use the
appropriate gas compositions in paragraph (u)(2) of this section.
(10) Method for calculating volumetric GHG emissions from
reciprocating compressor venting at an onshore petroleum and natural
gas production facility or an onshore petroleum and natural gas
gathering and boosting facility. You must calculate volumetric
emissions from reciprocating compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility as specified in paragraphs (p)(10)(i)
through (iv) of this section, as applicable.
(i) For all reciprocating compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility that are subject to the reciprocating
compressor standards in Sec. 60.5385b of this chapter or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter, you must conduct the volumetric emission measurements as
required by Sec. 60.5385b(b) and (c) of this chapter or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter, conduct any additional volumetric emission measurements
specified in paragraph (p)(1) of this section using methods specified
in paragraphs (p)(2) through (5) of this section (based on the
compressor mode (as defined in
[[Page 42274]]
Sec. 98.238) in which the compressor was found at the time of
measurement), and calculate emissions as specified in paragraphs (p)(6)
through (9) of this section. Conduct all measurements required by this
paragraph (p)(10)(i) at the frequency specified by Sec. 60.5385b(a) of
this chapter or an applicable approved state plan or applicable Federal
plan in part 62 of this chapter. For any reporting year in which
measuring at the frequency specified by Sec. 60.5385b(a) of this
chapter results in measurement not being required for a subject
compressor, calculate emissions for all mode-source combinations as
specified in paragraph (p)(6)(ii) of this section.
(ii) For all reciprocating compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility that are not subject to the
reciprocating compressor standards in Sec. 60.5385b of this chapter or
an applicable approved state plan or applicable Federal plan in part 62
of this chapter, you may elect to conduct volumetric emission
measurements specified in paragraph (p)(1) of this section using
methods specified in paragraphs (p)(2) through (5) of this section
(based on the compressor mode (as defined in Sec. 98.238) in which the
compressor was found at the time of measurement), and calculate
emissions as specified in paragraphs (p)(6) through (9) of this
section.
(iii) For all reciprocating compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility for which paragraph (p)(10)(i) of this
section does not apply, and you do not elect to conduct volumetric
emission measurements specified in paragraph (p)(1) of this section,
you must calculate total atmospheric rod packing emissions from all
reciprocating compressors at either an onshore petroleum and natural
gas production facility or an onshore petroleum and natural gas
gathering and boosting facility using equation W-29D to this section.
Reciprocating compressor rod packing emissions that are routed to a
flare, combustion, or vapor recovery system are not required to be
determined under this paragraph (p).
[GRAPHIC] [TIFF OMITTED] TR14MY24.090
Where:
Es,i = Annual volumetric GHGi (either
CH4 or CO2) emissions from all reciprocating
compressors, at standard conditions, in cubic feet.
Count = Total number of reciprocating compressors with rod packing
emissions vented directly to the atmosphere.
Es,i,p = Annual volumetric GHGi (either
CH4 or CO2) emissions for reciprocating
compressor p, at standard conditions, in cubic feet, calculated
using equation W-29E to this section.
(iv) For all reciprocating compressors at an onshore petroleum and
natural gas production facility or an onshore petroleum and natural gas
gathering and boosting facility for which paragraph (p)(10)(i) of this
section does not apply, you must calculate rod packing vent emissions
from each reciprocating compressor using equation W-29E to this
section. Reciprocating compressor rod packing emissions that are routed
to a flare, combustion, or vapor recovery system are not required to be
determined under this paragraph (p).
[GRAPHIC] [TIFF OMITTED] TR14MY24.091
Where:
Es,i,p = Annual volumetric GHGi (either
CH4 or CO2) emissions for reciprocating
compressor p, at standard conditions, in cubic feet.
EFs,p = Emission factor for reciprocating compressor p,
in standard cubic feet per year. Use 2.13 x 10\5\ standard cubic
feet per year per compressor for CH4 and 1.18 x 10\4\
standard cubic feet per year per compressor for CO2 at 60
[deg]F and 14.7 psia.
Tp = Total time reciprocating compressor p was in
operating mode, for which Es,i,p, is being calculated in
the reporting year, in hours.
Ttotal = Total hours per year. Use 8784 in leap years and
use 8760 in all other years.
GHGi,p = Mole fraction of GHG (either CH4 or
CO2) in the vent gas for reciprocating compressor p in
operating mode; use the appropriate gas compositions in paragraph
(u)(2) of this section.
GHGEF = Mole fraction of GHG (either CH4 or
CO2) used in the determination of EFs,p. Use
0.98 for CH4 and 0.02 for CO2.
(11) Method for converting from volumetric to mass emissions. You
must calculate both CH4 and CO2 mass emissions
from volumetric emissions using calculations in paragraph (v) of this
section.
(q) Equipment leak surveys. For the components identified in
paragraphs (q)(1)(i) through (iii) and (v) of this section, you must
conduct equipment leak surveys using the leak detection methods
specified in paragraphs (q)(1)(i) through (iii) and (v) of this
section. For the components identified in paragraph (q)(1)(iv) and (vi)
of this section, you may elect to conduct equipment leak surveys, and
if you elect to conduct surveys, you must use a leak detection method
specified in paragraph (q)(1)(iv) and (vi) of this section. This
paragraph (q) applies to components in streams with gas content greater
than 10 percent CH4 plus CO2 by weight.
Components in streams with gas content less than or equal to 10 percent
CH4 plus CO2 by weight are exempt from the
requirements of this paragraph (q) and do not need to be reported.
Tubing systems equal to or less than one half inch diameter are exempt
from the requirements of this paragraph (q) and do not need to be
reported. Equipment leak components in vacuum service are exempt from
the survey and emission estimation requirements of this paragraph (q)
and only the count of these equipment must be reported.
(1) Survey requirements--(i) For the components listed in Sec.
98.232(e)(7), (f)(5), (g)(4), and (h)(5), that are not subject to the
well site or compressor station fugitive emissions standards in Sec.
60.5397a of this chapter, the fugitive emissions standards for well
sites, centralized production facilities, and compressor stations in
Sec. 60.5397b or 60.5398b of this chapter, or an applicable approved
state plan or
[[Page 42275]]
applicable Federal plan in part 62 of this chapter, you must conduct
surveys using any of the leak detection methods listed in Sec.
98.234(a) and calculate equipment leak emissions using the procedures
specified in either paragraph (q)(2) or (3) of this section.
(ii) For the components listed in Sec. 98.232(i)(1), you must
conduct surveys using any of the leak detection methods listed in Sec.
98.234(a) except Sec. 98.234(a)(2)(ii) and calculate equipment leak
emissions using the procedures specified in either paragraph (q)(2) or
(3) of this section.
(iii) For the components listed in Sec. 98.232(c)(21)(i), (e)(7)
and (8), (f)(5) through (8), (g)(4), (g)(6) and (7), (h)(5), (h)(7) and
(8), and (j)(10)(i) that are subject to the well site or compressor
station fugitive emissions standards in Sec. 60.5397a of this chapter,
the fugitive emissions standards for well sites, centralized production
facilities, and compressor stations in Sec. 60.5397b or 60.5398b of
this chapter, or an applicable approved state plan or applicable
Federal plan in part 62 of this chapter, and are required to conduct
surveys using any of the leak detection methods in Sec.
98.234(a)(1)(ii) or (iii) or (a)(2)(ii), as applicable, you must use
the results of those surveys to calculate equipment leak emissions
using the procedures specified in either paragraph (q)(2) or (3) of
this section.
(iv) For the components listed in Sec. 98.232(c)(21)(i), (e)(8),
(f)(6) through (8), (g)(6) or (7), (h)(7) or (8), or (j)(10)(i), that
are not subject to or are not required to conduct surveys using the
methods in Sec. 98.234(a) in accordance with the fugitive emissions
standards in Sec. 60.5397a of this chapter, the fugitive emissions
standards for well sites, centralized production facilities, and
compressor stations in Sec. 60.5397b or 60.5398b of this chapter, or
an applicable approved state plan or applicable Federal plan in part 62
of this chapter, you may elect to conduct surveys according to this
paragraph (q), and, if you elect to do so, then you must use one of the
leak detection methods in Sec. 98.234(a).
(A) If you elect to use a leak detection method in Sec. 98.234(a)
for the surveyed component types in Sec. 98.232(c)(21)(i), (f)(7),
(g)(6), (h)(7), or (j)(10)(i) in lieu of the population count
methodology specified in paragraph (r) of this section, then you must
calculate emissions for the surveyed component types in Sec.
98.232(c)(21)(i), (f)(7), (g)(6), (h)(7), or (j)(10)(i) using the
procedures in either paragraph (q)(2) or (3) of this section.
(B) If you elect to use a leak detection method in Sec. 98.234(a)
for the surveyed component types in Sec. 98.232(e)(8), (f)(6) and (8),
(g)(7), and (h)(8), then you must use the procedures in either
paragraph (q)(2) or (3) of this section to calculate those emissions.
(C) If you elect to use a leak detection method in Sec.
98.234(a)(1)(ii) or (iii) or (a)(2)(ii), as applicable, for any
elective survey under paragraph (q)(1)(iv) of this section, then you
must survey the component types in Sec. 98.232(c)(21)(i), (e)(8),
(f)(6) through (8), (g)(6) and (7), (h)(7) and (8), and (j)(10)(i) that
are not subject to or are not required to conduct surveys using the
methods in Sec. 98.234(a) in accordance with the fugitive emissions
standards in Sec. 60.5397a of this chapter, the fugitive emissions
standards for well sites, centralized production facilities, and
compressor stations in Sec. 60.5397b or 60.5398b of this chapter, or
an applicable approved state plan or applicable Federal plan in part 62
of this chapter, and you must calculate emissions from the surveyed
component types in Sec. 98.232(c)(21)(i), (e)(8), (f)(6) through (8),
(g)(6) and (7), (h)(7) and (8), and (j)(10)(i) using the emission
calculation requirements in either paragraph (q)(2) or (3) of this
section.
(v) For the components listed in Sec. 98.232(d)(7), you must
conduct surveys as specified in paragraphs (q)(1)(v)(A) and (B) of this
section and you must calculate equipment leak emissions using the
procedures specified in either paragraph (q)(2) or (3) of this section.
(A) For the components listed in Sec. 98.232(d)(7) that are not
subject to the equipment leak standards for onshore natural gas
processing plants in Sec. 60.5400b or Sec. 60.5401b of this chapter,
or an applicable approved state plan or applicable Federal plan in part
62 of this chapter, you may use any of the leak detection methods
listed in Sec. 98.234(a).
(B) For the components listed in Sec. 98.232(d)(7) that are
subject to the equipment leak standards for onshore natural gas
processing plants in Sec. 60.5400b of this chapter, or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter, you must use either of the leak detection methods in Sec.
98.234(a)(1)(iii) or (a)(2)(ii).
(vi) For the components listed in Sec. 98.232(m)(3)(ii) and
(m)(4)(ii), you may elect to conduct surveys according to this
paragraph (q), and, if you elect to do so, then you must use one of the
leak detection methods in Sec. 98.234(a). If you elect to use a leak
detection method in Sec. 98.234(a) for the surveyed component types in
Sec. 98.232(m)(3)(ii) and (m)(4)(ii) in lieu of the population count
methodology specified in paragraph (r) of this section, then you must
calculate emissions for the surveyed component types in Sec.
98.232(m)(3)(ii) and (m)(4)(ii) using the procedures in either
paragraph (q)(2) or (3) of this section.
(vii) Except as provided in paragraph (q)(1)(viii) of this section,
you must conduct at least one complete leak detection survey in a
calendar year. If you conduct multiple complete leak detection surveys
in a calendar year, you must use the results from each complete leak
detection survey when calculating emissions using the procedures
specified in either paragraph (q)(2) or (3) of this section. Except as
provided in paragraphs (q)(1)(vii)(A) through (H) of this section, a
complete leak detection survey is a survey in which all equipment
components required to be surveyed as specified in paragraphs (q)(1)(i)
through (vi) of this section are surveyed.
(A) For components subject to the well site and compressor station
fugitive emissions standards in Sec. 60.5397a of this chapter, each
survey conducted in accordance with Sec. 60.5397a of this chapter
using one of the methods in Sec. 98.234(a) will be considered a
complete leak detection survey for purposes of this section.
(B) For components subject to the well site, centralized production
facility, and compressor station fugitive emissions standards in Sec.
60.5397b or 60.5398b of this chapter, each survey conducted in
accordance with the fugitive emissions standards for well sites,
centralized production facilities, and compressor stations in Sec.
60.5397b, 60.5398b(b)(4) or 60.5398b(b)(5)(ii) of this chapter using
one of the methods in Sec. 98.234(a) will be considered a complete
leak detection survey for purposes of this section.
(C) For components subject to the well site, centralized production
facility, and compressor station fugitive emissions standards in an
applicable approved state plan or applicable Federal plan in part 62 of
this chapter, each survey conducted in accordance with the applicable
approved state plan or applicable Federal plan in part 62 of this
chapter using one of the methods in Sec. 98.234(a) will be considered
a complete leak detection survey for purposes of this section.
(D) For an onshore petroleum and natural gas production facility
electing to conduct leak detection surveys according to paragraph
(q)(1)(iv) of this section, a survey of all required components at a
single well-pad will be considered a complete leak detection survey for
purposes of this section.
[[Page 42276]]
(E) For an onshore petroleum and natural gas gathering and boosting
facility electing to conduct leak detection surveys according to
paragraph (q)(1)(iv) of this section, a survey of all required
components at a gathering and boosting site, as defined in Sec.
98.238, will be considered a complete leak detection survey for
purposes of this section.
(F) For an onshore natural gas processing facility subject to the
equipment leak standards for onshore natural gas processing plants in
Sec. 60.5400b or Sec. 60.5401b of this chapter or an applicable
approved state plan or applicable Federal plan in part 62 of this
chapter, each survey conducted in accordance with the equipment leak
standards for onshore natural gas processing plants in Sec. 60.5400b
or Sec. 60.5401b of this chapter or an applicable approved state plan
or applicable Federal plan in part 62 of this chapter will be
considered a complete leak detection survey for the purposes of
calculating emissions using the procedures specified in either
paragraph (q)(2) or (3) of this section. At least one complete leak
detection survey conducted during the reporting year must include all
components listed in Sec. 98.232(d)(7) and subject to this paragraph
(q), including components which are considered difficult-to-monitor
emission sources as specified in Sec. 98.234(a). Inaccessible
components as provided in Sec. Sec. 60.5401b(h)(3) and 60.5401c(h)(3)
of this chapter are exempt from the monitoring requirements in this
subpart.
(G) For natural gas distribution facilities that choose to conduct
equipment leak surveys at all above grade transmission-distribution
transfer stations over multiple years as provided in paragraph
(q)(1)(vii) of this section, a survey of all required components at the
above grade transmission-distribution transfer stations monitored
during the calendar year will be considered a complete leak detection
survey for purposes of this section.
(H) For onshore natural gas transmission pipeline facilities that
conduct leak detection surveys according to paragraph (q)(1)(vi) of
this section, a survey of all required components at a transmission
company interconnect metering-regulating station or a farm tap/direct
sale metering-regulating station, will be considered a complete leak
detection survey for purposes of this section.
(viii) Natural gas distribution facilities are required to perform
equipment leak surveys only at above grade stations that qualify as
transmission-distribution transfer stations. Below grade transmission-
distribution transfer stations and all metering-regulating stations
that do not meet the definition of transmission-distribution transfer
stations are not required to perform equipment leak surveys under this
section. Natural gas distribution facilities may choose to conduct
equipment leak surveys at all above grade transmission-distribution
transfer stations over multiple years ``n,'' not exceeding a five-year
period to cover all above grade transmission-distribution transfer
stations. If the facility chooses to use the multiple year option, then
the number of transmission-distribution transfer stations that are
monitored in each year should be approximately equal across all years
in the cycle.
(2) Calculation Method 1: Leaker emission factor calculation
methodology. If you elect not to measure leaks according to Calculation
Method 2 as specified in paragraph (q)(3) of this section, you must use
this Calculation Method 1 for all components included in a complete
leak survey. For industry segments listed in Sec. 98.230(a)(2) through
(10), if equipment leaks are detected during surveys required or
elected for components listed in paragraphs (q)(1)(i) through (vi) of
this section, then you must calculate equipment leak emissions per
component type per reporting facility, well-pad site, or gathering and
boosting site, as applicable, using equation W-30 to this section and
the requirements specified in paragraphs (q)(2)(i) through (x) and
(xii) of this section. For the industry segment listed in Sec.
98.230(a)(8), the results from equation W-30 to this section are used
to calculate population emission factors on a meter/regulator run basis
using equation W-31 to this section. If you chose to conduct equipment
leak surveys at all above grade transmission-distribution transfer
stations over multiple years, ``n,'' according to paragraph
(q)(1)(viii) of this section, then you must calculate the emissions
from all above grade transmission-distribution transfer stations as
specified in paragraph (q)(2)(xi) of this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.092
Where:
Es,p,i = Annual total volumetric emissions of
GHGi from specific component type ``p'' (in accordance
with paragraphs (q)(1)(i) through (vi) of this section) in standard
(``s'') cubic feet, as specified in paragraphs (q)(2)(ii) through
(x) and (xii) of this section.
xp = Total number of specific component type ``p''
detected as leaking in any leak survey during the year. A component
found leaking in two or more surveys during the year is counted as
one leaking component.
EFs,p = Leaker emission factor as specified in paragraphs
(q)(2)(iii) through (x) and (xii) of this section.
k = Factor to adjust for undetected leaks by respective leak
detection method, where k equals 1.25 for the methods in Sec.
98.234(q)(1), (3) and (5); k equals 1.55 for the method in Sec.
98.234(q)(2)(i); and k equals 1.27 for the method in Sec.
98.234(q)(2)(ii).
GHGi = For onshore petroleum and natural gas production
facilities and onshore petroleum and natural gas gathering and
boosting facilities, concentration of GHGi,
CH4 or CO2, in produced natural gas as defined
in paragraph (u)(2) of this section; for onshore natural gas
processing facilities, concentration of GHGi,
CH4 or CO2, in the total hydrocarbon of the
feed natural gas; for onshore natural gas transmission compression
and underground natural gas storage, GHGi equals 0.975
for CH4 and 1.1 x 10-2 for CO2 or
concentration of GHGi, CH4 or CO2,
in the total hydrocarbon of the feed natural gas; for LNG storage
and LNG import and export equipment and onshore natural gas
transmission pipeline, GHGi equals 1 for CH4
and 0 for CO2; and for natural gas distribution,
GHGi equals 1 for CH4 and 1.1 x
10-2 for CO2.
Tp,z = The total time the surveyed component ``z,''
component type ``p,'' was assumed to be leaking and operational, in
hours. If one leak detection survey is conducted in the calendar
year, assume the component was leaking for the entire calendar year.
If multiple leak detection surveys are conducted in the calendar
year, assume a component found leaking in the first survey was
leaking since the beginning of the year until the date of the
survey; assume a component found leaking in the last survey of the
year was leaking from the preceding survey through the end of the
year; assume a component found leaking in a survey between the first
and last surveys of the
[[Page 42277]]
year was leaking since the preceding survey until the date of the
survey; and sum times for all leaking periods. For each leaking
component, account for time the component was not operational (i.e.,
not operating under pressure) using an engineering estimate based on
best available data.
(i) The leak detection surveys selected for use in equation W-30 to
this section must be conducted during the calendar year as indicated in
paragraph (q)(1)(vii) and (viii) of this section, as applicable.
(ii) Calculate both CO2 and CH4 mass
emissions using calculations in paragraph (v) of this section.
(iii) Onshore petroleum and natural gas production facilities must,
if available, use the facility-specific leaker emission factor
calculated in accordance with paragraph (q)(4) of section or use the
appropriate default whole gas leaker emission factors consistent with
the well type, where components associated with gas wells are
considered to be in gas service and components associated with oil
wells are considered to be in oil service as listed in table W-2 to
this subpart.
(iv) Onshore petroleum and natural gas gathering and boosting
facilities must, if available, use the facility-specific leaker
emission factor calculated in accordance with paragraph (q)(4) of
section or use the appropriate default whole gas leaker factors for
components in gas service listed in table W-2 to this subpart.
(v) Onshore natural gas processing facilities must, if available,
use the facility-specific leaker emission factor calculated in
accordance with paragraph (q)(4) of section or use the appropriate
default total hydrocarbon leaker emission factors for compressor
components in gas service and non-compressor components in gas service
listed in table W-4 to this subpart.
(vi) Onshore natural gas transmission compression facilities must,
if available, use the facility-specific leaker emission factor
calculated in accordance with paragraph (q)(4) of section or use the
appropriate default total hydrocarbon leaker emission factors for
compressor components in gas service and non-compressor components in
gas service listed in table W-4 to this subpart.
(vii) Underground natural gas storage facilities must, if
available, use the facility-specific leaker emission factor calculated
in accordance with paragraph (q)(4) of section or use the appropriate
default total hydrocarbon leaker emission factors for storage stations
or storage wellheads in gas service listed in table W-4 to this
subpart.
(viii) LNG storage facilities must, if available, use the facility-
specific leaker emission factor calculated in accordance with paragraph
(q)(4) of section or use the appropriate default methane leaker
emission factors for LNG storage components in LNG service or gas
service listed in table W-6 to this subpart.
(ix) LNG import and export facilities must, if available, use the
facility-specific leaker emission factor calculated in accordance with
paragraph (q)(4) of section or use the appropriate default methane
leaker emission factors for LNG terminals components in LNG service or
gas service listed in table W-6 to this subpart.
(x) Except as provided in paragraph (q)(3)(viii) of this section,
natural gas distribution facilities must use equation W-30 to this
section and the default methane leaker emission factors for
transmission-distribution transfer station components in gas service
listed in table W-6 to this subpart to calculate component emissions
from annual equipment leak surveys conducted at above grade
transmission-distribution transfer stations.
(A) Use equation W-31 to this section to determine the meter/
regulator run population emission factors for each GHGi. As
additional survey data become available, you must recalculate the
meter/regulator run population emission factors for each
GHGi annually according to paragraph (q)(2)(x)(B) of this
section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.093
Where:
EFs,MR,i = Meter/regulator run population emission factor
for GHGi based on all surveyed above grade transmission-
distribution transfer stations over ``n'' years, in standard cubic
feet of GHGi per operational hour of all meter/regulator
runs.
Es,p,i,y = Annual total volumetric emissions at standard
conditions of GHGi from component type ``p'' during year
``y'' in standard (``s'') cubic feet, as calculated using equation
W-30 to this section.
p = Seven component types listed in table W-6 to this subpart for
transmission-distribution transfer stations.
Tw,y = The total time the surveyed meter/regulator run
``w'' was operational, in hours during survey year ``y'' using an
engineering estimate based on best available data.
CountMR,y = Count of meter/regulator runs surveyed at
above grade transmission-distribution transfer stations in year
``y''.
y = Year of data included in emission factor ``EFs,MR,i''
according to paragraph (q)(2)(x)(B) of this section.
n = Number of years of data, according to paragraph (q)(1)(vii) of
this section, whose results are used to calculate emission factor
``EFs,MR,i'' according to paragraph (q)(2)(x)(B) of this
section.
(B) The emission factor ``EFs,MR,i,'' based on annual
equipment leak surveys at above grade transmission-distribution
transfer stations, must be calculated annually. If you chose to conduct
equipment leak surveys at all above grade transmission-distribution
transfer stations over multiple years, ``n,'' according to paragraph
(q)(1)(viii) of this section and you have submitted a smaller number of
annual reports than the duration of the selected cycle period of 5
years or less, then all available data from the current year and
previous years must be used in the calculation of the emission factor
``EFs,MR,i'' from equation W-31 to this section. After the
first survey cycle of ``n'' years is completed and beginning in
calendar year (n+1), the survey will continue on a rolling basis by
including the survey results from the current calendar year ``y'' and
survey results from all previous (n-1) calendar years, such that each
annual calculation of the emission factor ``EFs,MR,i'' from
equation W-31 to this section is based on survey results from ``n''
years. Upon completion of a cycle, you may elect to change the number
of years in the next cycle period (to be 5 years or less). If the
number of years in the new cycle is greater than the number of years in
the previous cycle, calculate ``EFs,MR,i'' from equation W-
31 to this section in each year of the new cycle using the survey
results from the current calendar year and the survey results
[[Page 42278]]
from the preceding number years that is equal to the number of years in
the previous cycle period. If the number of years, ``nnew,''
in the new cycle is smaller than the number of years in the previous
cycle, ``n,'' calculate ``EFs,MR,i'' from equation W-31 to
this section in each year of the new cycle using the survey results
from the current calendar year and survey results from all previous
(nnew-1) calendar years.
(xi) If you chose to conduct equipment leak surveys at all above
grade transmission-distribution transfer stations over multiple years,
``n,'' according to paragraph (q)(1)(viii) of this section, you must
use the meter/regulator run population emission factors calculated
using equation W-31 to this section and the total count of all meter/
regulator runs at above grade transmission-distribution transfer
stations to calculate emissions from all above grade transmission-
distribution transfer stations using equation W-32B to this section.
(xii) Onshore natural gas transmission pipeline facilities must use
the facility-specific leaker emission factor calculated in accordance
with paragraph (q)(4) of this section.
(3) Calculation Method 2: Leaker measurement methodology. For
industry segments listed in Sec. 98.230(a)(2) through (10), if
equipment leaks are detected during surveys required or elected for
components listed in paragraphs (q)(1)(i) through (vi) of this section,
you may elect to measure the volumetric flow rate of each natural gas
leak identified during a complete leak survey. If you elect to use this
method, you must use this method for all components included in a
complete leak survey and you must determine the volumetric flow rate of
each natural gas leak identified during the leak survey and aggregate
the emissions by the method of leak detection and component type as
specified in paragraphs (q)(3)(i) through (vii) of this section.
(i) Determine the volumetric flow rate of each natural gas leak
identified during the leak survey following the methods Sec. 98.234(b)
through (d), as appropriate for each leak identified. You do not need
to use the same measurement method for each leak measured. If you are
unable to measure the natural gas leak because it would require
elevating the measurement personnel more than 2 meters above the
surface and a lift is unavailable at the site or it would pose
immediate danger to measurement personnel, then you must substitute the
default leak rate for the component and site type from tables W-2, W-4,
or W-6 to this subpart, as applicable, as the measurement for this
leak.
(ii) For each leak, calculate the volume of natural gas emitted as
the product of the natural gas flow rate measured in paragraph
(q)(3)(i) of this section and the duration of the leak. If one leak
detection survey is conducted in the calendar year, assume the
component was leaking for the entire calendar year. If multiple leak
detection surveys are conducted in the calendar year, assume a
component found leaking in the first survey was leaking since the
beginning of the year until the date of the survey; assume a component
found leaking in the last survey of the year was leaking from the
preceding survey through the end of the year; assume a component found
leaking in a survey between the first and last surveys of the year was
leaking since the preceding survey until the date of the survey. For
each leaking component, account for time the component was not
operational (i.e., not operating under pressure) using an engineering
estimate based on best available data.
(iii) For each leak, convert the volumetric emissions of natural
gas determined in paragraph (q)(3)(ii) of this section to standard
conditions using the method specified in paragraph (t)(1) of this
section.
(iv) For each leak, convert the volumetric emissions of natural gas
at standard conditions determined in paragraph (q)(3)(iii) of this
section to CO2 and CH4 volumetric emissions at
standard conditions using the methods specified in paragraph (u) of
this section.
(v) For each leak, convert the GHG volumetric emissions at standard
conditions determined in paragraph (q)(3)(iv) of this section to GHG
mass emissions using the methods specified in paragraph (v) of this
section.
(vi) Sum the CO2 and CH4 mass emissions
determined in paragraph (q)(3)(v) of this section separately for each
type of component required to be surveyed by the method used for the
survey for which a leak was detected.
(vii) Multiply the total CO2 and CH4 mass
emissions by survey method and component type determined in paragraph
(q)(3)(vi) by the survey specific value for ``k'', the factor
adjustment for undetected leaks, where k equals 1.25 for the methods in
Sec. 98.234(q)(1), (3) and (5); k equals 1.55 for the method in Sec.
98.234(q)(2)(i); and k equals 1.27 for the method in Sec.
98.234(q)(2)(ii).
(viii) For natural gas distribution facilities:
(A) Use equation W-31 to this section to determine the meter/
regulator run population emission factors for each GHGi
using the methods as specified in paragraphs (q)(2)(x)(A) and (B) of
this section, except use the sum of the GHG volumetric emissions for
each type of component required to be surveyed by the method used for
the survey for which a leak was detected calculated in paragraph
(q)(3)(iv) of this section rather than the emissions calculated using
equation W-30 to this section.
(B) If you chose to conduct equipment leak surveys at all above
grade transmission-distribution transfer stations over multiple years,
``n,'' according to paragraph (q)(1)(vii) of this section, you must use
the meter/regulator run population emission factors calculated
according to paragraph (q)(3)(vii)(A) of this section and the total
count of all meter/regulator runs at above grade transmission-
distribution transfer stations to calculate emissions from all above
grade transmission-distribution transfer stations using equation W-32B
to this section.
(4) Development of facility-specific component-level leaker
emission factors by leak detection method. If you elect to measure
leaks according to Calculation Method 2 as specified in paragraph
(q)(3) of this section, you must use the measurement values determined
in accordance with paragraph (q)(3) of this section to calculate a
facility-specific component-level leaker emission factor by leak
detection method as provided in paragraphs (q)(4)(i) through (iv) of
this section.
(i) You must track the leak measurements made separately for each
of the applicable components listed in paragraphs (q)(1)(i) through (v)
of this section and by the leak detection method according to the
following three bins.
(A) Method 21 as specified in Sec. 98.234(a)(2)(i).
(B) Method 21 as specified in Sec. 98.234(a)(2)(ii).
(C) Optical gas imaging (OGI) and other leak detection methods as
specified in Sec. 98.234(a)(1), (3), or (5).
(ii) You must accumulate a minimum of 50 leak measurements total
for a given component type and leak detection method combination before
you can develop and use a facility-specific component-level leaker
emission factor for use in calculating emissions according to paragraph
(q)(2) of this section (Calculation Method 1: Leaker emission factor
calculation methodology).
(iii) Sum the volumetric flow rate of natural gas determined in
accordance with paragraph (q)(3)(i) of this section for each leak by
component type and
[[Page 42279]]
leak detection method as specified in paragraph (q)(4)(i) of this
section meeting the minimum number of measurement requirement in
paragraph (q)(4)(ii) of this section.
(iv) Convert the volumetric flow rate of natural gas determined in
paragraph (q)(4)(iii) of this section to standard conditions using the
method specified in paragraph (t)(1) of this section.
(v) Determine the emission factor in units of standard cubic feet
per hour component (scf/hr-component) by dividing the sum of the
volumetric flow rate of natural gas determined in paragraph (q)(4)(iv)
of this section by the total number of leak measurements for that
component type and leak detection method combination.
(vi) You must update the emission factor determined in (q)(4)(v) of
this section annually to include the results from all complete leak
surveys for which leak measurement was performed during the reporting
year in accordance with paragraph (q)(3) of this section.
(r) Equipment leaks by population count. This paragraph (r) applies
to emissions sources listed in Sec. 98.232(c)(21)(ii), (f)(7), (g)(5),
(h)(6), (j)(10)(ii), (m)(3)(i), and (m)(4)(i) if you are not required
to comply with paragraph (q) of this section and if you do not elect to
comply with paragraph (q) of this section for these components in lieu
of this paragraph (r). This paragraph (r) also applies to emission
sources listed in Sec. 98.232(i)(2) through (6), (j)(11), and (m)(5).
To be subject to the requirements of this paragraph (r), the listed
emissions sources also must contact streams with gas content greater
than 10 percent CH4 plus CO2 by weight. Emissions
sources that contact streams with gas content less than or equal to 10
percent CH4 plus CO2 by weight are exempt from
the requirements of this paragraph (r) and do not need to be reported.
Tubing systems equal to or less than one half inch diameter are exempt
from the requirements of this paragraph (r) and do not need to be
reported. Equipment leak components in vacuum service are exempt from
the survey and emission estimation requirements of this paragraph (r)
and only the count of these equipment must be reported. You must
calculate emissions from all emission sources listed in this paragraph
(r) using equation W-32A to this section, except for natural gas
distribution facility emission sources listed in Sec. 98.232(i)(3).
Natural gas distribution facility emission sources listed in Sec.
98.232(i)(3) must calculate emissions using equation W-32B to this
section and according to paragraph (r)(6)(ii) of this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.094
[GRAPHIC] [TIFF OMITTED] TR14MY24.095
Where:
Es,e,i = Annual volumetric emissions of GHGi
from the emission source type in standard cubic feet. The emission
source type may be a major equipment (e.g., wellhead, separator),
component (e.g., connector, open-ended line), below grade metering-
regulating station, below grade transmission-distribution transfer
station, distribution main, distribution service, gathering
pipeline, transmission company interconnect metering-regulating
station, farm tap and/or direct sale metering-regulating station, or
transmission pipeline.
Es,MR,i = Annual volumetric emissions of GHGi
from all meter/regulator runs at above grade metering regulating
stations that are not above grade transmission-distribution transfer
stations or, when used to calculate emissions according to paragraph
(q)(2)(xi) or (q)(3)(vii)(B) of this section, the annual volumetric
emissions of GHGi from all meter/regulator runs at above
grade transmission-distribution transfer stations.
Counte = Total number of the emission source type at the
facility. Onshore petroleum and natural gas production facilities
and onshore petroleum and natural gas gathering and boosting
facilities must count each major equipment piece listed in table W-1
to this subpart. Onshore petroleum and natural gas gathering and
boosting facilities must also count the miles of gathering pipelines
by material type (protected steel, unprotected steel, plastic, or
cast iron). Underground natural gas storage facilities must count
each component listed in table W-3 to this subpart. LNG storage
facilities must count the number of vapor recovery compressors. LNG
import and export facilities must count the number of vapor recovery
compressors. Natural gas distribution facilities must count the: (1)
Number of distribution services by material type; (2) miles of
distribution mains by material type; (3) number of below grade
transmission-distribution transfer stations; and (4) number of below
grade metering-regulating stations; as listed in table W-5 to this
subpart. Onshore natural gas transmission pipeline facilities must
count the following, as listed in table W-5 to this subpart: (1)
Miles of transmission pipelines by material type; (2) number of
transmission company interconnect metering-regulating stations; and
(3) number of farm tap and/or direct sale metering-regulating
stations.
CountMR = Total number of meter/regulator runs at above
grade metering-regulating stations that are not above grade
transmission-distribution transfer stations or, when used to
calculate emissions according to paragraph (q)(2)(xi) or
(q)(3)(vii)(B) of this section, the total number of meter/regulator
runs at above grade transmission-distribution transfer stations.
EFs,e = Population emission factor for the specific
emission source type, as specified in paragraphs (r)(2) through (7)
of this section.
EFs,MR,i = Meter/regulator run population emission factor
for GHGi based on all surveyed above grade transmission-
distribution transfer stations over ``n'' years, in standard cubic
feet of GHGi per operational hour of all meter/regulator
runs, as determined in equation W-31 to this section.
GHGi = For onshore petroleum and natural gas production
facilities and onshore petroleum and natural gas gathering and
boosting facilities, concentration of GHGi,
CH4 or CO2, in produced natural gas as defined
in paragraph (u)(2) of this section; for onshore natural gas
transmission compression and underground natural gas storage,
GHGi equals 0.975 for CH4 and 1.1 x
10-2 for CO2 or concentration of
GHGi, CH4 or CO2, in the total
hydrocarbon of the feed natural gas; for LNG storage and LNG import
and export equipment, GHGi equals 1 for CH4
and 0 for CO2; and for natural gas distribution and
onshore natural gas transmission pipeline, GHGi equals 1
for CH4 and 1.1 x 10-2 CO2.
Te = Average estimated time that each emission source
type associated with the equipment leak emission was operational in
the calendar year, in hours, using engineering estimate based on
best available data.
Tw,avg = Average estimated time that each meter/regulator
run was operational in the calendar year, in hours per meter/
regulator run, using engineering estimate based on best available
data.
(1) Calculate both CH4 and CO2 mass emissions
from volumetric emissions using calculations in paragraph (v) of this
section.
(2) Onshore petroleum and natural gas production facilities and
onshore petroleum and natural gas gathering and
[[Page 42280]]
boosting facilities must use the appropriate default whole gas
population emission factors listed in table W-1 to this subpart. Major
equipment associated with gas wells are considered gas service
equipment in table W-1 to this subpart. Onshore petroleum and natural
gas gathering and boosting facilities shall use the gas service
equipment emission factors in table W-1 to this subpart. Major
equipment associated with crude oil wells are considered crude service
equipment in table W-1 to this subpart. Where facilities conduct EOR
operations, the emission factor listed in table W-1 to this subpart
shall be used to estimate all streams of gases, including recycle
CO2 stream. For meters/piping, use one meters/piping per
well-pad for onshore petroleum and natural gas production operations
and the number of meters in the facility for onshore petroleum and
natural gas gathering and boosting operations.
(3) Underground natural gas storage facilities must use the
appropriate default total hydrocarbon population emission factors for
storage wellheads in gas service listed in table W-3 to this subpart.
(4) LNG storage facilities must use the appropriate default methane
population emission factors for LNG storage compressors in gas service
listed in table W-5 to this subpart.
(5) LNG import and export facilities must use the appropriate
default methane population emission factors for LNG terminal
compressors in gas service listed in table W-5 to this subpart.
(6) Natural gas distribution facilities must use the appropriate
methane emission factors as described in paragraphs (r)(6)(i) and (ii)
of this section.
(i) Below grade transmission-distribution transfer stations, below
grade metering-regulating stations, distribution mains, and
distribution services must use the appropriate default methane
population emission factors listed in table W-5 to this subpart to
estimate emissions from components listed in Sec. 98.232(i)(2), (4),
(5), and (6), respectively.
(ii) Above grade metering-regulating stations that are not above
grade transmission-distribution transfer stations must use the meter/
regulator run population emission factor calculated in equation W-31 to
this section in accordance with paragraph (q)(2)(x) or (q)(3)(viii)(A)
of this section for the components listed in Sec. 98.232(i)(3).
Natural gas distribution facilities that do not have above grade
transmission-distribution transfer stations are not required to
calculate emissions for above grade metering-regulating stations and
are not required to report GHG emissions in Sec. 98.236(r)(2)(v).
(7) Onshore natural gas transmission pipeline facilities must use
the appropriate default methane population emission factors listed in
table W-5 to this subpart to estimate emissions from components listed
in Sec. 98.232(m)(3)(i), (4)(i) and (5).
(s) Offshore petroleum and natural gas production facilities.
Calculate CO2, CH4, and N2O emissions
for offshore petroleum and natural gas production from all equipment
leaks (i.e., fugitives), vented emission, and flare emission source
types as identified by BOEM in the most recent monitoring and
calculation methods published by BOEM referenced in 30 CFR 550.302
through 304.
(1) Offshore production facilities that report to BOEM's emissions
inventory must calculate emissions as specified in paragraph (s)(1)(i)
or (ii) of this section, as applicable.
(i) Report the same annual emissions calculated using the most
recent monitoring and calculation methods published by BOEM as
referenced in 30 CFR 550.302 through 304 for any reporting year that
overlaps with a BOEM emissions inventory year and any other reporting
year in which the BOEM's emissions reporting system is available and
the facility has the data needed to use BOEM's emissions reporting
system.
(ii) If BOEM's emissions reporting system is not available or if
the facility does not have the data needed to use BOEM's emissions
reporting system, adjust emissions from the most recent emissions
calculated in accordance with paragraph (s)(1)(i), (s)(3), or (s)(4) of
this section, as applicable, by using a ratio of the operating time for
the facility in the current reporting year relative to the operating
time for the facility during the reporting year for which emissions
were calculated as specified in paragraph (s)(1)(i), (s)(3), or (s)(4)
of this section, as applicable.
(2) Offshore production facilities that do not report to BOEM's
emissions inventory must calculate emissions as specified in paragraph
(s)(2)(i) or (ii) of this section, as applicable.
(i) Use the most recent monitoring and calculation methods
published by BOEM as referenced in 30 CFR 550.302 through 304 to
calculate and report annual emissions for any reporting year that
overlaps with a BOEM emissions inventory year and any other reporting
year in which the facility has the data needed to use BOEM's emissions
calculation methods.
(ii) If the facility does not have the data needed to use BOEM's
calculation methods, adjust emissions from the facility's most recent
emissions calculated in accordance with paragraph (s)(2)(i), (s)(3), or
(s)(4) of this section, as applicable, by using a ratio of the
operating time for the facility in the current reporting year relative
to the operating time for the facility in the reporting year for which
the emissions were calculated as specified in paragraph (s)(2)(i),
(s)(3), or (s)(4) of this section, as applicable.
(3) If BOEM's emissions inventory is discontinued or delayed for
more than 3 consecutive years, then offshore production facilities
shall once in every 3 years use the most recent monitoring and
calculation methods published by BOEM referenced in 30 CFR 550.302
through 304 to calculate annual emissions for each of the emission
source types covered in BOEM's most recently published calculation
methods.
(4) For the first year of reporting, offshore production facilities
must use the most recent monitoring and calculation methods published
by BOEM referenced in 30 CFR 550.302 through 304 to calculate and
report annual emissions.
(t) GHG volumetric emissions using actual conditions. If equation
parameters in Sec. 98.233 are already determined at standard
conditions as provided in the introductory text in Sec. 98.233, which
results in volumetric emissions at standard conditions, then this
paragraph does not apply. Calculate volumetric emissions at standard
conditions as specified in paragraph (t)(1) or (2) of this section,
with actual pressure and temperature determined by engineering
estimates based on best available data unless otherwise specified.
(1) Calculate natural gas volumetric emissions at standard
conditions using actual natural gas emission temperature and pressure,
and equation W-33 to this section for conversions of Ea,n or
conversions of FRa (whether sub-sonic or sonic).
[[Page 42281]]
[GRAPHIC] [TIFF OMITTED] TR14MY24.096
Where:
Es,n = Natural gas volumetric emissions at standard
temperature and pressure (STP) conditions in cubic feet, except
Es,n equals FRs,p for each well p when
calculating either subsonic or sonic flowrates under Sec.
98.233(g).
Ea,n = Natural gas volumetric emissions at actual
conditions in cubic feet, except Ea,n equals
FRa,p for each well p when calculating either subsonic or
sonic flowrates under Sec. 98.233(g).
Ts = Temperature at standard conditions (60 [deg]F).
Ta = Temperature at actual emission conditions ([deg]F).
Ps = Absolute pressure at standard conditions (14.7
psia).
Pa = Absolute pressure at actual conditions (psia).
Za = Compressibility factor at actual conditions for
natural gas. You may use either a default compressibility factor of
1, or a site-specific compressibility factor based on actual
temperature and pressure conditions.
(2) Calculate GHG volumetric emissions at standard conditions using
actual GHG emissions temperature and pressure, and equation W-34 to
this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.097
Where:
Es,i = GHG i volumetric emissions at standard temperature
and pressure (STP) conditions in cubic feet.
Ea,i = GHG i volumetric emissions at actual conditions in
cubic feet.
Ts = Temperature at standard conditions (60 [deg]F).
Ta = Temperature at actual emission conditions ([deg]F).
Ps = Absolute pressure at standard conditions (14.7
psia).
Pa = Absolute pressure at actual conditions (psia).
Za = Compressibility factor at actual conditions for
GHGi. You may use either a default compressibility factor
of 1, or a site-specific compressibility factor based on actual
temperature and pressure conditions.
(3) Reporters using 68 [deg]F for standard temperature may use the
ratio 519.67/527.67 to convert volumetric emissions from 68 [deg]F to
60 [deg]F.
(u) GHG volumetric emissions at standard conditions. Calculate GHG
volumetric emissions at standard conditions as specified in paragraphs
(u)(1) and (2) of this section.
(1) Estimate CH4 and CO2 emissions from
natural gas emissions using equation W-35 to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.098
Where:
Es,i = GHG i (either CH4 or CO2)
volumetric emissions at standard conditions in cubic feet.
Es,n = Natural gas volumetric emissions at standard
conditions in cubic feet.
Mi = Mole fraction of GHG i in the natural gas.
(2) For equation W-35 to this section, the mole fraction,
Mi, shall be the annual average mole fraction for each sub-
basin category or facility, as specified in paragraphs (u)(2)(i)
through (vii) of this section.
(i) GHG mole fraction in produced natural gas for onshore petroleum
and natural gas production facilities and onshore petroleum and natural
gas gathering and boosting facilities. If you have a continuous gas
composition analyzer for produced natural gas, you must use an annual
average of these values for determining the mole fraction. If you do
not have a continuous gas composition analyzer, then you must use an
annual average gas composition based on your most recent available
analysis of the sub-basin category or facility, as applicable to the
emission source.
(ii) GHG mole fraction in feed natural gas for all emissions
sources upstream of the de-methanizer or dew point control and GHG mole
fraction in facility specific residue gas to transmission pipeline
systems for all emissions sources downstream of the de-methanizer
overhead or dew point control for onshore natural gas processing
facilities. For onshore natural gas processing plants that solely
fractionate a liquid stream, use the GHG mole percent in feed natural
gas liquid for all streams. If you have a continuous gas composition
analyzer on feed natural gas, you must use these values for determining
the mole fraction. If you do not have a continuous gas composition
analyzer, then annual samples must be taken according to methods set
forth in Sec. 98.234(b).
(iii) GHG mole fraction in transmission pipeline natural gas that
passes through the facility for the onshore natural gas transmission
compression industry segment and the onshore natural gas transmission
pipeline industry segment. You may use either a default 95 percent
methane and 1 percent carbon dioxide fraction for GHG mole fraction in
natural gas or site specific engineering estimates based on best
available data.
(iv) GHG mole fraction in natural gas stored in the underground
natural gas storage industry segment. You may use either a default 95
percent methane and 1 percent carbon dioxide fraction for GHG mole
fraction in natural gas or site specific engineering estimates based on
best available data.
(v) GHG mole fraction in natural gas stored in the LNG storage
industry segment. You may use either a default 95 percent methane and 1
percent carbon dioxide fraction for GHG mole fraction in natural gas or
site specific engineering estimates based on best available data.
(vi) GHG mole fraction in natural gas stored in the LNG import and
export industry segment. For export facilities that receive gas from
transmission pipelines, you may use either a default 95 percent methane
and 1 percent carbon dioxide fraction for GHG mole fraction in natural
gas or site specific
[[Page 42282]]
engineering estimates based on best available data.
(vii) GHG mole fraction in local distribution pipeline natural gas
that passes through the facility for natural gas distribution
facilities. You may use either a default 95 percent methane and 1
percent carbon dioxide fraction for GHG mole fraction in natural gas or
site specific engineering estimates based on best available data.
(v) GHG mass emissions. Calculate GHG mass emissions in metric tons
by converting the GHG volumetric emissions at standard conditions into
mass emissions using equation W-36 to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.099
Where:
Massi = GHGi (either CH4,
CO2, or N2O) mass emissions in metric tons.
Es,i = GHGi (either CH4,
CO2, or N2O) volumetric emissions at standard
conditions, in cubic feet.
[rho]i = Density of GHGi. Use 0.0526 kg/
ft3 for CO2 and N2O, and 0.0192 kg/
ft3 for CH4 at 60 [deg]F and 14.7 psia.
(w) EOR injection pump blowdown. Calculate CO2 pump
blowdown emissions from each EOR injection pump system as follows:
(1) Calculate the total injection pump system volume in cubic feet
(including pipelines, manifolds and vessels) between isolation valves.
(2) Retain logs of the number of blowdowns per calendar year.
(3) Calculate the total annual CO2 emissions from each
EOR injection pump system using equation W-37 to this section:
[GRAPHIC] [TIFF OMITTED] TR14MY24.100
Where:
MassCO2 = Annual EOR injection pump system emissions in
metric tons from blowdowns.
N = Number of blowdowns for the EOR injection pump system in the
calendar year.
Vv = Total volume in cubic feet of EOR injection pump
system chambers (including pipelines, manifolds and vessels) between
isolation valves.
Rc = Density of critical phase EOR injection gas in kg/
ft3. You may use an appropriate standard method published
by a consensus-based standards organization if such a method exists
or you may use an industry standard practice to determine density of
super critical EOR injection gas.
GHGCO2 = Mass fraction of CO2 in critical
phase injection gas.
1 x 10-3 = Conversion factor from kilograms to metric
tons.
(x) EOR hydrocarbon liquids dissolved CO2. Calculate CO2
emissions downstream of the storage tank from dissolved CO2
in hydrocarbon liquids produced through EOR operations as follows:
(1) Determine the amount of CO2 retained in hydrocarbon
liquids after flashing in tankage at STP conditions. Annual samples of
hydrocarbon liquids downstream of the storage tank must be taken
according to methods set forth in Sec. 98.234(b) to determine
retention of CO2 in hydrocarbon liquids immediately
downstream of the storage tank. Use the annual analysis for the
calendar year.
(2) Estimate emissions using equation W-38 to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.101
Where:
MassCO2 = Annual CO2 emissions from
CO2 retained in hydrocarbon liquids produced through EOR
operations beyond tankage, in metric tons.
Shl = Amount of CO2 retained in hydrocarbon
liquids downstream of the storage tank, in metric tons per barrel,
under standard conditions.
Vhl = Total volume of hydrocarbon liquids produced at the
EOR operations in barrels in the calendar year.
(y) Other large release events. Calculate CO2 and
CH4 emissions from other large release events as specified
in paragraphs (y)(2) through (5) of this section for each release that
meets or exceeds the applicable criteria in paragraph (y)(1) of this
section. You are not required to measure every release from your
facility, but if you have EPA-provided notification(s) under the super
emitter program in Sec. 60.5371, 60.5371a, or 60.5371b of this chapter
or an applicable approved state plan or applicable Federal plan in part
62 of this chapter or if EPA- or facility-funded monitoring or
measurement data that demonstrate the release meets or exceeds one of
the thresholds or may reasonably be anticipated to meet or exceed (or
to have met or exceeded) one of the thresholds in paragraph (y)(1) of
this section, then you must calculate the event emissions and, if the
thresholds are confirmed to be exceeded, report the emissions as an
other large release event. If you receive an EPA-provided notification
under the super emitter program in Sec. 60.5371, 60.5371a, or 60.5371b
of this chapter or an applicable approved state plan or applicable
Federal plan in part 62 of this chapter, you must comply with the
requirements in paragraph (y)(6) of this section.
(1) You must report emissions for other large release events that
emit GHG at or above any applicable threshold listed in paragraphs
(y)(1)(i) or (ii) of this section. You must report the emissions for
the entire duration of the event, not just those time periods of the
event emissions exceed the thresholds in paragraphs (y)(1)(i) or (ii)
of this section.
(i) For sources not subject to reporting under paragraphs (a)
through (s), (w), (x), (dd), or (ee) of this section (such as but not
limited to a fire, explosion, well blowout, or pressure relief), a
release that emits methane at any point in time at a rate of 100 kg/hr
or greater.
(ii) For sources subject to reporting under paragraphs (a) through
(h), (j) through (s), (w), (x), (dd), or (ee) of this section, a
release that emits methane at any point in time at a rate of 100 kg/hr
or greater in excess of the emissions calculated from the source using
the applicable methods under paragraphs (a) through (h), (j) through
(s), (w), (x), (dd), or (ee) of this section. For a release meeting the
criteria in this paragraph (y)(1)(ii), you must report the emissions
[[Page 42283]]
as an other large release event and exclude the emissions that would
have been calculated for that source during the timespan of the event
in the source-specific emissions calculated under paragraphs (a)
through (h), (j) through (s), (w), (x), (dd), or (ee) of this section,
as applicable.
(2) Estimate the total volume of gas released during the event in
standard cubic feet and the methane emission rate at any point in time
during the event in kilograms per hour using measurement data according
to Sec. 98.234(b), if available, or a combination of process
knowledge, engineering estimates, and best available data when
measurement data are not available according to paragraphs (y)(2)(i)
through (v) of this section.
(i) The total volume of gas released must be estimated as the
product of the measured or estimated average flow or release rate and
the estimated event duration. For events for which information is
available showing variable or decaying flow rates, you must calculate
the maximum natural gas flow or release rate during the event and
either determine a representative average release rate across the
entire event or determine representative release rates for specific
time periods within the event duration. If you elect to determine
representative release rates for specific time periods within the event
duration, calculate the volume of gas released for each time period
within the event duration as the product of the representative release
rate and the length of the corresponding time period and sum the volume
of gas released across each of the time periods for the full duration
of the event. For events that have releases from multiple release
points but have a common root cause (e.g., over-pressuring of a system
causes releases from multiple pressure relief devices), you must report
the event as a single other large release event considering the
cumulative volume of gas released across all release points.
(ii) The start time of the event must be determined based on
monitored process parameters and sound engineering principles. If
monitored process parameters cannot identify the start of the event,
the event must be assumed to start on the date of the most recent
monitoring or measurement survey that confirms the source was not
emitting at or above the rates specified in paragraph (y)(1) of this
section or assumed to have started 91 days prior to the date the event
was first identified, whichever start date is most recent.
(iii) The end time of the event must be the date of the confirmed
repair or confirmed cessation of emissions.
(iv) For the purposes of paragraph (y)(2)(ii) of this section,
``monitoring or measurement survey'' includes any monitoring or
measurement method in Sec. 98.234(a) through (d) as well as advanced
screening methods such as monitoring systems mounted on vehicles,
drones, helicopters, airplanes, or satellites capable of identifying
emissions at the thresholds specified in paragraph (y)(1) of this
section at a 90 percent probability of detection as demonstrated by
controlled release tests. Audio, visual, and olfactory inspections are
considered monitoring surveys if and only if the event was identified
via an audio, visual, and olfactory inspection.
(v) For events that span two different reporting years, calculate
the portion of the event's volumetric emissions calculated according to
paragraph (y)(2)(i) of this section that occurred in each reporting
year considering only reporting year 2025 and later reporting years.
For events with consistent flow or for which one average emissions rate
is used, use the relative duration of the event within each reporting
year to apportion the volume of gas released for each reporting year.
For variable flow events for which the volume of gas released is
estimated for separate time periods, sum the volume of gas released
across each of the time periods within a given reporting year
separately. If one of the time periods span two different reporting
years, calculate the portion of the volumetric emissions calculated for
that time period that applies to each reporting year based on the
number of hours in that time period within each reporting year.
(3) Determine the composition of the gas released to the atmosphere
using measurement data, if available, or a combination of process
knowledge, engineering estimates, and best available data when
measurement data are not available. In the event of an explosion or
fire, where a portion of the natural gas may be combusted, estimate the
composition of the gas released to the atmosphere considering the
fraction of natural gas released directly to the atmosphere and the
fraction of natural gas that was combusted by the explosion or fire
during the release event. Assume combustion efficiency equals
destruction efficiency and assume a maximum combustion efficiency of 92
percent for natural gas that is combusted in an explosion or fire when
estimating the CO2 and CH4 composition of the
release. You may use different compositions for different periods
within the duration if available information suggests composition
varied during the release (e.g., if a portion of the release occurred
while fire was present and a portion of the release occurred when no
fire was present).
(4) Calculate the GHG volumetric emissions using equation W-35 to
this section.
(5) Calculate both CH4 and CO2 mass emissions
from volumetric emissions using calculations in paragraph (v) of this
section.
(6) If you receive an EPA-provided notification under the super
emitter program in Sec. 60.5371, 60.5371a, or 60.5371b of this chapter
or an applicable approved state plan or applicable Federal plan in part
62 of this chapter, you must include the emissions from that source or
event within your subpart W report unless you can provide certification
as specified in either paragraph (y)(6)(i) or (ii) of this section, as
applicable, or unless the EPA has determined that the notification has
a demonstrable error, as specified in paragraph (y)(6)(iii) of this
section.
(i) If you do not own or operate any petroleum and natural gas
system equipment within 50 meters of the location identified in the
notification, you may prepare and submit the certification that the
facility does not own or operate the equipment at the location
identified in the notification.
(ii) If you own or operate petroleum and natural gas system
equipment within 50 meters of the location identified in the
notification, but there are also other petroleum and natural gas system
equipment within 50 meters of the location identified in the
notification owned and operated by a different facility, you may
prepare and submit the certification that the facility does not own or
operate the emitting equipment at the location identified in the
notification if and only if you comply with all of the following
requirements.
(A) Within 5 days of receiving the notification, complete an
investigation of available data as specified in Sec. 60.5371b(d)(2)(i)
through (iv) of this chapter to identify the emissions source related
to the event notification.
(B) If the data investigation in paragraph (y)(6)(ii)(A) of this
section does not identify the emissions source related to the event
notification, you must conduct a complete survey of equipment at your
facility that is within 50 meters of the location identified in the
notification following any one of the methods provided in Sec.
98.234(a)(1) through (3) within 15 days of receiving the notification.
[[Page 42284]]
(C) The investigations and surveys conducted in paragraphs
(y)(6)(ii)(A) and (B) of this section verify that none of the equipment
that you own or operate at the location identified in the notification
were responsible for the high emissions event.
(iii) For consideration of demonstrable error, you must submit a
statement of demonstrable error as specified by Sec. 60.5371,
60.5371a, or 60.5371b of this chapter or an applicable approved state
plan or applicable Federal plan in part 62 of this chapter. You must
report emissions associated with the notification unless the EPA has
determined that the notification contained a demonstrable error.
(z) Combustion equipment. Except as specified in paragraphs (z)(6)
and (7) of this section, calculate CO2, CH4, and
N2O combustion-related emissions from stationary or portable
equipment using the applicable method in paragraphs (z)(1) through (3)
of this section according to the fuel combusted as specified in those
paragraphs:
(1) If a fuel combusted in the stationary or portable equipment
meets the specifications of paragraph (z)(1)(i) of this section, then
calculate emissions according to paragraph (z)(1)(ii) of this section.
(i) The fuel combusted in the stationary or portable equipment is
listed in table C-1 to subpart C of this part or is a blend in which
all fuels are listed in table C-1. If the fuel is natural gas or the
blend contains natural gas, the natural gas must also meet the criteria
of paragraphs (z)(1)(i)(A) and (B) of this section.
(A) The natural gas must be of pipeline quality specification.
(B) The natural gas must have a minimum higher heating value of 950
Btu per standard cubic foot.
(ii) For fuels listed in paragraph (z)(1)(i) of this section,
calculate CO2, CH4, and N2O emissions
for each unit or group of units combusting the same fuel according to
any Tier listed in subpart C of this part, except that each natural
gas-fired reciprocating internal combustion engine or gas turbine must
use one of the methods in paragraph (z)(4) of this section to quantify
a CH4 emission factor instead of using the CH4
emission factor in table C-2 to subpart C of this part. You must follow
all applicable calculation requirements for that tier listed in Sec.
98.33, any monitoring or QA/QC requirements listed for that tier in
Sec. 98.34, any missing data procedures specified in Sec. 98.35, and
any recordkeeping requirements specified in Sec. 98.37. You must
report emissions according to paragraph (z)(5) of this section.
(2) If a fuel combusted in the stationary or portable equipment
meets the specifications of paragraph (z)(2)(i) of this section, then
calculate emissions according to paragraph (z)(2)(ii) of this section.
(i) The fuel combusted in the stationary or portable equipment is
natural gas that is not pipeline quality or it is a blend containing
natural gas that is not pipeline quality with only fuels that are
listed in table C-1. The natural gas must meet the criteria of
paragraphs (z)(2)(i)(A) through (C) of this section.
(A) The natural gas must have a minimum higher heating value of 950
Btu per standard cubic foot.
(B) The natural gas must have a maximum CO2 content of
higher heating value of 1,100 Btu per standard cubic foot.
(C) The natural gas must have a minimum CH4 content of
70 percent by volume.
(ii) For fuels listed in paragraph (z)(2)(i) of this section,
calculate CO2, CH4, and N2O emissions
for each unit or group of units combusting the same fuel according to
Tier 2, Tier 3, or Tier 4 listed in subpart C of this part, except that
each natural gas-fired reciprocating engine or gas turbine must use one
of the methods in paragraph (z)(4) of this section to quantify a
CH4 emission factor instead of using the CH4
emission factor in table C-2 to subpart C of this part. You must follow
all applicable calculation requirements for that tier listed in Sec.
98.33, any monitoring or QA/QC requirements listed for that tier in
Sec. 98.34, any missing data procedures specified in Sec. 98.35, and
any recordkeeping requirements specified in Sec. 98.37. You must
report emissions according to paragraph (z)(5) of this section.
(3) If a fuel combusted in the stationary or portable equipment
meets the specifications of paragraph (z)(3)(i) of this section, then
calculate emissions according to paragraph (z)(3)(ii) of this section.
(i) The fuel combusted in the stationary or portable equipment does
not meet the criteria of either paragraph (z)(1)(i) or (z)(2)(i) of
this section. Examples include natural gas that is not of pipeline
quality, natural gas that has a higher heating value of less than 950
Btu per standard cubic feet, and natural gas that is not pipeline
quality and does not meet the criteria of either paragraph (z)(2)(i)(B)
or (C) of this section. Other examples include field gas that does not
meet the definition of natural gas in Sec. 98.238 and blends
containing field gas that does not meet the definition of natural gas
in Sec. 98.238.
(ii) For fuels listed in paragraph (z)(3)(i) of this section,
calculate combustion emissions for each unit or group of units
combusting the same fuel using the applicable steps from paragraphs
(z)(3)(ii)(A) through (G) of this section:
(A) You may use company records to determine the volume of fuel
combusted in the unit or group of units during the reporting year.
(B) If you have a continuous gas composition analyzer on fuel to
the combustion unit(s), you must use these compositions for determining
the concentration of each constituent in the flow of gas to the unit or
group of units. If you do not have a continuous gas composition
analyzer on gas to the combustion unit(s), you may use engineering
estimates based on best available data to determine the concentration
of each constituent in the flow of gas to the unit or group of units.
Otherwise, you must use the appropriate gas compositions for each
stream going to the combustion unit(s) as specified in paragraph (u)(2)
of this section.
(C) For reciprocating internal combustion engines or gas turbines,
you may conduct a performance test following the applicable procedures
in Sec. 98.234(i) and calculate CH4 emissions in accordance
with paragraph (z)(3)(ii)(G) of this section. Otherwise, you must
calculate CH4 emissions in accordance with paragraphs
(z)(3)(ii)(D) through (F) of this section.
(D) Calculate GHG volumetric emissions at actual conditions using
equations W-39A and W-39B to this section:
[GRAPHIC] [TIFF OMITTED] TR14MY24.102
[[Page 42285]]
[GRAPHIC] [TIFF OMITTED] TR14MY24.103
Where:
Ea,CO2 = Contribution of annual CO2 emissions
from portable or stationary fuel combustion sources in cubic feet,
under actual conditions.
Va = Volume of gas sent to the combustion unit or group
of units in actual cubic feet, during the year.
YCO2 = Mole fraction of CO2 in gas sent to the
combustion unit or group of units.
[eta] = Fraction of gas combusted for portable and stationary
equipment determined using engineering estimation. For internal
combustion devices that are not reciprocating internal combustion
engines or gas turbines, a default of 0.995 can be used. For two-
stroke lean-burn reciprocating internal combustion engines, a
default of 0.953 must be used; for four-stroke lean-burn
reciprocating internal combustion engines, a default of 0.962 must
be used; for four-stroke rich-burn reciprocating internal combustion
engines, a default of 0.997 must be used, and for gas turbines, a
default of 0.999 must be used.
Yj = Mole fraction of hydrocarbon constituent j (such as
methane, ethane, propane, butane, and pentanes plus) in gas sent to
the combustion unit or group of units.
Rj = Number of carbon atoms in the hydrocarbon
constituent j in gas sent to the combustion unit or group of units;
1 for methane, 2 for ethane, 3 for propane, 4 for butane, and 5 for
pentanes plus.
Ea,CH4 = Contribution of annual CH4 emissions
from portable or stationary fuel combustion sources in cubic feet,
under actual conditions.
YCH4 = Mole fraction of methane in gas sent to the
combustion unit or group of units.
(E) Calculate GHG volumetric emissions at standard conditions using
calculations in paragraph (t) of this section.
(F) Calculate both combustion-related CH4 and
CO2 mass emissions from volumetric CH4 and
CO2 emissions using calculation in paragraph (v) of this
section.
(G) Calculate CH4 and N2O mass emissions, as
applicable, using equation W-40 to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.104
Where:
Massi = Annual N2O or CH4 emissions
from the combustion of a particular type of fuel (metric tons).
Fuel = Annual mass or volume of the fuel combusted (mass or volume
per year, choose appropriately to be consistent with the units of
HHV).
HHV = Site-specific higher heating value of the fuel, mmBtu/unit of
the fuel (in units consistent with the fuel quantity combusted).
EFi = For N2O, use 1.0 x 10-4 kg
N2O/mmBtu; for CH4, use the CH4 EF
(kg CH4/MMBtu) determined from your performance test
according to paragraph (z)(4)(i) of this section.
1 x 10-3 = Conversion factor from kilograms to metric
tons.
(4) For each natural gas-fired reciprocating internal combustion
engine or gas turbine calculating emissions according to paragraph
(z)(1)(ii) or (z)(2)(ii) of this section, you must determine a
CH4 emission factor (kg CH4/MMBtu) using one of
the methods provided in paragraphs (z)(4)(i) through (iii) of this
section. For each reciprocating internal combustion engine or gas
turbine calculating CH4 emissions according to paragraph
(z)(3)(ii)(G) of this section, you must determine a CH4
emission factor (kg CH4/MMBtu) using the method provided in
paragraph (z)(4)(i).
(i) Conduct a performance test following the applicable procedures
in Sec. 98.234(i). If you are required or elect to conduct a
performance test for any reason, you must use that result to determine
the CH4 emission factors. If multiple performance tests are
conducted in the same reporting year, the arithmetic average of all
performance tests completed that year must be used to determine the
CH4 emission factor.
(ii) Original equipment manufacturer information, which may include
manufacturer specification sheets, emissions certification data, or
other manufacturer data providing expected emission rates from the
reciprocating internal combustion engine or gas turbine.
(iii) Applicable equipment type-specific emission factor from table
W-7 to this subpart.
(5) Emissions from fuel combusted in stationary or portable
equipment at onshore petroleum and natural gas production facilities,
at onshore petroleum and natural gas gathering and boosting facilities,
and at natural gas distribution facilities that are calculated
according to the procedures in either paragraph (z)(1)(ii) or
(z)(2)(ii) of this section must be reported according to the
requirements specified in Sec. 98.236(z) rather than the reporting
requirements specified in subpart C of this part.
(6) External fuel combustion sources with a rated heat capacity
equal to or less than 5 mmBtu/hr do not need to report combustion
emissions or include these emissions for threshold determination in
Sec. 98.231(a). You must report the type and number of each external
fuel combustion unit.
(7) Internal fuel combustion sources, not compressor-drivers, with
a rated heat capacity equal to or less than 1 mmBtu/hr (or the
equivalent of 130 horsepower), do not need to report combustion
emissions or include these emissions for threshold determination in
Sec. 98.231(a). You must report the type and number of each internal
fuel combustion unit.
(aa) through (cc) [Reserved]
(dd) Drilling mud degassing. Calculate annual volumetric
CH4 emissions from the degassing of drilling mud using one
of the calculation methods described in paragraphs (dd)(1), (2), or (3)
of this section. If you have taken mudlogging measurements from the
penetration of the first hydrocarbon bearing zone until drilling mud
ceases to be circulated in the wellbore, including mud pumping rate and
gas trap-derived gas concentration that is reported in parts per
million (ppm) or is reported in units from which ppm can be derived,
you must use Calculation Method 1 as described in paragraph (dd)(1) of
this section. If you have not taken mudlogging measurements, you must
use Calculation Method 2 as described in paragraph (dd)(2) of this
section. If you have taken mudlogging measurements for some, but not
all, of the time the well bore has penetrated the first hydrocarbon
bearing zone until drilling mud ceases to be circulated in the wellbore
including mud pumping rate and gas trap-derived gas concentration that
is reported in parts per million (ppm) or is reported in units from
which ppm can be derived, you must use Calculation Method 3 as
described in paragraph (dd)(3) of this section.
(1) Calculation Method 1. For each well in the sub-basin in which
drilling mud was used during well drilling, you must calculate
CH4 emissions from drilling mud degassing by applying an
emissions rate derived from a representative well in the same sub-
[[Page 42286]]
basin and within the equivalent stratigraphic interval. You must follow
the procedures specified in paragraph (dd)(1)(i) of this section to
calculate CH4 emissions for the representative well and
follow the procedures in paragraphs (dd)(1)(ii) through (iv) of this
section to calculate CH4 emissions for every well drilled in
the sub-basin and within the equivalent stratigraphic interval.
(i) Calculate CH4 emissions from mud degassing for one
representative well in each sub-basin and within the equivalent
stratigraphic interval. For the representative well, you must use
mudlogging measurements, including gas trap derived gas concentration
and mud pumping rate, taken during the reporting year. In the first
year of reporting, you may use measurements from the prior reporting
year if measurements from the current reporting year are not available.
Use equation W-41 to this section to calculate natural gas emissions
from mud degassing at the representative well. You must identify and
calculate CH4 emissions for a representative well for the
sub-basin and within the equivalent stratigraphic interval every 2
calendar years or on a more frequent basis. If a representative well is
not available in the same sub-basin and within the equivalent
stratigraphic interval, you may choose a well within the facility that
is drilled into the same formation and within the equivalent
stratigraphic interval.
[GRAPHIC] [TIFF OMITTED] TR14MY24.105
Where:
Es,CH4,r = Annual total volumetric CH4
emissions from mud degassing for the representative well, r, in
standard cubic feet.
MRr = Average mud rate for the representative well, r, in
gallons per minute.
Tr = Total time that drilling mud is circulated in the
representative well, r, in minutes beginning with initial
penetration of the first hydrocarbon-bearing zone until drilling mud
ceases to be circulated in the wellbore.
Xn = Average concentration of natural gas in the drilling
mud as measured by the gas trap, in parts per million.
GHGCH4 = Measured mole fraction of CH4 in
natural gas entrained in the drilling mud.
0.1337 = Conversion from gallons to standard cubic feet.
(ii) Calculate the emissions rate of CH4 in standard
cubic feet per minute from the representative well using equation W-42
to this section.
[GRAPHIC] [TIFF OMITTED] TR14MY24.106
Where:
ERs,CH4,r = Volumetric CH4 emission rate from
mud degassing for the representative well, r, in standard cubic feet
per minute.
Es,CH4,r = Annual total volumetric CH4
emissions from mud degassing for the representative well, r, in
standard cubic feet.
Tr = Total time that drilling mud is circulated in the
representative well, r, in minutes beginning with initial
penetration of the first hydrocarbon-bearing zone until drilling mud
ceases to be circulated in the wellbore.
(iii) Use equation W-43 to this section to calculate emissions for
any wells drilled in the same sub-basin and within the equivalent
stratigraphic interval in the reporting year.
[GRAPHIC] [TIFF OMITTED] TR14MY24.107
Where:
Es,CH4,p = Annual total CH4 emissions from mud
degassing for the well, p, in standard cubic feet.
ERs,CH4,r = Volumetric CH4 emission rate from
mud degassing for the representative well, r, in standard cubic feet
per minute.
Tp = Total time that drilling mud is circulated in the
well, p, during the reporting year, in minutes beginning with
initial penetration of the first hydrocarbon-bearing zone until
drilling mud ceases to be circulated in the wellbore.
(iv) Calculate CH4 mass emissions using calculations in
paragraph (v) of this section.
(2) Calculation Method 2. If you did not take mudlogging
measurements, calculate emissions from mud degassing for each well
using equation W-44 to this section:
[GRAPHIC] [TIFF OMITTED] TR14MY24.108
Where:
MassCH4,p = Annual total CH4 emissions for the
well, p, in metric tons.
EFCH4 = Emission factor in metric tons CH4 per
drilling day. Use 0.2605 for water-based drilling muds, 0.0586 for
oil-based drilling muds, and 0.0586 for synthetic drilling muds.
DDp = Total number of drilling days for the well, p, when
drilling mud is circulated in the wellbore. The first drilling day
is the day that the borehole penetrated the first hydrocarbon-
bearing zone and the last drilling day is the day drilling mud
ceases to be circulated in the wellbore.
XCH4 = The mole percent of methane in gas vented during
mud degassing in the sub-basin in which the well is located and
derived from the average mole fraction of CH4 in produced
gas for the sub-basin as reported in Sec. 98.236(aa)(1)(ii)(I).
83.85 = The mole percent of methane from the vented gas used to
derive the emission factor (EF).
(3) Calculation Method 3. If you have taken mudlogging measurements
at
[[Page 42287]]
intermittent time intervals for some, but not all, of the time the well
bore has penetrated the first hydrocarbon bearing zone until drilling
mud ceases to be circulated in the wellbore, you must use Calculation
Method 1 to calculate emissions for the cumulative amount of time
mudlogging measurements were taken and Calculation Method 2 for the
cumulative amount of time mudlogging measurements were not taken. To
determine total annual CH4 emissions for the well, add
MassCH4,p calculated using Calculation Method 2 to
Es,CH4,p, if the well is a representative well, or
Es,CH4,p, if the well is not a representative well,
calculated using Calculation Method 1.
(ee) Crankcase venting. For each reciprocating internal combustion
engine with a rated heat capacity greater than 1 mmBtu/hr (or the
equivalent of 130 horsepower), calculate annual CH4 mass
emissions from crankcase venting using one of the methods provided in
paragraphs (ee)(1) and (2) of this section. If you elect to use the
method in paragraph (ee)(1) of this section, you must use the results
of the direct measurement to determine the CH4 emissions. If
any crankcase vents are routed to a flare, you must calculate
CH4, CO2, and N2O emissions for the
flare stack as specified in paragraph (n) of this section and report
emissions from the flare as specified in Sec. 98.236(n).
Notwithstanding the calculation and emissions reporting requirements as
specified in this paragraph (ee) of this section, the number of
reciprocating internal combustion engines with crankcase vents routed
to flares must be reported as specified in Sec. 98.236(ee)(1).
(1) Calculation Method 1. Determine the CH4 mass
emissions from reciprocating internal combustion engines annually using
the method provided in paragraphs (ee)(1)(i) through (iv) of this
section. If you choose to use this method you must use it for all
reciprocating internal combustion engines at the facility, well-pad
site, or gathering and boosting site, except that if you choose to
perform the screening specified in paragraph (ee)(1)(ii) of this
section, you must use the method in paragraph (ee)(2) of this section
to determine emissions from each reciprocating internal combustion
engine that is not operating at the facility, well-pad site, or
gathering and boosting site at the time of the screening.
(i) Determine the volumetric flow from the crankcase vent at
standard conditions using an appropriate meter, calibrated bag, or high
volume sampler according to methods set forth in Sec. 98.234(b), (c),
and (d), respectively. Each measurement must be conducted within 10
percent of 100 percent peak load. You may not measure during period of
startup, shutdown, or malfunction.
(ii) You may choose to use any of the methods set forth in Sec.
98.234(a)(1) through (3) to screen for emissions. If emissions are
detected using the methods set forth in Sec. 98.234(a)(1) through (3),
then you must use one of the methods specified in paragraphs (ee)(1)(i)
of this section to determine the volumetric flow from the crank case
vent at standard conditions. If emissions are not detected using the
methods in Sec. 98.234(a)(1) through (3), then you may assume that the
emissions are zero. For the purposes of this paragraph, when using any
of the methods in Sec. 98.234(a)(1) through (3), emissions are
detected whenever a leak is detected according to the method.
(iii) If conducting measurements for a manifolded group of
crankcase vent sources, you must measure at a single point in the
manifold downstream of all crankcase vent inputs and, if practical,
prior to comingling with other non-compressor emission sources.
Determine the volumetric flow at standard conditions from the common
stack using one of the methods specified in paragraph (ee)(1)(i) of
this section. If the manifolded group contains only crankcase vent
sources, divide the measured volumetric flow equally between all
operating reciprocating internal combustion engines. If the manifolded
group contains crankcase vent sources and compressor vent sources,
follow the methods for manifolded sources provided in paragraphs (o) or
(p) of this section, as applicable, and report emissions from the
crankcase vent as specified in Sec. 98.236(o) or (p), as applicable.
(iv) Using equation W-45 to this section, calculate the annual
volumetric CH4 emissions for each reciprocating internal
combustion engine that was measured during the reporting year.
[GRAPHIC] [TIFF OMITTED] TR14MY24.109
Where:
ECH4 = Annual total volumetric emissions of
CH4 from crankcase venting on the reciprocating internal
combustion engine, in standard cubic feet.
MTs,CCV = Volumetric gas emissions for measured crankcase
vent, in standard cubic feet per hour, measured according to
paragraph (ee)(1)(i) of this section.
GHGCH4 = Concentration of CH4 in the gas
stream entering reciprocating internal combustion engine. If the
concentration of CH4 is unknown, use the concentration of
CH4 in the gas stream either using engineering estimates
based on best available data or as defined in paragraph (u)(2) of
this section.
T = Total operating hours per year for the reciprocating internal
combustion engine.
(v) You must calculate CH4 mass emissions from
volumetric emissions using calculations in paragraph (v) of this
section.
(2) Calculation Method 2. Calculate annual CH4 mass
emissions from crankcase venting for each reciprocating internal
combustion engine using equation W-46 to this section:
[GRAPHIC] [TIFF OMITTED] TR14MY24.110
Where:
ECH4 = Annual total mass emissions of CH4 from
crankcase venting on the reciprocating internal combustion engine,
in metric tons.
EF = Emission factor for crankcase venting on the reciprocating
internal combustion engine, in kilograms CH4 per hour per
reciprocating internal combustion engine. Use 0.083 kilograms
CH4 per hour per reciprocating internal combustion engine
for sources in the onshore petroleum and natural gas production and
onshore petroleum and natural gas gathering and boosting industry
segments. Use 0.11 kilograms CH4 per hour per
reciprocating internal combustion engine for sources in all other
applicable industry segments.
0.001 = Conversion from kilograms to metric tons.
T = Total operating hours per year for the reciprocating internal
combustion engine.
[[Page 42288]]
0
14. Amend Sec. 98.234 by:
0
a. Revising the introductory text, paragraphs (a)(1) through (3), and
(a)(5);
0
b. Removing paragraphs (a)(6) and (7);
0
c. Revising paragraph (d)(3);
0
d. Adding paragraph (d)(5);
0
e. Removing the text ``equation W-41'' and ``(Eq. W-41)'' in paragraph
(e) and adding in its place the text ``equation W-47'' and ``(Eq. W-
47)'', respectively;
0
f. Removing and reserving paragraphs (f) and (g); and
0
g. Adding paragraph (i).
The revisions and additions read as follows:
Sec. 98.234 Monitoring and QA/QC requirements.
The GHG emissions data for petroleum and natural gas emissions
sources must be quality assured as applicable as specified in this
section. Offshore petroleum and natural gas production facilities shall
adhere to the monitoring and QA/QC requirements as set forth in 30 CFR
part 550.
(a) You must use any of the applicable methods described in
paragraphs (a)(1) through (5) of this section to conduct leak
detection(s) or screening survey(s) as specified in Sec. 98.233(k),
(o), (p), and (ee) that occur during a calendar year. You must use any
of the methods described in paragraphs (a)(1) through (5) of this
section to conduct leak detection(s) of equipment leaks from components
as specified in Sec. 98.233(q)(1)(i) or (ii) or (q)(1)(v)(A) that
occur during a calendar year. You must use one of the methods described
in paragraph (a)(1)(ii) or (iii) or (a)(2)(ii) of this section, as
applicable, to conduct leak detection(s) of equipment leaks from
components as specified in Sec. 98.233(q)(1)(iii) or (q)(1)(v)(B). If
electing to comply with Sec. 98.233(q) as specified in Sec.
98.233(q)(1)(iv), you must use any of the methods described in
paragraphs (a)(1) through (5) of this section to conduct leak
detection(s) of equipment leaks from component types as specified in
Sec. 98.233(q)(1)(iv) that occur during a calendar year. Difficult-to-
monitor emissions sources are not exempt from this subpart. If the
primary leak detection method employed cannot be used to monitor
difficult-to-monitor components without elevating the monitoring
personnel more than 2 meters above a support surface, you must use
alternative leak detection devices as described in paragraph (a)(1) or
(3) of this section to monitor difficult-to-monitor equipment leaks or
vented emissions at least once per calendar year.
(1) Optical gas imaging instrument. Use an optical gas imaging
instrument for equipment leak detection as specified in either
paragraph (a)(1)(i), (ii), or (iii) of this section. You may use any of
the methods as specified in paragraphs (a)(1)(i) through (iii) of this
section unless you are required to use a specific method in Sec.
98.233(q)(1).
(i) Optical gas imaging instrument as specified in Sec. 60.18 of
this chapter. Use an optical gas imaging instrument for equipment leak
detection in accordance with 40 CFR part 60, subpart A, Sec. 60.18 of
the Alternative work practice for monitoring equipment leaks, Sec.
60.18(i)(1)(i); Sec. 60.18(i)(2)(i) except that the minimum monitoring
frequency shall be annual using the detection sensitivity level of 60
grams per hour as stated in 40 CFR part 60, subpart A, Table 1:
Detection Sensitivity Levels; Sec. 60.18(i)(2)(ii) and (iii) except
the gas chosen shall be methane, and Sec. 60.18(i)(2)(iv) and (v);
Sec. 60.18(i)(3); Sec. 60.18(i)(4)(i) and (v); including the
requirements for daily instrument checks and distances, and excluding
requirements for video records. Any emissions detected by the optical
gas imaging instrument from an applicable component is a leak. In
addition, you must operate the optical gas imaging instrument to image
the source types required by this subpart in accordance with the
instrument manufacturer's operating parameters.
(ii) Optical gas imaging instrument as specified in Sec. 60.5397a
of this chapter. Use an optical gas imaging instrument for equipment
leak detection in accordance with Sec. 60.5397a (c)(3) and (7), and
(e) of this chapter and paragraphs (a)(1)(ii)(A) through (C) of this
section.
(A) For the purposes of this subpart, any visible emissions
observed by the optical gas imaging instrument from a component
required or elected to be monitored as specified in Sec. 98.233(q)(1)
is a leak.
(B) For the purposes of this subpart, the term ``fugitive emissions
component'' in Sec. 60.5397a of this chapter means ``component.''
(C) For the purpose of complying with Sec. 98.233(q)(1)(iv), the
phrase ``the collection of fugitive emissions components at well sites
and compressor stations'' in Sec. 60.5397a of this chapter means ``the
collection of components for which you elect to comply with Sec.
98.233(q)(1)(iv).''
(iii) Optical gas imaging instrument as specified in appendix K to
part 60 of this chapter. Use an optical gas imaging instrument for
equipment leak detection in accordance with appendix K to part 60,
Determination of Volatile Organic Compound and Greenhouse Gas Leaks
Using Optical Gas Imaging. Any emissions detected by the optical gas
imaging instrument from an applicable component is a leak.
(2) Method 21. Use the equipment leak detection methods in Method
21 in appendix A-7 to part 60 of this chapter as specified in paragraph
(a)(2)(i) or (ii) of this section. You may use either of the methods as
specified in paragraphs (a)(2)(i) and (ii) of this section unless you
are required to use a specific method in Sec. 98.233(q)(1). You must
survey all applicable source types at the facility needed to conduct a
complete equipment leak survey as defined in Sec. 98.233(q)(1). For
the purposes of this subpart, the term ``fugitive emissions component''
in Sec. 60.5397a of this chapter and Sec. 60.5397b of this chapter
means ``component.''
(i) Method 21 with a leak definition of 10,000 ppm. Use the
equipment leak detection methods in Method 21 in appendix A-7 to part
60 of this chapter using methane as the reference compound. If an
instrument reading of 10,000 ppm or greater is measured for any
applicable component, a leak is detected.
(ii) Method 21 with a leak definition of 500 ppm. Use the equipment
leak detection methods in Method 21 in appendix A-7 to part 60 of this
chapter using methane as the reference compound. If an instrument
reading of 500 ppm or greater is measured for any applicable component,
a leak is detected.
(3) Infrared laser beam illuminated instrument. Use an infrared
laser beam illuminated instrument for equipment leak detection. Any
emissions detected by the infrared laser beam illuminated instrument is
a leak. In addition, you must operate the infrared laser beam
illuminated instrument to detect the source types required by this
subpart in accordance with the instrument manufacturer's operating
parameters.
* * * * *
(5) Acoustic leak detection device. Use the acoustic leak detection
device to detect through-valve leakage. When using the acoustic leak
detection device to quantify the through-valve leakage, you must use
the instrument manufacturer's calculation methods to quantify the
through-valve leak. When using the acoustic leak detection device, if a
leak of 3.1 scf per hour or greater is calculated, a leak is detected.
In addition, you must operate the acoustic leak detection device to
monitor the source valves required by this subpart in accordance with
the instrument manufacturer's operating parameters. Acoustic
stethoscope type devices designed to detect through valve leakage when
put in contact with the valve body
[[Page 42289]]
and that provide an audible leak signal but do not calculate a leak
rate can be used to identify through-valve leakage. For these acoustic
stethoscope type devices, a leak is detected if an audible leak signal
is observed or registered by the device. If the acoustic stethoscope
type device is used as a screening to a measurement method and a leak
is detected, the leak must be measured using any one of the methods
specified in paragraphs (b) through (d) of this section.
* * * * *
(d) * * *
(3) For high volume samplers that output methane mass emissions,
you must use the calculations in Sec. 98.233(u) and (v) in reverse to
determine the natural gas volumetric emissions at standard conditions.
For high volume samplers that output methane volumetric flow in actual
conditions, divide the volumetric methane flow rate by the mole
fraction of methane in the natural gas according to the provisions in
Sec. 98.233(u) and estimate natural gas volumetric emissions at
standard conditions using calculations in Sec. 98.233(t). Estimate
CH4 and CO2 volumetric and mass emissions from
volumetric natural gas emissions using the calculations in Sec.
98.233(u) and (v).
* * * * *
(5) If the measured methane flow exceeds the manufacturer's
reported quantitation limit or if the measured natural gas flow
determined as specified in paragraph (d)(3) of this section exceeds 70
percent of the manufacturer's reported maximum sampling flow rate, then
the flow exceeds the capacity of the instrument and you must either use
a temporary or permanent flow meter according to paragraph (b) of this
section or use calibrated bags according to paragraph (c) of this
section to determine the leak or flow rate. If you elect to use OGI to
demonstrate that 100 percent of the flow is captured by the high volume
sampler throughout the measurement period, then the measured flow rate
above the 70 percent maximum sampling rate provision can be used.
However, if any emissions are observed via OGI escaping capture of the
high volume sampler during a measurement period, then that measurement
is considered invalid (i.e., considered to be exceeding the
quantitation capacity of the device) even if the measured flow rate is
less than 70 percent of the sampling rate and you must either use a
temporary or permanent flow meter according to paragraph (b) of this
section or use calibrated bags according to paragraph (c) of this
section to determine the leak or flow rate.
* * * * *
(e) Peng Robinson Equation of State means the equation of state
defined by equation W-47 to this section:
[GRAPHIC] [TIFF OMITTED] TR14MY24.111
(i) You must use any of the applicable methods described in
paragraphs (i)(1) through (4) of this section to conduct a performance
test to determine the concentration of CH4 in the exhaust gas. This
concentration must be used to develop a CH4 emission factor (kg/MMBtu)
for estimating combustion slip from reciprocating internal combustion
engines or gas turbines as specified in Sec. 98.233(z)(4). You may not
conduct performance tests during period of startup, shutdown or
malfunction. You must conduct three separate test runs for each
performance test. Each test run must be conducted within 10 percent of
100 percent peak (or the highest achievable) load and last at least 1
hour.
(1) EPA Method 18 in appendix A-6 to part 60 of this chapter.
(2) EPA Method 320 in appendix A to part 63 of this chapter.
(3) ASTM D6348-12 (Reapproved 2020) (incorporated by reference, see
Sec. 98.7).
(4) EPA Method 25A in appendix A-7 to part 60 of this chapter, with
the use of nonmethane cutter as described in Sec. 1065.265 of this
chapter.
0
15. Amend Sec. 98.235 by revising paragraph (f) to read as follows:
Sec. 98.235 Procedures for estimating missing data.
* * * * *
(f) For the first 6 months of required data collection, facilities
that are currently subject to this subpart W and that start up new
emission sources or acquire new sources from another facility that were
not previously subject to this subpart W may use best engineering
estimates for any data related to those newly operating or newly
acquired sources that cannot reasonably be measured or obtained
according to the requirements of this subpart.
* * * * *
0
16. Effective July 15, 2024, amend Sec. 98.236 by:
0
a. Revising paragraphs (b), (c), and (d)(2)(iii) introductory text;
0
b. Adding paragraph (d)(2)(iii)(M);
0
c. Revising paragraphs (e) introductory text, (e)(1) introductory text,
(e)(2) introductory text, (e)(2)(i), and (g)(5) introductory text;
0
d. Adding paragraph (g)(5)(iv);
0
e. Revising paragraph (g)(6) introductory text;
0
f. Redesignating paragraph (g)(6)(iii) as (g)(6)(iv);
0
g. Adding new paragraph (g)(6)(iii);
0
h. Revising paragraphs (j)(2)(i)(A) and (m)(4) through (6);
0
i. Redesignating paragraphs (m)(7)(ii) and (iii) as (m)(7)(iii) and
(iv), respectively;
0
j. Adding new paragraph (m)(7)(ii);
0
k. Revising paragraphs (o) introductory text, (p) introductory text,
and (q)(1) introductory text;
0
l. Adding paragraph (q)(1)(vi); and
0
m. Revising paragraph (q)(2).
The revisions and additions read as follows:
Sec. 98.236 Data reporting requirements.
* * * * *
(b) Natural gas pneumatic devices. You must indicate whether the
facility contains the following types of equipment: Continuous high
bleed natural gas pneumatic devices, continuous low bleed natural gas
pneumatic devices, and intermittent bleed natural gas pneumatic
devices. If the facility contains any continuous high bleed natural gas
pneumatic devices, continuous low bleed natural gas pneumatic devices,
or intermittent bleed natural gas pneumatic devices, then you must
report the information specified in paragraphs (b)(1) through (b)(6) of
this section, as applicable.
(1) [Reserved]
(2) The number of natural gas pneumatic devices as specified in
paragraphs (b)(2)(i) through (viii) of this section, as applicable.
(i) The total number of natural gas pneumatic devices of each type
(continuous low bleed, continuous high bleed, and intermittent bleed),
determined according to Sec. 98.233(a)(5) through (7).
(ii) The total number of natural gas pneumatic devices of each type
(continuous low bleed, continuous high bleed, and intermittent bleed)
vented
[[Page 42290]]
directly to the atmosphere, determined according to Sec. 98.233(a)(5)
through (7).
(iii) [Reserved]
(iv) The total number of natural gas pneumatic devices of each type
(continuous low bleed, continuous high bleed, and intermittent bleed)
vented directly to the atmosphere for which emissions were calculated
using Calculation Method 1 according to Sec. 98.233(a)(1).
(v) The total number of natural gas pneumatic devices of each type
(continuous low bleed, continuous high bleed, and intermittent bleed)
vented directly to the atmosphere for which emissions were calculated
using Calculation Method 2 according to Sec. 98.233(a)(2).
(vi) The total number of natural gas pneumatic devices of each type
(continuous low bleed, continuous high bleed, and intermittent bleed)
vented directly to the atmosphere for which emissions were calculated
using Calculation Method 3 according to Sec. 98.233(a)(3).
(vii) The total number of natural gas pneumatic devices of each
type (continuous low bleed, continuous high bleed, and intermittent
bleed) for which emissions were calculated using Calculation Method 4
according to Sec. 98.233(a)(4).
(viii) If the reported values in paragraphs (b)(2)(i) through (vii)
of this section are estimated values determined according to Sec.
98.233(a)(6), then you must report the information specified in
paragraphs (b)(2)(viii)(A) through (C) of this section.
(A) The number of natural gas pneumatic devices of each type
reported in paragraphs (b)(2)(i) through (vii) of this section that are
counted.
(B) The number of natural gas pneumatic devices of each type
reported in paragraph (b)(2)(i) through (vii) of this section that are
estimated (not counted).
(C) Whether the calendar year is the first calendar year of
reporting or the second calendar year of reporting.
(3) For natural gas pneumatic devices vented directly to the
atmosphere for which emissions were calculated using Calculation Method
1 according to Sec. 98.233(a)(1), report the information in paragraphs
(b)(3)(i) through (vi) of this section for each measurement location.
(i) Unique measurement location identification number.
(ii) Type of flow monitor (volumetric flow monitor; mass flow
monitor).
(iii) Number of natural gas pneumatic devices of each type
(continuous low bleed, continuous high bleed, and intermittent bleed)
downstream of the flow monitor.
(iv) An indication of whether a natural gas driven pneumatic pump
is also downstream of the flow monitor.
(v) Annual CO2 emissions, in metric tons CO2,
for the natural gas pneumatic devices calculated according to Sec.
98.233(a)(1) for the measurement location.
(vi) Annual CH4 emissions, in metric tons
CH4, for the natural gas pneumatic devices calculated
according to Sec. 98.233(a)(1) for the measurement location.
(4) For natural gas pneumatic devices vented directly to the
atmosphere for which emissions were calculated using Calculation Method
2 according to Sec. 98.233(a)(2), report the information in paragraphs
(b)(4)(i) or (ii) of this section, as applicable.
(i) For onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting facilities:
(A) Indicate the primary measurement method used (temporary flow
meter, calibrated bagging, or high volume sampler).
(B) The average number of hours each type of the natural gas
pneumatic device (continuous low bleed, continuous high bleed, and
intermittent bleed) was in service (i.e., supplied with natural gas) in
the calendar year.
(C) Annual CO2 emissions, in metric tons CO2,
cumulative by type of natural gas pneumatic device for which emissions
were directly measured and calculated as specified in Sec.
98.233(a)(2)(iii) through (viii).
(D) Annual CH4 emissions, in metric tons CH4,
cumulative by type of natural gas pneumatic device for which emissions
were directly measured and calculated as specified in Sec.
98.233(a)(2)(iii) through (viii).
(ii) For onshore natural gas processing facilities, onshore natural
gas transmission compression facilities, underground natural gas
storage facilities, and natural gas distribution facilities:
(A) The number of years used in the current measurement cycle.
(B) Indicate the primary measurement method used (temporary flow
meter, calibrated bagging, or high volume sampler) to measure the
emissions from natural gas pneumatic devices at this facility.
(C) Indicate whether the emissions from any natural gas pneumatic
devices at this facility were calculated using equation W-1B to Sec.
98.233.
(D) If the emissions from any natural gas pneumatic devices at this
facility were calculated using equation W-1B to Sec. 98.233, report
the following information for each type of natural gas pneumatic device
(continuous low bleed, continuous high bleed, and intermittent bleed).
(1) The value of the emission factor for the reporting year as
calculated using equation W-1A to Sec. 98.233 (in scf/hour/device).
(2) The total number of natural gas pneumatic devices measured
across all years upon which the emission factor is based (i.e., the
cumulative value of ``[Sigma]ny=1 Countt,y'' in equation W-
1A to Sec. 98.233).
(3) Total number of natural gas pneumatic devices that vent
directly to the atmosphere and that were not directly measured
according to the requirements in Sec. 98.233(a)(1) or (a)(2)(iii)
(``Countt'' in equation W-1B to Sec. 98.233).
(4) The average estimated number of hours in the operating year the
natural gas pneumatic devices were in service (i.e., supplied with
natural gas) (``Tt'' in equation W-1B to Sec. 98.233).
(E) Annual CO2 emissions, in metric tons CO2,
cumulative by type of natural gas pneumatic device for which emissions
were directly measured and calculated as specified in Sec.
98.233(a)(2)(iii) through (viii).
(F) Annual CH4 emissions, in metric tons CH4,
cumulative by type of natural gas pneumatic device for which emissions
were directly measured and calculated as specified in Sec.
98.233(a)(2)(iii) through (viii).
(G) Annual CO2 emissions, in metric tons CO2,
cumulative by type of natural gas pneumatic device for which emissions
were calculated according to Sec. 98.233(a)(2)(ix). Enter 0 if all
devices at this facility were monitored during the reporting year.
(H) Annual CH4 emissions, in metric tons CH4,
cumulative by type of natural gas pneumatic device for which emissions
were calculated according to Sec. 98.233(a)(2)(ix). Enter 0 if all
devices at this facility were monitored during the reporting year.
(5) For natural gas pneumatic devices vented directly to the
atmosphere for which emissions were calculated using Calculation Method
3 according to Sec. 98.233(a)(3), report the information in paragraphs
(b)(5)(i) through (iv) of this section.
(i) For continuous high bleed and continuous low bleed natural gas
pneumatic devices:
(A) Indicate whether you measured emissions according to Sec.
98.233(a)(3)(i)(A) or used default emission factors according to Sec.
98.233(a)(3)(i)(B) to calculate emissions from your continuous high
bleed and continuous low bleed natural
[[Page 42291]]
gas pneumatic devices vented directly to the atmosphere.
(B) If measurements were made according to Sec.
98.233(a)(3)(i)(A), indicate the primary measurement method used
(temporary flow meter, calibrated bagging, or high volume sampler).
(C) If default emission factors were used according to Sec.
98.233(a)(3)(i)(B) to calculate emissions, report the following
information for each type of applicable natural gas pneumatic device
(continuous low bleed and continuous high bleed).
(1) Total number of natural gas pneumatic devices that vent
directly to the atmosphere and that were not directly measured
according to the requirements in Sec. 98.233(a)(1) or (a)(2)(iii)
(i.e., ``Countt'' in equation W-1B to Sec. 98.233).
(2) The average estimated number of hours in the operating year
that the natural gas pneumatic devices were in service (i.e., supplied
with natural gas) (``Tt'' in equation W-1B to Sec. 98.233).
(ii) For intermittent bleed natural gas pneumatic devices:
(A) Indicate the primary monitoring method used (OGI; Method 21 at
10,000 ppm; Method 21 at 500 ppm; or infrared laser beam) and the
number of complete monitoring surveys conducted.
(B) The total number of intermittent bleed natural gas pneumatic
devices detected as malfunctioning in any pneumatic device monitoring
survey during the calendar year (`` x '' in equation W-1C to Sec.
98.233).
(C) Average time the intermittent bleed natural gas pneumatic
devices were in service (i.e., supplied with natural gas) and assumed
to be malfunctioning in the calendar year (average value of
``Tm.z'' in equation W-1C to Sec. 98.233).
(D) The total number of intermittent bleed natural gas pneumatic
devices that were monitored but were not detected as malfunctioning in
any pneumatic device monitoring survey during the calendar year
(``Count'' in equation W-1C to Sec. 98.233).
(E) Average time the intermittent bleed natural gas pneumatic
devices that were monitored but were not detected as malfunctioning in
any pneumatic device monitoring survey during the calendar year were in
service (i.e., supplied with natural gas) during the calendar year
(``Tavg'' in equation W-1C to Sec. 98.233).
(iii) Annual CO2 emissions, in metric tons
CO2, for each type of natural gas pneumatic device
calculated according to Calculation Method 3 in Sec. 98.233(a)(3).
(iv) Annual CH4 emissions, in metric tons
CH4, for each type of natural gas pneumatic device
calculated according to Calculation Method 3 in Sec. 98.233(a)(3).
(6) For natural gas pneumatic devices for which emissions were
calculated using Calculation Method 4 according to Sec. 98.233(a)(4),
report the following information for each type of applicable natural
gas pneumatic device (continuous low bleed, continuous high bleed, and
intermittent bleed).
(i) [Reserved]
(ii) The estimated average number of hours in the operating year
that the natural gas pneumatic devices were in service (i.e., supplied
with natural gas) (``Tt'' in equation W-1B to Sec. 98.233).
(iii) Annual CO2 emissions, in metric tons
CO2, for the natural gas pneumatic devices combined,
calculated according to Calculation Method 4 in Sec. 98.233(a)(4).
(iv) Annual CH4 emissions, in metric tons
CH4, for the natural gas pneumatic devices combined,
calculated according to Calculation Method 4 in Sec. 98.233(a)(4).
(c) Natural gas driven pneumatic pumps. You must indicate whether
the facility has any natural gas driven pneumatic pumps. If the
facility contains any natural gas driven pneumatic pumps, then you must
report the information specified in paragraphs (c)(1) through (5) of
this section.
(1) [Reserved]
(2) The number of natural gas driven pneumatic pumps as specified
in paragraphs (c)(2)(i) through (iv) of this section, as applicable.
(i) The total number of natural gas driven pneumatic pumps.
(ii) The total number of natural gas driven pneumatic pumps vented
directly to the atmosphere at any point during the year.
(iii) [Reserved]
(iv) [Reserved]
(3) For natural gas driven pneumatic pumps for which vented
emissions were calculated using Calculation Method 1 according to Sec.
98.233(c)(1), report the information in paragraphs (c)(3)(i) through
(vi) of this section for each measurement location.
(i) Unique measurement location identification number.
(ii) Type of flow monitor (volumetric flow monitor; mass flow
monitor).
(iii) Number of natural gas driven pneumatic pumps downstream of
the flow monitor.
(iv) An indication of whether any natural gas pneumatic devices are
also downstream of the monitoring location.
(v) Annual CO2 emissions, in metric tons CO2,
for the natural gas driven pneumatic pump(s) calculated according to
Sec. 98.233(c)(1) for the measurement location.
(vi) Annual CH4 emissions, in metric tons
CH4, for the natural gas driven pneumatic pump(s) calculated
according to Sec. 98.233(c)(1) for the measurement location.
(4) If you used Calculation Method 2 according to Sec.
98.233(c)(2) to calculate vented emissions, report the information in
paragraphs (c)(4)(i) through (viii) of this section, as applicable.
(i) The number of years used in the current measurement cycle.
(ii) The total number of natural gas driven pneumatic pumps for
which emissions were measured or calculated using Calculation Method 2.
(iii) Indicate whether the emissions from the natural gas driven
pneumatic pumps at this facility were measured during the reporting
year or if the emissions were calculated using equation W-2B to Sec.
98.233.
(iv) If the natural gas driven pneumatic pumps at this facility
were measured during the reporting year, indicate the primary
measurement method used (temporary flow meter, calibrated bagging, or
high volume sampler).
(v) If the emissions from natural gas driven pneumatic pumps at
this facility were calculated using equation W-2B to Sec. 98.233,
report the following information:
(A) The value of the emission factor for the reporting year as
calculated using equation W-2A to Sec. 98.233 (in scf/hour/pump).
(B) The total number of natural gas driven pneumatic pumps measured
across all years upon which the emission factor is based (i.e., the
cumulative value of ``[Sigma]ny=1 County'' term used in
equation W-2A to Sec. 98.233).
(C) Total number of natural gas driven pneumatic pumps that vent
directly to the atmosphere and that were not directly measured
according to the requirements in Sec. 98.233(c)(1) or (c)(2)(iii)
(i.e., ``Count'' in equation W-2B to Sec. 98.233).
(D) The average estimated number of hours in the operating year the
pumps were pumping liquid (i.e., ``T'' in equation W-2B to Sec.
98.233).
(vi) Annual CO2 emissions, in metric tons
CO2, cumulative for all natural gas driven pneumatic pumps
for which emissions were directly measured and calculated as specified
in Sec. 98.233(c)(2)(ii) through (vi). Enter 0 if emissions from none
of the natural gas driven pneumatic pumps at this facility were
measured during the reporting year.
[[Page 42292]]
(vii) Annual CH4 emissions, in metric tons
CH4, cumulative for all natural gas driven pneumatic pumps
for which emissions were directly measured and calculated as specified
in Sec. 98.233(c)(2)(ii) through (vi). Enter 0 if emissions from none
of the natural gas driven pneumatic pumps at this facility were
measured during the reporting year.
(viii) Annual CO2 emissions, in metric tons
CO2, cumulative for all natural gas driven pneumatic pumps
for which emissions were calculated according to Sec.
98.233(c)(2)(vii)(B) through (D). Enter 0 if emissions from all natural
gas driven pneumatic pumps at this facility were measured during the
reporting year.
(ix) Annual CH4 emissions, in metric tons
CH4, cumulative for all natural gas driven pneumatic pumps
for which emissions were calculated according to Sec.
98.233(c)(2)(vii)(B) through (D). Enter 0 if emissions from all natural
gas driven pneumatic pumps at this facility were measured during the
reporting year.
(5) If you used Calculation Method 3 according to Sec.
98.233(c)(3) to calculate vented emissions, report the information in
paragraphs (c)(5)(i) through (iv) of this section for the natural gas
driven pneumatic pumps subject to Calculation Method 3.
(i) Number of pumps that vent directly to the atmosphere (i.e.,
``Count'' in equation W-2B to Sec. 98.233).
(ii) Average estimated number of hours in the calendar year that
natural gas driven pneumatic pumps that vented directly to atmosphere
were pumping liquid (``T'' in equation W-2B to Sec. 98.233).
(iii) Annual CO2 emissions, in metric tons
CO2, for all natural gas driven pneumatic pumps vented
directly to the atmosphere combined, calculated according to Sec.
98.233(c)(3).
(iv) Annual CH4 emissions, in metric tons
CH4, for all natural gas driven pneumatic pumps vented
directly to the atmosphere combined, calculated according to Sec.
98.233(c)(3).
(d) * * *
(2) * * *
(iii) If you used Calculation Method 4 as specified in Sec.
98.233(d) to calculate CO2 emissions from the acid gas
removal unit, then you must report the information specified in
paragraphs (d)(2)(iii)(A) through (M) of this section, as applicable to
the simulation software package used.
* * * * *
(M) If a vent meter is installed and you elected to use Calculation
Method 4 for an AGR, report the information in paragraphs
(d)(2)(iii)(M)(1) through (3) of this section.
(1) The total annual volume of vent gas flowing out of the AGR in
cubic feet per year at actual conditions as determined by flow meter
(``Va,meter'' from equation W-4D to Sec. 98.233).
(2) The total annual volume of vent gas flowing out of the AGR in
cubic feet per year at actual conditions as determined the standard
simulation software package (``Va,sim'' from equation W-4D
to Sec. 98.233).
(3) If the calculated percent difference between the vent volumes
(``PD'' from equation W-4D to Sec. 98.233) is greater than 20 percent,
provide a brief description of the reason for the difference.
(e) Dehydrators. You must indicate whether your facility contains
any of the following equipment: Glycol dehydrators for which you
calculated emissions using Calculation Method 1 according to Sec.
98.233(e)(1), glycol dehydrators for which you calculated emissions
using Calculation Method 2 according to Sec. 98.233(e)(2), and
dehydrators that use desiccant. If your facility contains any of the
equipment listed in this paragraph (e), then you must report the
applicable information in paragraphs (e)(1) through (3) of this
section.
(1) For each glycol dehydrator for which you calculated emissions
using Calculation Method 1 (as specified in Sec. 98.233(e)(1)), you
must report the information specified in paragraphs (e)(1)(i) through
(xviii) of this section for the dehydrator.
* * * * *
(2) For glycol dehydrators with an annual average daily natural gas
throughput less than 0.4 million standard cubic feet per day for which
you calculated emissions using Calculation Method 2 (as specified in
Sec. 98.233(e)(2)), you must report the information specified in
paragraphs (e)(2)(i) through (v) of this section for the entire
facility.
(i) The total number of dehydrators at the facility for which you
calculated emissions using Calculation Method 2.
* * * * *
(g) * * *
(5) If you used equation W-10A to Sec. 98.233 to calculate annual
volumetric total gas emissions, then you must report the information
specified in paragraphs (g)(5)(i) through (iv) of this section.
* * * * *
(iv) Whether the flow rate during the initial flowback period was
determined using a multiphase flow meter upstream of the separator.
(6) If you used equation W-10B to Sec. 98.233 to calculate annual
volumetric total gas emissions, then you must report the information
specified in paragraphs (g)(6)(i) through (iv) of this section.
* * * * *
(iii) If a multiphase flowmeter was used to measure the flow rate
during the initial flowback period, report the average flow rate
measured by the multiphase flow meter from the initiation of flowback
to the beginning of the period of time when sufficient quantities of
gas present to enable separation in standard cubic feet per hour.
* * * * *
(j) * * *
(2) * * *
(i) * * *
(A) The total annual oil/condensate throughput that is sent to all
atmospheric tanks in the basin, in barrels. You may delay reporting of
this data element for onshore production if you indicate in the annual
report that wildcat wells and delineation wells are the only wells in
the sub-basin with oil/condensate production that send oil/condensate
to atmospheric tanks for which emissions were calculated using
Calculation Method 3. If you elect to delay reporting of this data
element, you must report by the date specified in Sec. 98.236(cc) the
total annual oil/condensate throughput from all wells and the well ID
number(s) for the well(s) included in this volume.
* * * * *
(m) * * *
(4) Average gas to oil ratio, in standard cubic feet of gas per
barrel of oil (average of the ``GOR'' values used in equation W-18 to
Sec. 98.233). Do not report GOR if you used a continuous flow monitor
to determine the total volume of associated gas vented or routed to the
flare (i.e., if you did not use equation W-18 to Sec. 98.233 for the
well with associated gas venting or flaring emissions).
(5) Volume of oil produced, in barrels, in the calendar year during
the time periods in which associated gas was vented or flared (the sum
of ``Vp,q'' used in equation W-18 to Sec. 98.233). You may
delay reporting of this data element if you indicate in the annual
report that wildcat wells and/or delineation wells are the only wells
from which associated gas was vented or flared. If you elect to delay
reporting of this data element, you must report by the date specified
in Sec. 98.236(cc) the volume of oil produced for well(s) with
associated gas venting and flaring and the well ID number(s) for the
well(s) included in the
[[Page 42293]]
measurement. Do not report the volume of oil produced if you used a
continuous flow monitor to determine the total volume of associated gas
vented or routed to the flare (i.e., if you did not use equation W-18
to Sec. 98.233 for the well with associated gas venting or flaring
emissions).
(6) Total volume of associated gas sent to sales, in standard cubic
feet, in the calendar year during time periods in which associated gas
was vented or flared (the sum of ``SG'' values used in equation W-18 to
Sec. 98.233). You may delay reporting of this data element if you
indicate in the annual report that wildcat wells and/or delineation
wells from which associated gas was vented or flared. If you elect to
delay reporting of this data element, you must report by the date
specified in Sec. 98.236(cc) the measured total volume of associated
gas sent to sales for well(s) with associated gas venting and flaring
and the well ID number(s) for the well(s) included in the measurement.
Do not report the volume of gas sent to sales if you used a continuous
flow monitor to determine the total volume of associated gas vented or
routed to the flare (i.e., if you did not use equation W-18 to Sec.
98.233).
(7) * * *
(ii) If the associated gas volume vented from the well was measured
using a continuous flow monitor, total volume of associated gas vented
directly to the atmosphere, in standard cubic feet.
* * * * *
(o) Centrifugal compressors. You must indicate whether your
facility has centrifugal compressors. You must report the information
specified in paragraphs (o)(1) and (2) of this section for all
centrifugal compressors at your facility. For each compressor source or
manifolded group of compressor sources that you conduct as found leak
measurements as specified in Sec. 98.233(o)(2) or (4), you must report
the information specified in paragraph (o)(3) of this section. For each
compressor source or manifolded group of compressor sources that you
conduct continuous monitoring as specified in Sec. 98.233(o)(3) or
(5), you must report the information specified in paragraph (o)(4) of
this section. Centrifugal compressors in onshore petroleum and natural
gas production and onshore petroleum and natural gas gathering and
boosting that calculate emissions according to Sec. 98.233(o)(10)(iii)
are not required to report information in paragraphs (o)(1) through (4)
of this section and instead must report the information specified in
paragraph (o)(5) of this section.
* * * * *
(p) Reciprocating compressors. You must indicate whether your
facility has reciprocating compressors. You must report the information
specified in paragraphs (p)(1) and (2) of this section for all
reciprocating compressors at your facility. For each compressor source
or manifolded group of compressor sources that you conduct as found
leak measurements as specified in Sec. 98.233(p)(2) or (4), you must
report the information specified in paragraph (p)(3) of this section.
For each compressor source or manifolded group of compressor sources
that you conduct continuous monitoring as specified in Sec.
98.233(p)(3) or (5), you must report the information specified in
paragraph (p)(4) of this section. Reciprocating compressors in onshore
petroleum and natural gas production and onshore petroleum and natural
gas gathering and boosting that calculate emissions according to Sec.
98.233(p)(10)(iii) are not required to report information in paragraphs
(p)(1) through (4) of this section and instead must report the
information specified in paragraph (p)(5) of this section.
* * * * *
(q) * * *
(1) You must report the information specified in paragraphs
(q)(1)(i) through (vi) of this section.
* * * * *
(vi) Report whether emissions were calculated using Calculation
Method 1 (leaker factor emission calculation methodology) and/or using
Calculation Method 2 (leaker measurement methodology).
(2) You must indicate whether your facility contains any of the
component types subject to or complying with Sec. 98.233(q) that are
listed in Sec. 98.232(c)(21), (d)(7), (e)(7) or (8), (f)(5) through
(8), (g)(4), (g)(6) or (7), (h)(5), (h)(7) or (8), (i)(1), or (j)(10)
for your facility's industry segment. For each component type that is
located at your facility, you must report the information specified in
paragraphs (q)(2)(i) through (v) of this section. If a component type
is located at your facility and no leaks were identified from that
component, then you must report the information in paragraphs (q)(2)(i)
through (v) of this section but report a zero (``0'') for the
information required according to paragraphs (q)(2)(ii) through (v) of
this section. If you used Calculation Method 1 (leaker factor emission
calculation methodology) for some complete leak surveys and used
Calculation Method 2 (leaker measurement methodology) for some complete
leak surveys, you must report the information specified in paragraphs
(q)(2)(i) through (ix) of this section separately for component surveys
using Calculation Method 1 and Calculation Method 2.
(i) [Reserved]
(ii) Component type.
(iii) [Reserved]
(iv) Emission factor or measurement method used (e.g., default
emission factor; facility-specific emission factor developed according
to Sec. 98.233(q)(4); or direct measurement according to Sec.
98.233(q)(3)).
(v) Total number of components surveyed by type in the calendar
year.
(vi) Total number of the surveyed component type that were
identified as leaking in the calendar year (``xp'' in
equation W-30 to Sec. 98.233 for the component type or the number of
leaks measured for the specified component type according to the
provisions in Sec. 98.233(q)(3)).
(vii) Average time the surveyed components are assumed to be
leaking and operational, in hours (average of ``Tp,z'' from
equation W-30 to Sec. 98.233 for the component type or average
duration of leaks for the specified component type determined according
to the provisions in Sec. 98.233(q)(3)(ii))).
(viii) Annual CO2 emissions, in metric tons
CO2, for the component type as calculated using equation W-
30 to Sec. 98.233 or Sec. 98.233(q)(3)(vii) (for surveyed components
only).
(ix) Annual CH4 emissions, in metric tons
CH4, for the component type as calculated using equation W-
30 to Sec. 98.233 or Sec. 98.233(q)(3)(vii) (for surveyed components
only).
* * * * *
0
17. Revise and republish Sec. 98.236 to read as follows:
Sec. 98.236 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain reported emissions and related information
as specified in this section. Reporters that use a flow or volume
measurement system that corrects to standard conditions as provided in
the introductory text in Sec. 98.233 for data elements that are
otherwise required to be determined at actual conditions, report gas
volumes at standard conditions rather than the gas volumes at actual
conditions and report the standard temperature and pressure used by the
measurement system rather than the actual temperature and pressure.
(a) The annual report must include the information specified in
paragraphs (a)(1) through (10) of this section for
[[Page 42294]]
each applicable industry segment. The annual report must also include
annual emissions totals, in metric tons of each GHG, for each
applicable industry segment listed in paragraphs (a)(1) through (10) of
this section, and each applicable emission source listed in paragraphs
(b) through (z), (dd) and (ee) of this section.
(1) Onshore petroleum and natural gas production. For the
equipment/activities specified in paragraphs (a)(1)(i) through (xxii)
of this section, report the information specified in the applicable
paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified
in paragraph (b) of this section.
(ii) Natural gas driven pneumatic pumps. Report the information
specified in paragraph (c) of this section.
(iii) Acid gas removal units and nitrogen removal units. Report the
information specified in paragraph (d) of this section.
(iv) Dehydrators. Report the information specified in paragraph (e)
of this section.
(v) Liquids unloading. Report the information specified in
paragraph (f) of this section.
(vi) Completions and workovers with hydraulic fracturing. Report
the information specified in paragraph (g) of this section.
(vii) Completions and workovers without hydraulic fracturing.
Report the information specified in paragraph (h) of this section.
(viii) Blowdown vent stacks. Report the information specified in
paragraph (i) of this section.
(ix) Hydrocarbon liquids and produced water storage tanks. Report
the information specified in paragraph (j) of this section.
(x) Well testing. Report the information specified in paragraph (l)
of this section.
(xi) Associated natural gas. Report the information specified in
paragraph (m) of this section.
(xii) Flare stacks. Report the information specified in paragraph
(n) of this section.
(xiii) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
(xiv) Reciprocating compressors. Report the information specified
in paragraph (p) of this section.
(xv) Equipment leak surveys. Report the information specified in
paragraph (q) of this section.
(xvi) Equipment leaks by population count. Report the information
specified in paragraph (r) of this section.
(xvii) EOR injection pumps. Report the information specified in
paragraph (w) of this section.
(xviii) EOR hydrocarbon liquids. Report the information specified
in paragraph (x) of this section.
(xix) Other large release events. Report the information specified
in paragraph (y) of this section.
(xx) Combustion equipment. Report the information specified in
paragraph (z) of this section.
(xxi) Drilling mud degassing. Report the information specified in
paragraph (dd) of this section.
(xxii) Crankcase vents. Reporting the information specified in
paragraph (ee) of this section.
(2) Offshore petroleum and natural gas production. For the
equipment/activities specified in paragraphs (a)(2)(i) and (ii) of this
section, report the information specified in the applicable paragraphs
of this section.
(i) Offshore petroleum and natural gas production. Report the
information specified in paragraph (s) of this section.
(ii) Other large release events. Report the information specified
in paragraph (y) of this section.
(3) Onshore natural gas processing. For the equipment/activities
specified in paragraphs (a)(3)(i) through (xi) of this section, report
the information specified in the applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified
in paragraph (b) of this section.
(ii) Acid gas removal units and nitrogen removal units. Report the
information specified in paragraph (d) of this section.
(iii) Dehydrators. Report the information specified in paragraph
(e) of this section.
(iv) Blowdown vent stacks. Report the information specified in
paragraph (i) of this section.
(v) Hydrocarbon liquids and produced water storage tanks. Report
the information specified in paragraph (j) of this section.
(vi) Flare stacks. Report the information specified in paragraph
(n) of this section.
(vii) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
(viii) Reciprocating compressors. Report the information specified
in paragraph (p) of this section.
(ix) Equipment leak surveys. Report the information specified in
paragraph (q) of this section.
(x) Other large release events. Report the information specified in
paragraph (y) of this section.
(xi) Crankcase vents. Report the information specified in paragraph
(ee) of this section.
(4) Onshore natural gas transmission compression. For the
equipment/activities specified in paragraphs (a)(4)(i) through (x) of
this section, report the information specified in the applicable
paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified
in paragraph (b) of this section.
(ii) Dehydrators. Report the information specified in paragraph (e)
of this section.
(iii) Blowdown vent stacks. Report the information specified in
paragraph (i) of this section.
(iv) Condensate storage tanks. Report the information specified in
paragraph (k) of this section.
(v) Flare stacks. Report the information specified in paragraph (n)
of this section.
(vi) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
(vii) Reciprocating compressors. Report the information specified
in paragraph (p) of this section.
(viii) Equipment leak surveys. Report the information specified in
paragraph (q) of this section.
(ix) Other large release events. Report the information specified
in paragraph (y) of this section.
(x) Crankcase vents. Reporting the information specified in
paragraph (ee) of this section.
(5) Underground natural gas storage. For the equipment/activities
specified in paragraphs (a)(5)(i) through (xi) of this section, report
the information specified in the applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified
in paragraph (b) of this section.
(ii) Dehydrators. Report the information specified in paragraph (e)
of this section.
(iii) Blowdown vent stacks. Report the information specified in
paragraph (i) of this section.
(iv) Condensate storage tanks. Report the information specified in
paragraph (k) of this section.
(v) Flare stacks. Report the information specified in paragraph (n)
of this section.
(vi) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
(vii) Reciprocating compressors. Report the information specified
in paragraph (p) of this section.
(viii) Equipment leak surveys. Report the information specified in
paragraph (q) of this section.
(ix) Equipment leaks by population count. Report the information
specified in paragraph (r) of this section.
(x) Other large release events. Report the information specified in
paragraph (y) of this section.
[[Page 42295]]
(xi) Crankcase vents. Reporting the information specified in
paragraph (ee) of this section.
(6) LNG storage. For the equipment/activities specified in
paragraphs (a)(6)(i) through (ix) of this section, report the
information specified in the applicable paragraphs of this section.
(i) Acid gas removal units and nitrogen removal units. Report the
information specified in paragraph (d) of this section.
(ii) Blowdown vent stacks. Report the information specified in
paragraph (i) of this section.
(iii) Flare stacks. Report the information specified in paragraph
(n) of this section.
(iv) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
(v) Reciprocating compressors. Report the information specified in
paragraph (p) of this section.
(vi) Equipment leak surveys. Report the information specified in
paragraph (q) of this section.
(vii) Equipment leaks by population count. Report the information
specified in paragraph (r) of this section.
(viii) Other large release events. Report the information specified
in paragraph (y) of this section.
(ix) Crankcase vents. Reporting the information specified in
paragraph (ee) of this section.
(7) LNG import and export equipment. For the equipment/activities
specified in paragraphs (a)(7)(i) through (ix) of this section, report
the information specified in the applicable paragraphs of this section.
(i) Acid gas removal units and nitrogen removal units. Report the
information specified in paragraph (d) of this section.
(ii) Blowdown vent stacks. Report the information specified in
paragraph (i) of this section.
(iii) Flare stacks. Report the information specified in paragraph
(n) of this section.
(iv) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
(v) Reciprocating compressors. Report the information specified in
paragraph (p) of this section.
(vi) Equipment leak surveys. Report the information specified in
paragraph (q) of this section.
(vii) Equipment leaks by population count. Report the information
specified in paragraph (r) of this section.
(viii) Other large release events. Report the information specified
in paragraph (y) of this section.
(ix) Crankcase vents. Reporting the information specified in
paragraph (ee) of this section.
(8) Natural gas distribution. For the equipment/activities
specified in paragraphs (a)(8)(i) through (vii) of this section, report
the information specified in the applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified
in paragraph (b) of this section.
(ii) Blowdown vent stacks. Report the information specified in
paragraph (i) of this section.
(iii) Equipment leak surveys. Report the information specified in
paragraph (q) of this section.
(iv) Equipment leaks by population count. Report the information
specified in paragraph (r) of this section.
(v) Other large release events. Report the information specified in
paragraph (y) of this section.
(vi) Combustion equipment. Report the information specified in
paragraph (z) of this section.
(vii) Crankcase vents. Reporting the information specified in
paragraph (ee) of this section.
(9) Onshore petroleum and natural gas gathering and boosting. For
the equipment/activities specified in paragraphs (a)(9)(i) through
(xiv) of this section, report the information specified in the
applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified
in paragraph (b) of this section.
(ii) Natural gas driven pneumatic pumps. Report the information
specified in paragraph (c) of this section.
(iii) Acid gas removal units and nitrogen removal units. Report the
information specified in paragraph (d) of this section.
(iv) Dehydrators. Report the information specified in paragraph (e)
of this section.
(v) Blowdown vent stacks. Report the information specified in
paragraph (i) of this section.
(vi) Hydrocarbon liquids and produced water storage tanks. Report
the information specified in paragraph (j) of this section.
(vii) Flare stacks. Report the information specified in paragraph
(n) of this section.
(viii) Centrifugal compressors. Report the information specified in
paragraph (o) of this section.
(ix) Reciprocating compressors. Report the information specified in
paragraph (p) of this section.
(x) Equipment leak surveys. Report the information specified in
paragraph (q) of this section.
(xi) Equipment leaks by population count. Report the information
specified in paragraph (r) of this section.
(xii) Other large release events. Report the information specified
in paragraph (y) of this section.
(xiii) Combustion equipment. Report the information specified in
paragraph (z) of this section.
(xiv) Crankcase vents. Reporting the information specified in
paragraph (ee) of this section.
(10) Onshore natural gas transmission pipeline. For the equipment/
activities specified in paragraphs (a)(10)(i) through (iii) of this
section, report the information specified in the applicable paragraphs
of this section.
(i) Blowdown vent stacks. Report the information specified in
paragraph (i) of this section.
(ii) Equipment leaks by population count. Report the information
specified in paragraph (r) of this section.
(iii) Other large release events. Report the information specified
in paragraph (y) of this section.
(b) Natural gas pneumatic devices. You must indicate whether the
facility contains the following types of equipment: Continuous high
bleed natural gas pneumatic devices, continuous low bleed natural gas
pneumatic devices, and intermittent bleed natural gas pneumatic
devices. If the facility contains any continuous high bleed natural gas
pneumatic devices, continuous low bleed natural gas pneumatic devices,
or intermittent bleed natural gas pneumatic devices, then you must
report the information specified in paragraphs (b)(1) through (6) of
this section, as applicable. You must report the information specified
in paragraphs (b)(1) through (6) of this section, as applicable, for
each well-pad (for onshore petroleum and natural gas production), each
gathering and boosting site (for onshore petroleum and natural gas
gathering and boosting), or facility (for all other applicable industry
segments).
(1) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(2) The number of natural gas pneumatic devices as specified in
paragraphs (b)(2)(i) through (viii) of this section, as applicable. If
a natural gas pneumatic device was vented directly to the atmosphere
for part of the year and routed to a flare, combustion unit, or vapor
recovery system during another part of the year, then include the
device in each of the applicable counts specified in paragraphs
(b)(2)(ii) through (vii) of this section.
(i) The total number of natural gas pneumatic devices of each type
[[Page 42296]]
(continuous low bleed, continuous high bleed, and intermittent bleed),
determined according to Sec. 98.233(a)(5) through (7).
(ii) The total number of natural gas pneumatic devices of each type
(continuous low bleed, continuous high bleed, and intermittent bleed)
vented directly to the atmosphere, determined according to Sec.
98.233(a)(5) through (7).
(iii) The total number of natural gas pneumatic devices of each
type (continuous low bleed, continuous high bleed, and intermittent
bleed) routed to a flare, combustion, or vapor recovery system.
(iv) The total number of natural gas pneumatic devices of each type
(continuous low bleed, continuous high bleed, and intermittent bleed)
vented directly to the atmosphere for which emissions were calculated
using Calculation Method 1 according to Sec. 98.233(a)(1).
(v) The total number of natural gas pneumatic devices of each type
(continuous low bleed, continuous high bleed, and intermittent bleed)
vented directly to the atmosphere for which emissions were calculated
using Calculation Method 2 according to Sec. 98.233(a)(2).
(vi) The total number of natural gas pneumatic devices of each type
(continuous low bleed, continuous high bleed, and intermittent bleed)
vented directly to the atmosphere for which emissions were calculated
using Calculation Method 3 according to Sec. 98.233(a)(3).
(vii) The total number of natural gas pneumatic devices of each
type (continuous low bleed, continuous high bleed, and intermittent
bleed) vented directly to the atmosphere for which emissions were
calculated using Calculation Method 4 according to Sec. 98.233(a)(4).
(viii) If the reported values in paragraphs (b)(2)(i) through (vii)
of this section are estimated values determined according to Sec.
98.233(a)(6), then you must report the information specified in
paragraphs (b)(2)(viii)(A) through (C) of this section.
(A) The number of natural gas pneumatic devices of each type
reported in paragraphs (b)(2)(i) through (vii) of this section that are
counted.
(B) The number of natural gas pneumatic devices of each type
reported in paragraphs (b)(2)(i) through (vii) of this section that are
estimated (not counted).
(C) Whether the calendar year is the first calendar year of
reporting or the second calendar year of reporting.
(3) For natural gas pneumatic devices vented directly to the
atmosphere for which emissions were calculated using Calculation Method
1 according to Sec. 98.233(a)(1), report the information in paragraphs
(b)(3)(i) through (vi) of this section for each measurement location.
(i) Unique measurement location identification number.
(ii) Type of flow monitor (volumetric flow monitor; mass flow
monitor).
(iii) Number of natural gas pneumatic devices of each type
(continuous low bleed, continuous high bleed, and intermittent bleed)
downstream of the flow monitor.
(iv) An indication of whether a natural gas driven pneumatic pump
is also downstream of the flow monitor.
(v) Annual CO2 emissions, in metric tons CO2,
for the natural gas pneumatic devices calculated according to Sec.
98.233(a)(1) for the measurement location.
(vi) Annual CH4 emissions, in metric tons
CH4, for the natural gas pneumatic devices calculated
according to Sec. 98.233(a)(1) for the measurement location.
(4) For natural gas pneumatic devices vented directly to the
atmosphere for which emissions were calculated using Calculation Method
2 according to Sec. 98.233(a)(2), report the information in paragraphs
(b)(4)(i) through (ii) of this section, as applicable.
(i) For onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting facilities:
(A) Indicate the primary measurement method used (temporary flow
meter, calibrated bagging, or high volume sampler).
(B) The average number of hours each type of the natural gas
pneumatic device (continuous low bleed, continuous high bleed, and
intermittent bleed) was in service (i.e., supplied with natural gas) in
the calendar year.
(C) Annual CO2 emissions, in metric tons CO2,
cumulative by type of natural gas pneumatic device for which emissions
were directly measured and calculated as specified in Sec.
98.233(a)(2)(iii) through (viii).
(D) Annual CH4 emissions, in metric tons CH4,
cumulative by type of natural gas pneumatic device for which emissions
were directly measured and calculated as specified in Sec.
98.233(a)(2)(iii) through (viii).
(ii) For onshore natural gas processing facilities, onshore natural
gas transmission compression facilities, underground natural gas
storage facilities, and natural gas distribution facilities:
(A) The number of years used in the current measurement cycle.
(B) Indicate the primary measurement method used (temporary flow
meter, calibrated bagging, or high volume sampler) to measure the
emissions from natural gas pneumatic devices at this facility.
(C) Indicate whether the emissions from any natural gas pneumatic
devices at this facility were calculated using equation W-1B to Sec.
98.233.
(D) If the emissions from any natural gas pneumatic devices at this
facility were calculated using equation W-1B to Sec. 98.233, report
the following information for each type of natural gas pneumatic device
(continuous low bleed, continuous high bleed, and intermittent bleed).
(1) The value of the emission factor for the reporting year as
calculated using equation W-1A to Sec. 98.233 (in scf/hour/device).
(2) The total number of natural gas pneumatic devices measured
across all years upon which the emission factor is based (i.e., the
cumulative value of ``[Sigma]y=1n Countt,y'' in equation W-1A to Sec.
98.233).
(3) Total number of natural gas pneumatic devices that vent
directly to the atmosphere and that were not directly measured
according to the requirements in Sec. 98.233(a)(1) or (a)(2)(iii)
(i.e., ``Countt'' in equation W-1B to Sec. 98.233).
(4) The average estimated number of hours in the operating year the
natural gas pneumatic devices were in service (i.e., supplied with
natural gas) (``Tt'' in equation W-1B to Sec. 98.233).
(E) Annual CO2 emissions, in metric tons CO2,
cumulative by type of natural gas pneumatic device for which emissions
were directly measured and calculated as specified in Sec.
98.233(a)(2)(iii) through (viii).
(F) Annual CH4 emissions, in metric tons CH4,
cumulative by type of natural gas pneumatic device for which emissions
were directly measured and calculated as specified in Sec.
98.233(a)(2)(iii) through (viii).
(G) Annual CO2 emissions, in metric tons CO2,
cumulative by type of natural gas pneumatic device for which emissions
were calculated according to Sec. 98.233(a)(2)(ix). Enter 0 if all
devices at this facility were monitored during the reporting year.
(H) Annual CH4 emissions, in metric tons CH4,
cumulative by type of natural gas pneumatic device for which emissions
were calculated according to Sec. 98.233(a)(2)(ix). Enter 0 if all
devices at this facility were monitored during the reporting year.
(5) For natural gas pneumatic devices vented directly to the
atmosphere for which emissions were calculated using
[[Page 42297]]
Calculation Method 3 according to Sec. 98.233(a)(3), report the
information in paragraphs (b)(5)(i) through (iv) of this section.
(i) For continuous high bleed and continuous low bleed natural gas
pneumatic devices:
(A) Indicate whether you measured emissions according to Sec.
98.233(a)(3)(i)(A) or used default emission factors according to Sec.
98.233(a)(3)(i)(B) to calculate emissions from your continuous high
bleed and continuous low bleed natural gas pneumatic devices vented
directly to the atmosphere at this well-pad, gathering and boosting
site, or facility, as applicable.
(B) If measurements were made according to Sec.
98.233(a)(3)(i)(A), indicate the primary measurement method used
(temporary flow meter, calibrated bagging, or high volume sampler).
(C) If default emission factors were used according to Sec.
98.233(a)(3)(i)(B) to calculate emissions, report the following
information for each type of applicable natural gas pneumatic device
(continuous low bleed and continuous high bleed).
(1) Total number of natural gas pneumatic devices that vent
directly to the atmosphere and that were not directly measured
according to the requirements in Sec. 98.233(a)(1) or (a)(2)(iii)
(``Countt'' in equation W-1B to Sec. 98.233).
(2) The average estimated number of hours in the operating year
that the natural gas pneumatic devices were in service (i.e., supplied
with natural gas) (``Tt'' in equation W-1B to Sec. 98.233).
(ii) For intermittent bleed natural gas pneumatic devices:
(A) Indicate the primary monitoring method used (OGI; Method 21 at
10,000 ppm; Method 21 at 500 ppm; or infrared laser beam) and the
number of complete monitoring surveys conducted at the well-pad site or
gathering and boosting site.
(B) The total number of intermittent bleed natural gas pneumatic
devices detected as malfunctioning in any pneumatic device monitoring
survey during the calendar year (``x'' in equation W-1C to Sec.
98.233).
(C) Average time the intermittent bleed natural gas pneumatic
devices were in service (i.e., supplied with natural gas) and assumed
to be malfunctioning in the calendar year (average value of
``Tm.z'' in equation W-1C to Sec. 98.233).
(D) The total number of intermittent bleed natural gas pneumatic
devices that were monitored but were not detected as malfunctioning in
any pneumatic device monitoring survey during the calendar year
(``Count'' in equation W-1C to Sec. 98.233).
(E) Average time the intermittent bleed natural gas pneumatic
devices that were monitored but were not detected as malfunctioning in
any pneumatic device monitoring survey during the calendar year were in
service (i.e., supplied with natural gas) during the calendar year
(``Tavg'' in equation W-1C to Sec. 98.233).
(iii) Annual CO2 emissions, in metric tons
CO2, for each type of natural gas pneumatic device
calculated according to Calculation Method 3 in Sec. 98.233(a)(3).
(iv) Annual CH4 emissions, in metric tons
CH4, for each type of natural gas pneumatic device
calculated according to Calculation Method 3 in Sec. 98.233(a)(3).
(6) For natural gas pneumatic devices vented directly to the
atmosphere for which emissions were calculated using Calculation Method
4 according to Sec. 98.233(a)(4), report the following information for
each type of applicable natural gas pneumatic device (continuous low
bleed, continuous high bleed, and intermittent bleed).
(i) Total number of natural gas pneumatic devices that vent
directly to the atmosphere and that were not directly measured
according to the requirements in Sec. 98.233(a)(1) (i.e.,
``Countt'' in equation W-1B to Sec. 98.233).
(ii) The average estimated number of hours in the operating year
that the natural gas pneumatic devices were in service (i.e., supplied
with natural gas) (``Tt'' in equation W-1B to Sec. 98.233).
(iii) Annual CO2 emissions, in metric tons
CO2, for each type of natural gas pneumatic device
calculated according to Calculation Method 4 in Sec. 98.233(a)(4).
(iv) Annual CH4 emissions, in metric tons
CH4, for each type of natural gas pneumatic device
calculated according to Calculation Method 4 in Sec. 98.233(a)(4).
(c) Natural gas driven pneumatic pumps. You must indicate whether
the facility has any natural gas driven pneumatic pumps. If the
facility contains any natural gas driven pneumatic pumps, then you must
report the information specified in paragraphs (c)(1) through (5) of
this section. You must report the information specified in paragraphs
(c)(1) through (5) of this section, as applicable, for each well-pad
site (for onshore petroleum and natural gas production) and each
gathering and boosting site (for onshore petroleum and natural gas
gathering and boosting).
(1) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(2) The number of natural gas driven pneumatic pumps as specified
in paragraphs (c)(2)(i) through (iv) of this section, as applicable. If
a natural gas driven pneumatic pump was vented directly to the
atmosphere for part of the year and routed to a flare, combustion, or
vapor recovery system during another part of the year, then include the
device in each of the applicable counts specified in paragraphs
(c)(2)(ii) through (iv) of this section.
(i) The total number of natural gas driven pneumatic pumps.
(ii) The total number of natural gas driven pneumatic pumps vented
directly to the atmosphere at any point during the year (including
pumps that normally routed emissions to a flare but flow bypassed the
flare for part of the year).
(iii) The total number of natural gas driven pneumatic pumps routed
to a flare at any point during the year.
(iv) The total number of natural gas driven pneumatic pumps routed
to combustion or a vapor recovery system at any point during the year.
(3) For natural gas driven pneumatic pumps for which vented
emissions were calculated using Calculation Method 1 according to Sec.
98.233(c)(1), report the information in paragraphs (c)(3)(i) through
(vi) of this section for each measurement location.
(i) Unique measurement location identification number.
(ii) Type of flow monitor (volumetric flow monitor; mass flow
monitor).
(iii) Number of natural gas driven pneumatic pumps downstream of
the flow monitor.
(iv) An indication of whether any natural gas pneumatic devices are
also downstream of the monitoring location.
(v) Annual CO2 emissions, in metric tons CO2,
for the pneumatic pump(s) calculated according to Sec. 98.233(c)(1)
for the measurement location.
(vi) Annual CH4 emissions, in metric tons
CH4, for the pneumatic pump(s) calculated according to Sec.
98.233(c)(1) for the measurement location.
(4) If you used Calculation Method 2 according to Sec.
98.233(c)(2) to calculate vented emissions, report the information in
paragraphs (c)(4)(i) through (ix) of this section, as applicable.
(i) The number of years used in the current measurement cycle.
(ii) The total number of natural gas driven pneumatic pumps for
which emissions were measured or calculated using Calculation Method 2.
[[Page 42298]]
(iii) Indicate whether the emissions from the natural gas driven
pneumatic pumps at this well-pad site or gathering and boosting site,
as applicable, were measured during the reporting year or if the
emissions were calculated using equation W-2B to Sec. 98.233.
(iv) If the natural gas driven pneumatic pumps at this well-pad
site or gathering and boosting site, as applicable, were measured
during the reporting year, indicate the primary measurement method used
(temporary flow meter, calibrated bagging, or high volume sampler).
(v) If the emissions from natural gas driven pneumatic pumps at
this well-pad site or gathering and boosting site, as applicable, were
calculated using equation W-2B to Sec. 98.233, report the following
information:
(A) The value of the emission factor for the reporting year as
calculated using equation W-2A to Sec. 98.233 (in scf/hour/pump).
(B) The total number of natural gas driven pneumatic pumps measured
across all years upon which the emission factor is based (i.e., the
cumulative value of ``Sy=1n County'' term used in equation W-2A to
Sec. 98.233).
(C) Total number of natural gas driven pneumatic pumps that vent
directly to the atmosphere and that were not directly measured
according to the requirements in Sec. 98.233(c)(1) or (c)(2)(iii)
(i.e., ``Count'' in equation W-2B to Sec. 98.233).
(D) The average estimated number of hours in the operating year the
pumps were pumping liquid (i.e., ``T'' in equation W-2B to Sec.
98.233).
(vi) Annual CO2 emissions, in metric tons
CO2, cumulative for all natural gas driven pneumatic pumps
for which emissions were directly measured and calculated as specified
in Sec. 98.233(c)(2)(ii) through (vi). Enter 0 if emissions from none
of the natural gas driven pneumatic pumps at this well-pad or gathering
and boosting site were measured during the reporting year.
(vii) Annual CH4 emissions, in metric tons
CH4, cumulative for all natural gas driven pneumatic pumps
for which emissions were directly measured and calculated as specified
in Sec. 98.233(c)(2)(ii) through (vi). Enter 0 if emissions from none
of the natural gas driven pneumatic pumps at this well-pad or gathering
and boosting site were measured during the reporting year.
(viii) Annual CO2 emissions, in metric tons
CO2, cumulative for all natural gas driven pneumatic pumps
for which emissions were calculated according to Sec.
98.233(c)(2)(vii)(B) through (D). Enter 0 if emissions from all natural
gas driven pneumatic pumps at this well-pad or gathering and boosting
site were measured during the reporting year.
(ix) Annual CH4 emissions, in metric tons
CH4, cumulative for all natural gas driven pneumatic pumps
for which emissions were calculated according to Sec.
98.233(c)(2)(vii)(B) through (D). Enter 0 if emissions from all natural
gas driven pneumatic pumps at this well-pad site or gathering and
boosting site were measured during the reporting year.
(5) If you used Calculation Method 3 according to Sec.
98.233(c)(3) to calculate vented emissions, report the information in
paragraphs (c)(5)(i) through (iv) of this section for the natural gas
driven pneumatic pumps subject to Calculation Method 3.
(i) Number of pumps that vent directly to the atmosphere (i.e.,
``Count'' in equation W-2B to Sec. 98.233).
(ii) Average estimated number of hours in the calendar year that
natural gas driven pneumatic pumps that vented directly to atmosphere
were pumping liquid (``T'' in equation W-2B to Sec. 98.233).
(iii) Annual CO2 emissions, in metric tons
CO2, for all natural gas driven pneumatic pumps vented
directly to the atmosphere combined, calculated according to Sec.
98.233(c)(3).
(iv) Annual CH4 emissions, in metric tons
CH4, for all natural gas driven pneumatic pumps vented
directly to the atmosphere combined, calculated according to Sec.
98.233(c)(3).
(d) Acid gas removal units and nitrogen removal units. You must
indicate whether your facility has any acid gas removal units or
nitrogen removal units that vent directly to the atmosphere, to a flare
or engine, or to a sulfur recovery plant. For any acid gas removal
units or nitrogen removal units that vent directly to the atmosphere or
to a sulfur recovery plant, you must report the information specified
in paragraphs (d)(1) and (2) of this section. If the acid gas removal
units or nitrogen removal units that vent directly to the atmosphere
for only part of the year, report the information specified in
paragraph (d)(2) if this section for the part of the year that the
units vent directly to the atmosphere. For acid gas removal units or
nitrogen removal units that were routed to an engine or routed to a
vapor recovery system for the entire year, you must only report the
information specified in paragraphs (d)(1)(i) through (v) and (x) of
this section. For acid gas removal units or nitrogen removal units that
were routed to flares for which you calculated natural gas emissions
routed to the flare using continuous parameter monitoring systems as
specified in Sec. 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and
continuous gas composition analyzers or sampling as specified in Sec.
98.233(n)(4), you must report the information specified in paragraphs
(d)(1)(i) through (v) and (x) of this section, as applicable. For acid
gas removal units that were routed to flares for which you calculated
natural gas emissions routed to the flare using the calculation methods
in Sec. 98.233(d) to determine natural gas volumes as specified in
Sec. 98.233(n)(3)(ii)(B), then you must report the information
specified in paragraphs (d)(1)(i) through (vii) and (x) of this section
and paragraph (d)(2) of this section.
(1) You must report the information specified in paragraphs
(d)(1)(i) through (xi) of this section for each acid gas removal unit
or nitrogen removal unit, as applicable.
(i) A unique name or ID number for the acid gas removal unit or
nitrogen removal unit. For the onshore petroleum and natural gas
production and the onshore petroleum and natural gas gathering and
boosting industry segments, a different name or ID may be used for a
single acid gas removal unit or nitrogen removal unit for each location
it operates at in a given year.
(ii) Whether the acid gas removal unit or nitrogen removal unit
vent was routed to a flare. If so, report the information specified in
paragraphs (d)(1)(ii)(A) through (D) of this section for acid gas
removal units and the information specified in paragraph (d)(1)(ii)(B)
of this section for nitrogen removal units.
(A) Indicate whether you calculated natural gas emissions routed to
the flare using continuous parameter monitoring systems as specified in
Sec. 98.233(n)(3)(i) and (ii)(A) and continuous gas composition
analyzers or sampling as specified in Sec. 98.233(n)(4), or you
calculated natural gas emissions routed to the flare using the
calculation methods in Sec. 98.233(d) as specified in Sec.
98.233(n)(3)(ii)(B).
(B) Indicate whether natural gas emissions were routed to a flare
for the entire year or only part of the year.
(C) The unique name or ID for the flare stack as specified in
paragraph (n)(1) of this section to which the acid gas removal unit or
nitrogen removal unit vent was routed.
(D) The unique ID for the stream routed to the flare as specified
in paragraph (n)(3) of this section from the acid gas removal unit or
nitrogen removal unit vent.
(iii) Whether the acid gas removal unit or nitrogen removal unit
vent was routed to combustion, and if so, whether
[[Page 42299]]
it was routed for the entire year or only part of the year.
(iv) Whether the acid gas removal unit or nitrogen removal unit
vent was routed to a vapor recovery system, and if so, whether it was
routed for the entire year or only part of the year.
(v) Total feed rate entering the acid gas removal unit or nitrogen
removal unit, using a meter or engineering estimate based on process
knowledge or best available data, in million standard cubic feet per
year.
(vi) If the acid gas removal unit or nitrogen removal unit was
routed to a flare, to combustion, or to vapor recovery for only part of
the year, the feed rate entering the acid gas removal unit or nitrogen
removal unit during the portion of the year that the emissions were
vented directly to the atmosphere, using a meter or engineering
estimate based on process knowledge or best available data, in million
standard cubic feet per year.
(vii) The calculation method used to calculate CO2 and
CH4 emissions from the acid gas removal unit or to calculate
CH4 emissions from the nitrogen removal unit, as specified
in Sec. 98.233(d).
(viii) Annual CO2 emissions, in metric tons
CO2, vented directly to the atmosphere from the acid gas
removal unit, calculated using any one of the calculation methods
specified in Sec. 98.233(d) and as specified in Sec. 98.233(d)(11)
and (12).
(ix) Annual CH4 emissions, in metric tons
CH4, vented directly to the atmosphere from the acid gas
removal unit or nitrogen removal unit, calculated using any one of the
calculation methods specified in Sec. 98.233(d) and as specified in
Sec. 98.233(d)(11) and (12).
(x) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(2) You must report information specified in paragraphs (d)(2)(i)
through (iii) of this section, applicable to the calculation method
reported in paragraph (d)(1)(iii) of this section, for each acid gas
removal unit or nitrogen removal unit.
(i) If you used Calculation Method 1 or Calculation Method 2 as
specified in Sec. 98.233(d) to calculate CO2 emissions from
the acid gas removal unit and Calculation Method 2 as specified in
Sec. 98.233(d) to calculate CH4 emissions from the acid gas
removal unit or nitrogen removal unit, then you must report the
information specified in paragraphs (d)(2)(i)(A) through (C) of this
section, as applicable.
(A) Annual average volumetric fraction of CO2 in the
vent gas exiting the acid gas removal unit.
(B) Annual average volumetric fraction of CH4 in the
vent gas exiting the acid gas removal unit or nitrogen removal unit.
(C) Annual volume of gas vented from the acid gas removal unit or
nitrogen removal unit, in cubic feet.
(D) The temperature that corresponds to the reported annual volume
of gas vented from the unit, in degrees Fahrenheit. If the annual
volume of gas vented is reported in actual cubic feet, report the
actual temperature; if it is reported in standard cubic feet, report 60
[deg]F.
(E) The pressure that corresponds to the reported annual volume of
gas vented from the unit, in pounds per square inch absolute. If the
annual volume of gas vented is reported in actual cubic feet, report
the actual pressure; if it is reported in standard cubic feet, report
14.7 psia.
(ii) If you used Calculation Method 3 as specified in Sec.
98.233(d) to calculate CO2 or CH4 emissions from
the acid gas removal unit or nitrogen removal unit, then you must
report the information specified in paragraphs (d)(2)(ii)(A) through
(M) of this section, as applicable depending on the equation used.
(A) Indicate which equation was used (equation W-4A, W-4B, or W-4C
to Sec. 98.233).
(B) Annual average volumetric fraction of CO2 in the
natural gas flowing out of the acid gas removal unit, as specified in
equation W-4A, equation W-4B, or equation W-4C to Sec. 98.233.
(C) Annual average volumetric fraction of CO2 content in
natural gas flowing into the acid gas removal unit, as specified in
equation W-4A, equation W-4B, or equation W-4C to Sec. 98.233.
(D) Annual average volumetric fraction of CO2 in the
vent gas exiting the acid gas removal unit, as specified in equation W-
4A or equation W-4B to Sec. 98.233.
(E) Annual average volumetric fraction of CH4 in the
natural gas flowing out of the acid gas removal unit or nitrogen
removal unit, as specified in equation W-4A, equation W-4B, or equation
W-4C to Sec. 98.233.
(F) Annual average volumetric fraction of CH4 content in
natural gas flowing into the acid gas removal unit or nitrogen removal
unit, as specified in equation W-4A, equation W-4B, or equation W-4C to
Sec. 98.233.
(G) Annual average volumetric fraction of CH4 in the
vent gas exiting the acid gas removal unit or nitrogen removal unit, as
specified in equation W-4A or equation W-4B to Sec. 98.233.
(H) The total annual volume of natural gas flow into the acid gas
removal unit or nitrogen removal unit, as specified in equation W-4A or
equation W-4C to Sec. 98.233, in cubic feet at actual conditions.
(I) The temperature that corresponds to the reported total annual
volume of natural gas flow into the acid gas removal unit or nitrogen
removal unit, as specified in equation W-4A or equation W-4C to Sec.
98.233, in degrees Fahrenheit. If the total annual volume of natural
gas flow is reported in actual cubic feet, report the actual
temperature; if it is reported in standard cubic feet, report 60
[deg]F.
(J) The pressure that corresponds to the reported total annual
volume of natural gas flow into the acid gas removal unit or nitrogen
removal unit, as specified in equation W-4A or equation W-4C to Sec.
98.233, in pounds per square inch absolute. If the total annual volume
of natural gas flow is reported in actual cubic feet, report the actual
pressure; if it is reported in standard cubic feet, report 14.7 psia.
(K) The total annual volume of natural gas flow out of the acid gas
removal unit or nitrogen removal unit, as specified in equation W-4B or
equation W-4C to Sec. 98.233, in cubic feet at actual conditions.
(L) The temperature that corresponds to the reported total annual
volume of natural gas flow out of the acid gas removal unit or nitrogen
removal unit, as specified in equation W-4B or equation W-4C to Sec.
98.233, in degrees Fahrenheit. If the total annual volume of natural
gas flow is reported in actual cubic feet, report the actual
temperature; if it is reported in standard cubic feet, report 60
[deg]F.
(M) The pressure that corresponds to the reported total annual
volume of natural gas flow out of the acid gas removal unit or nitrogen
removal unit, as specified in equation W-4B or equation W-4C to Sec.
98.233, in pounds per square inch absolute. If the total annual volume
of natural gas flow is reported in actual cubic feet, report the actual
pressure; if it is reported in standard cubic feet, report 14.7 psia.
(iii) If you used Calculation Method 4 as specified in Sec.
98.233(d) to calculate CO2 or CH4 emissions from
the acid gas removal unit or nitrogen removal unit, then you must
report the information specified in paragraphs (d)(2)(iii)(A) through
(O) of this section, as applicable to the simulation software package
used.
(A) The name of the simulation software package used.
[[Page 42300]]
(B) Annual average natural gas feed temperature, in degrees
Fahrenheit.
(C) Annual average natural gas feed pressure, in pounds per square
inch.
(D) Annual average natural gas feed flow rate, in standard cubic
feet per minute.
(E) Annual average acid gas content of the feed natural gas, in
mole percent.
(F) Annual average acid gas content of the outlet natural gas, in
mole percent.
(G) Annual average methane content of the feed natural gas, in mole
percent.
(H) Annual average methane content of the outlet natural gas, in
mole percent.
(I) Total annual unit operating hours, excluding downtime for
maintenance or standby, in hours per year.
(J) Annual average exit temperature of the natural gas, in degrees
Fahrenheit.
(K) Annual average solvent pressure, in pounds per square inch.
(L) Annual average solvent temperature, in degrees Fahrenheit.
(M) Annual average solvent circulation rate, in gallons per minute.
(N) Solvent type used for the majority of the year, from one of the
following options: SelexolTM, Rectisol[supreg],
PurisolTM, Fluor SolventSM,
BenfieldTM, 20 wt% MEA, 30 wt% MEA, 40 wt% MDEA, 50 wt%
MDEA, and other (specify).
(O) If a vent meter is installed and you elected to use Calculation
Method 4 for an AGR, report the information in paragraphs
(d)(2)(iii)(O)(1) through (3) of this section.
(1) The total annual volume of vent gas flowing out of the AGR in
cubic feet per year at actual conditions as determined by flow meter
(``Va,meter'' from equation W-4D to Sec. 98.233).
(2) The total annual volume of vent gas flowing out of the AGR in
cubic feet per year at actual conditions as determined the standard
simulation software package (``Va,sim'' from equation W-4D
to Sec. 98.233).
(3) If the calculated percent difference between the vent volumes
(``PD'' from equation W-4D to Sec. 98.233) is greater than 20 percent,
provide a brief description of the reason for the difference.
(e) Dehydrators. You must indicate whether your facility contains
any of the following equipment: Glycol dehydrators for which you
calculated emissions using Calculation Method 1 according to Sec.
98.233(e)(1), glycol dehydrators for which you calculated emissions
using Calculation Method 2 according to Sec. 98.233(e)(2), and
dehydrators that use desiccant. If your facility contains any of the
equipment listed in this paragraph (e), then you must report the
applicable information in paragraphs (e)(1) through (3) of this
section. For dehydrators that were routed to flares for which you
calculated natural gas emissions routed to the flare using continuous
parameter monitoring systems as specified in Sec. 98.233(n)(3)(i) and
(ii)(A) and continuous gas composition analyzers or sampling as
specified in Sec. 98.233(n)(4), you must report the information
specified in paragraph (e)(4) of this section. For dehydrators that
were routed to flares for which you calculated natural gas emissions
routed to the flare using the calculation methods in Sec. 98.233(e) to
determine natural gas volumes as specified in Sec.
98.233(n)(3)(ii)(B), then you must report the applicable information in
paragraphs (e)(1) through (3) of this section and the information
specified in paragraph (e)(4) of this section.
(1) For each glycol dehydrator for which you calculated emissions
using Calculation Method 1 (as specified in Sec. 98.233(e)(1)), you
must report the information specified in paragraphs (e)(1)(i) through
(xviii) of this section for the dehydrator. If reported emissions are
based on more than one simulation, you must report the average of the
simulation inputs.
(i) A unique name or ID number for the dehydrator. For the onshore
petroleum and natural gas production and the onshore petroleum and
natural gas gathering and boosting industry segments, a different name
or ID may be used for a single dehydrator for each location it operates
at in a given year.
(ii) Dehydrator feed natural gas flow rate, in million standard
cubic feet per day.
(iii) Dehydrator feed natural gas water content, in pounds per
million standard cubic feet.
(iv) Dehydrator outlet natural gas water content, in pounds per
million standard cubic feet.
(v) Dehydrator absorbent circulation pump type (e.g., natural gas
pneumatic, air pneumatic, or electric).
(vi) Dehydrator absorbent circulation rate, in gallons per minute.
(vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene
glycol (DEG), or ethylene glycol (EG)).
(viii) Whether stripping gas is used in dehydrator.
(ix) Whether a flash tank separator is used in dehydrator.
(x) Total time the dehydrator is operating during the year, in
hours.
(xi) Temperature of the wet natural gas at the absorber inlet, in
degrees Fahrenheit.
(xii) Pressure of the wet natural gas at the absorber inlet, in
pounds per square inch gauge.
(xiii) Mole fraction of CH4 in wet natural gas.
(xiv) Mole fraction of CO2 in wet natural gas.
(xv) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(xvi) If a flash tank separator is used in the dehydrator, then you
must report the information specified in paragraphs (e)(1)(xvi)(A)
through (F) of this section for the emissions from the flash tank vent,
as applicable. If flash tank emissions were routed to a regenerator
firebox/fire tubes, then you must also report the information specified
in paragraphs (e)(1)(xvi)(G) through (I) of this section for the
combusted emissions from the flash tank vent.
(A) Whether any flash gas emissions are vented directly to the
atmosphere, routed to a flare, routed to the regenerator firebox/fire
tubes, routed to a vapor recovery system, used as stripping gas, or any
combination.
(B) Annual CO2 emissions, in metric tons CO2,
from the flash tank when not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec. 98.233(e)(1) and, if
applicable, (e)(4).
(C) Annual CH4 emissions, in metric tons CH4,
from the flash tank when not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec. 98.233(e)(1) and, if
applicable, paragraph (e)(4) of this section.
(D) Annual CO2 emissions, in metric tons CO2,
that resulted from routing flash gas to a regenerator firebox/fire
tubes, calculated according to Sec. 98.233(e)(5).
(E) Annual CH4 emissions, in metric tons CH4,
that resulted from routing flash gas to a regenerator firebox/fire
tubes, calculated according to Sec. 98.233(e)(5).
(F) Annual N2O emissions, in metric tons N2O,
that resulted from routing flash gas to a regenerator firebox/fire
tubes, calculated according to Sec. 98.233(e)(5).
(G) Indicate whether the regenerator firebox/fire tubes was
monitored with a CEMS. If a CEMS was used, then paragraphs
(e)(1)(xvi)(E) and (F) and (e)(1)(xvi)(H) and (I) of this section do
not apply.
(H) Total volume of gas from the flash tank to a regenerator
firebox/fire tubes, in standard cubic feet.
(I) Average combustion efficiency, expressed as a fraction of gas
from the flash tank combusted by a burning regenerator firebox/fire
tubes.
(xvii) Report the information specified in paragraphs
(e)(1)(xvii)(A) through (F)
[[Page 42301]]
of this section for the emissions from the still vent, as applicable.
If still vent emissions were routed to a regenerator firebox/fire
tubes, then you must also report the information specified in
paragraphs (e)(1)(xvii)(G) through (I) of this section for the
combusted emissions from the still vent.
(A) Whether any still vent emissions are vented directly to the
atmosphere, routed to a flare, routed to the regenerator firebox/fire
tubes, routed to a vapor recovery system, used as stripping gas, or any
combination.
(B) Annual CO2 emissions, in metric tons CO2,
from the still vent when not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec. 98.233(e)(1), and, if
applicable, (e)(4).
(C) Annual CH4 emissions, in metric tons CH4,
from the still vent when not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec. 98.233(e)(1) and, if
applicable, (e)(4).
(D) Annual CO2 emissions, in metric tons CO2,
that resulted from routing still vent gas to a regenerator firebox/fire
tubes, calculated according to Sec. [thinsp]98.233(e)(5).
(E) Annual CH4 emissions, in metric tons CH4,
that resulted from routing still vent gas to a regenerator firebox/fire
tubes, calculated according to Sec. [thinsp]98.233(e)(5).
(F) Annual N2O emissions, in metric tons N2O,
that resulted from routing still vent gas to a regenerator firebox/fire
tubes, calculated according to Sec. [thinsp]98.233(e)(5).
(G) Indicate whether the regenerator firebox/fire tubes were
monitored with a CEMS. If a CEMS was used, then paragraphs
(e)(1)(xvii)(E) and (F) and (e)(1)(xvii)(H) and (I) of this section do
not apply.
(H) Total volume of gas from the still vent to a regenerator
firebox/fire tubes, in standard cubic feet.
(I) Average combustion efficiency, expressed as a fraction of gas
from the still vent combusted by a burning regenerator firebox/fire
tubes.
(xviii) Name of the software package used.
(2) You must report the information specified in paragraphs
(e)(2)(i) through (vi) of this section for all glycol dehydrators with
an annual average daily natural gas throughput greater than 0 million
standard cubic feet per day and less than 0.4 million standard cubic
feet per day for which you calculated emissions using Calculation
Method 2 (as specified in Sec. 98.233(e)(2)) at the facility, well-pad
site, or gathering and boosting site.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) The total number of dehydrators at the facility, well-pad
site, or gathering and boosting site for which you calculated emissions
using Calculation Method 2.
(iii) Whether any dehydrator emissions were routed to a vapor
recovery system. If any dehydrator emissions were routed to a vapor
recovery system, then you must report the total number of dehydrators
at the facility that routed to a vapor recovery system.
(iv) Whether any dehydrator emissions were routed to a control
device that reduces CO2 and/or CH4 emissions
other than a vapor recovery system or a flare or regenerator firebox/
fire tubes. If any dehydrator emissions were routed to a control device
that reduces CO2 and/or CH4 emissions other than
a vapor recovery system or a flare or regenerator firebox/fire tubes,
then you must specify the type of control device(s) and the total
number of dehydrators at the facility that were routed to each type of
control device.
(v) Whether any dehydrator emissions were routed to a flare or
regenerator firebox/fire tubes. If any dehydrator emissions were routed
to a flare or regenerator firebox/fire tubes, then you must report the
information specified in paragraphs (e)(2)(v)(A) through (E) of this
section.
(A) The total number of dehydrators routed to a flare and the total
number of dehydrators routed to regenerator firebox/fire tubes.
(B) Total volume of gas from the flash tank to a regenerator
firebox/fire tubes, in standard cubic feet.
(C) Annual CO2 emissions, in metric tons CO2,
for the dehydrators routed to a regenerator firebox/fire tubes reported
in paragraph (e)(2)(v)(A) of this section, calculated according to
Sec. 98.233(e)(5).
(D) Annual CH4 emissions, in metric tons CH4,
for the dehydrators routed to a regenerator firebox/fire tubes reported
in paragraph (e)(2)(v)(A) of this section, calculated according to
Sec. 98.233(e)(5).
(E) Annual N2O emissions, in metric tons N2O,
for the dehydrators routed to a regenerator firebox/fire tubes reported
in paragraph (e)(2)(v)(A) of this section, calculated according to
Sec. 98.233(e)(5).
(vi) For dehydrator emissions that were not routed to a flare or
regenerator firebox/fire tubes, report the information specified in
paragraphs (e)(2)(vi)(A) and (B) of this section.
(A) Annual CO2 emissions, in metric tons CO2,
for emissions from all dehydrators reported in paragraph (e)(2)(ii) of
this section that were not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec. 98.233(e)(2) and, if
applicable, (e)(4), where emissions are added together for all such
dehydrators.
(B) Annual CH4 emissions, in metric tons CH4,
for emissions from all dehydrators reported in paragraph (e)(2)(ii) of
this section that were not routed to a flare or regenerator firebox/
fire tubes, calculated according to Sec. 98.233(e)(2) and, if
applicable, (e)(4), where emissions are added together for all such
dehydrators.
(3) For dehydrators that use desiccant (as specified in Sec.
98.233(e)(3)), you must report the information specified in paragraphs
(e)(3)(i) through (viii) of this section for each well-pad site,
gathering and boosting site, or facility, as applicable.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) Count of desiccant dehydrators as specified in paragraphs
(e)(3)(ii)(A) and (B) of this section that had one or more openings
during the calendar year at the facility, well-pad site, or gathering
and boosting site for which you calculated emissions using Calculation
Method 3.
(A) The number of opened desiccant dehydrators that used
deliquescing desiccant (e.g., calcium chloride or lithium chloride).
(B) The number of opened desiccant dehydrators that used
regenerative desiccant (e.g., molecular sieves, activated alumina, or
silica gel).
(iii) For desiccant dehydrators at the facility, well-pad site, or
gathering and boosting site identified in paragraph (e)(3)(ii) of this
section, total physical volume of all opened dehydrator vessels.
(iv) For desiccant dehydrators at the facility, well-pad site, or
gathering and boosting site identified in paragraph (e)(3)(ii) of this
section, total number of dehydrator openings in the calendar year.
(v) For desiccant dehydrators at the facility, well-pad site, or
gathering and boosting site identified in paragraph (e)(3)(ii) of this
section, whether any dehydrator emissions were routed to a vapor
recovery system. If any dehydrator emissions were routed to a vapor
recovery system, then you must report the total number of dehydrators
at the facility that routed to a vapor recovery system.
(vi) For desiccant dehydrators at the facility, well-pad, or
gathering and boosting site identified in paragraph (e)(3)(ii) of this
section, whether any
[[Page 42302]]
dehydrator emissions were routed to a control device that reduces
CO2 and/or CH4 emissions other than a vapor
recovery system or a flare or a non-flare combustion unit. If any
dehydrator emissions were routed to a control device that reduces
CO2 and/or CH4 emissions other than a vapor
recovery system or a flare or a non-flare combustion unit, then you
must specify the type of control device(s) and the total number of
dehydrators at the facility that were routed to each type of control
device.
(vii) For desiccant dehydrators at the facility, well-pad site, or
gathering and boosting site identified in paragraph (e)(3)(ii) of this
section, whether any dehydrator emissions were routed to a flare or a
non-flare combustion unit. If any dehydrator emissions were routed to a
flare or a non-flare combustion unit, then you must report the
information specified in paragraphs (e)(3)(vii)(A) through (E) of this
section.
(A) The total number of dehydrators routed to a flare and the total
number of dehydrators routed to a non-flare combustion unit.
(B) Total volume of gas from the flash tank to non-flare combustion
units, in standard cubic feet.
(C) Annual CO2 emissions, in metric tons CO2,
for the dehydrators routed to non-flare combustion units reported in
paragraph (e)(3)(vii)(A) of this section, calculated according to Sec.
98.233(e)(5).
(D) Annual CH4 emissions, in metric tons CH4,
for the dehydrators routed to non-flare combustion units reported in
paragraph (e)(3)(vii)(A) of this section, calculated according to Sec.
98.233(e)(5).
(E) Annual N2O emissions, in metric tons N2O,
for the dehydrators routed to non-flare combustion units reported in
paragraph (e)(3)(vii)(A) of this section, calculated according to Sec.
98.233(e)(5).
(viii) For desiccant dehydrators at the facility, well-pad site, or
gathering and boosting site identified in paragraph (e)(3)(ii) of this
section that were not routed to a flare or a non-flare combustion unit,
report the information specified in paragraphs (e)(3)(viii)(A) and (B)
of this section.
(A) Annual CO2 emissions, in metric tons CO2,
for emissions from all desiccant dehydrators reported under paragraph
(e)(3)(ii) of this section that are not venting to a flare or non-flare
combustion units, calculated according to Sec. 98.233(e)(3) and, if
applicable, (e)(4), and summing for all such dehydrators.
(B) Annual CH4 emissions, in metric tons CH4,
for emissions from all desiccant dehydrators reported in paragraph
(e)(3)(ii) of this section that are not venting to a flare or non-flare
combustion unit, calculated according to Sec. 98.233(e)(3), and, if
applicable, (e)(4), and summing for all such dehydrators.
(4) For dehydrators that were routed to flares, report the
information specified in paragraphs (e)(4)(i) through (iv) of this
section.
(i) Indicate whether you calculated natural gas emissions routed to
the flare using continuous parameter monitoring systems as specified in
Sec. 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas
composition analyzers or sampling as specified in Sec. 98.233(n)(4),
or you calculated natural gas emissions routed to the flare using the
calculation methods in Sec. 98.233(e) as specified in Sec.
98.233(n)(3)(ii)(B).
(ii) Indicate whether natural gas emissions were routed to a flare
for the entire year or only part of the year.
(iii) The unique name or ID for the flare stack as specified in
paragraph (n)(1) of this section to which the dehydrator vent was
routed.
(iv) The unique ID for the stream routed to the flare as specified
in paragraph (n)(3) of this section from the dehydrator.
(f) Liquids unloading. You must indicate whether well venting for
liquids unloading occurs at your facility, and if so, which methods (as
specified in Sec. 98.233(f)) were used to calculate emissions. If your
facility performs well venting for liquids unloading venting to the
atmosphere and uses Calculation Method 1, then you must report the
information specified in paragraph (f)(1) of this section. If the
facility performs liquids unloading venting to the atmosphere and uses
Calculation Method 2 or 3, then you must report the information
specified in paragraph (f)(2) of this section.
(1) For each well for which you used Calculation Method 1 to
calculate natural gas emissions from well venting for liquids unloading
vented to the atmosphere, report the information specified in
paragraphs (f)(1)(i) through (xii) of this section. Report information
separately for wells with plunger lifts and wells without plunger lifts
by unloading type combination (with or without plunger lifts, automated
or manual unloading).
(i) Well ID number.
(ii) Well tubing diameter and pressure group ID.
(iii) Unloading type combination (with or without plunger lifts,
automated or manual unloading).
(iv) [Reserved]
(v) Indicate whether the monitoring period used to determine the
cumulative amount of time venting to the atmosphere was not the full
calendar year.
(vi) Cumulative amount of time the well was vented directly to the
atmosphere (``Tp'' from equation W-7A or W-7B to Sec.
98.233), in hours.
(vii) Cumulative number of unloadings vented directly to the
atmosphere for the well.
(viii) Annual natural gas emissions, in standard cubic feet, from
well venting for liquids unloading, calculated according to Sec.
98.233(f)(1).
(ix) Annual CO2 emissions, in metric tons
CO2, from well venting for liquids unloading, calculated
according to Sec. 98.233(f)(1) and (4).
(x) Annual CH4 emissions, in metric tons CH4,
from well venting for liquids unloading, calculated according to Sec.
98.233(f)(1) and (4).
(xi) For each well tubing diameter group and pressure group
combination, you must report the information specified in paragraphs
(f)(1)(xi)(A) through (F) of this section for each individual well not
using a plunger lift that was tested during the year.
(A) Well ID number of tested well.
(B) Casing pressure, in pounds per square inch absolute.
(C) Internal casing diameter, in inches.
(D) Measured depth of the well, in feet.
(E) Average flow rate of the well venting over the duration of the
liquids unloading, in standard cubic feet per hour.
(F) Unloading type (automated or manual).
(xii) For each well tubing diameter group and pressure group
combination, you must report the information specified in paragraphs
(f)(1)(xii)(A) through (F) of this section for each individual well
using a plunger lift that was tested during the year.
(A) Well ID number.
(B) The tubing pressure, in pounds per square inch absolute.
(C) The internal tubing diameter, in inches.
(D) Measured depth of the well, in feet.
(E) Average flow rate of the well venting over the duration of the
liquids unloading, in standard cubic feet per hour.
(F) Unloading type (automated or manual).
(2) For each well for which you used Calculation Method 2 or 3 (as
specified in Sec. 93.233(f)) to calculate natural gas emissions from
well venting for liquids unloading vented to the atmosphere, you must
report the information in paragraphs (f)(2)(i) through (xii) of this
section. Report information separately
[[Page 42303]]
for each calculation method and unloading type combination (with or
without plunger lifts, automated or manual unloadings).
(i) Well ID number.
(ii) Calculation method.
(iii) Unloading type combination (with or without plunger lifts,
automated or manual unloadings).
(iv) [Reserved]
(v) Cumulative number of unloadings venting directly to the
atmosphere for the well.
(vi) Annual natural gas emissions, in standard cubic feet, from
well venting for liquids unloading, calculated according to Sec.
98.233(f)(2) or (3), as applicable.
(vii) Annual CO2 emissions, in metric tons
CO2, from well venting for liquids unloading, calculated
according to Sec. 98.233(f)(2) or (3), as applicable, and Sec.
98.233(f)(4).
(viii) Annual CH4 emissions, in metric tons
CH4, from well venting for liquids unloading, calculated
according to Sec. 98.233(f)(2) or (3), as applicable, and Sec.
98.233(f)(4).
(ix) Average flow-line rate of gas (average of ``SFRp''
from equation W-8 or W-9 to Sec. 98.233, as applicable), at standard
conditions in cubic feet per hour.
(x) Cumulative amount of time that wells were left open to the
atmosphere during unloading events (sum of ``HRp,q'' from
equation W-8 or W-9 to Sec. 98.233, as applicable), in hours.
(xi) For each well without plunger lifts, the information in
paragraphs (f)(2)(xi)(A) through (C) of this section.
(A) Internal casing diameter (``CDp'' from equation W-8
to Sec. 98.233), in inches.
(B) Well depth (``WDp'' from equation W-8 to Sec.
98.233), in feet.
(C) Shut-in pressure, surface pressure, or casing pressure
(``SPp'' from equation W-8 to Sec. 98.233), in pounds per
square inch absolute.
(xii) For each well with plunger lifts, the information in
paragraphs (f)(2)(xiii)(A) through (C) of this section.
(A) Internal tubing diameter (``TDp'' from equation W-9
to Sec. 98.233), in inches.
(B) Tubing depth (``WDp'' from equation W-9 to Sec.
98.233), in feet.
(C) Flow line pressure (``SPp'' from equation W-9 to
Sec. 98.233), in pounds per square inch absolute.
(g) Completions and workovers with hydraulic fracturing. You must
indicate whether your facility had any well completions or workovers
with hydraulic fracturing during the calendar year. If your facility
had well completions or workovers with hydraulic fracturing during the
calendar year that vented directly to the atmosphere, then you must
report information specified in paragraphs (g)(1) through (10) of this
section, for each well. If your facility had well completions or
workovers with hydraulic fracturing during the year that routed to
flares and you calculated natural gas emissions routed to the flare
using continuous parameter monitoring systems as specified in Sec.
98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas composition
analyzers or sampling as specified in Sec. 98.233(n)(4), then you must
report the information specified in paragraphs (g)(1) through (3) and
(10) of this section, for each well. If your facility had well
completions or workovers with hydraulic fracturing during the year that
routed to flares and you calculated natural gas emissions routed to the
flare using the calculation methods in Sec. 98.233(g) to determine
natural gas volumes as specified in Sec. 98.233(n)(3)(ii)(B), then you
must report the information specified in paragraphs (g)(1) through (6)
and (10) of this section, for each well. Report information separately
for completions and workovers.
(1) Well ID number.
(2) Well type combination (horizontal or vertical, flared or
vented, reduced emission completion or not a reduced emission
completion, gas well or oil well).
(3) Number of completions or workovers for each well.
(4) Calculation method used.
(5) If you used equation W-10A to Sec. 98.233 to calculate annual
volumetric total gas emissions, then you must report the information
specified in paragraphs (g)(5)(i) through (v) of this section.
(i) Cumulative gas flowback time, in hours, for all completions or
workovers at the well from when gas is first detected until sufficient
quantities are present to enable separation, and the cumulative
flowback time, in hours, after sufficient quantities of gas are present
to enable separation (sum of ``Tp,i'' and sum of
``Tp,s'' values used in equation W-10A to Sec. 98.233). You
may delay the reporting of this data element if you indicate in the
annual report that the well is a wildcat well or delineation well. If
you elect to delay reporting of this data element, you must report by
the date specified in paragraph (cc) of this section the total number
of hours of flowback from the well during completions or workovers.
(ii) If the well is a measured well for the sub-basin and well-type
combination, the flowback rate, in standard cubic feet per hour
(average of ``FRs,p'' values used in equation W-12A to Sec.
98.233). You may delay the reporting of this data element if you
indicate in the annual report that the well is a wildcat well or
delineation well. If you elect to delay reporting of this data element,
you must report by the date specified in paragraph (cc) of this section
the measured flowback rate(s) during well completion or workover for
the well.
(iii) If you used equation W-12C to Sec. 98.233 to calculate the
average gas production rate for an oil well, then you must report the
information specified in paragraphs (g)(5)(iii)(A) and (B) of this
section.
(A) Gas to oil ratio for the well in standard cubic feet of gas per
barrel of oil (``GORp'' in equation W-12C to Sec. 98.233).
You may delay the reporting of this data element if you indicate in the
annual report that the well is a wildcat well or delineation well. If
you elect to delay reporting of this data element, you must report by
the date specified in paragraph (cc) of this section the gas to oil
ratio for the well.
(B) Volume of oil produced during the first 30 days of production
after completion of the newly drilled well or well workover using
hydraulic fracturing, in barrels (``Vp'' in equation W-12C
to Sec. 98.233). You may delay the reporting of this data element if
you indicate in the annual report that the well is a wildcat well or
delineation well. If you elect to delay reporting of this data element,
you must report by the date specified in paragraph (cc) of this section
the volume of oil produced during the first 30 days of production after
well completion or workover for the well.
(iv) Whether the flow rate during the initial flowback period was
determined using:
(A) A recording flow meter (digital or analog) installed on the
vent line, downstream of a separator.
(B) A multiphase flow meter upstream of the separator.
(C) Equation W-11A or W-11B to Sec. 98.233.
(v) Whether the flow rate when sufficient quantities are present to
enable separation was determined using:
(A) A recording flow meter (digital or analog) installed on the
vent line, downstream of a separator.
(B) Equation W-11A or W-11B to Sec. 98.233.
(6) If you used equation W-10B to Sec. 98.233 to calculate annual
volumetric total gas emissions, then you must report the information
specified in paragraphs (g)(6)(i) through (iii) of this section.
[[Page 42304]]
(i) Vented natural gas volume, in standard cubic feet
(``FVs,p'' in equation W-10B to Sec. 98.233).
(ii) Flow rate at the beginning of the period of time when
sufficient quantities of gas are present to enable separation, in
standard cubic feet per hour (``FRp,i'' in equation W-10B to
Sec. 98.233).
(iii) If a multiphase flowmeter was used to measure the flow rate
during the initial flowback period, report the average flow rate
measured by the multiphase flow meter from the initiation of flowback
to the beginning of the period of time when sufficient quantities of
gas present to enable separation in standard cubic feet per hour.
(7) Annual gas emissions, in standard cubic feet
(``Es,n'' in equation W-10A or W-10B to Sec. 98.233).
(8) Annual CO2 emissions, in metric tons CO2.
(9) Annual CH4 emissions, in metric tons CH4.
(10) Indicate whether natural gas emissions from completion(s) or
workover(s) with hydraulic fracturing were routed to a flare and
emissions are reported according to paragraph (n) of this section, and
if so, provide the information specified in paragraphs (g)(10)(i)
through (iv) of this section.
(i) Indicate whether you calculated natural gas emissions routed to
the flare using continuous parameter monitoring systems as specified in
Sec. 98.233(n)(3)(i) and (n)(3)(ii)(A) and continuous gas composition
analyzers or sampling as specified in Sec. 98.233(n)(4), or you
calculated natural gas emissions routed to the flare using the
calculation methods in Sec. 98.233(g) as specified in Sec.
98.233(n)(3)(ii)(B).
(ii) Indicate whether natural gas emissions were routed to a flare
for the entire year or only part of the year.
(iii) The unique name or ID for the flare stack as specified in
paragraph (n)(1) of this section.
(iv) The unique ID for each stream routed to the flare as specified
in paragraph (n)(3) of this section.
(h) Completions and workovers without hydraulic fracturing. You
must indicate whether the facility had any gas well completions without
hydraulic fracturing or any gas well workovers without hydraulic
fracturing, and if the activities occurred with or without flaring. If
the facility had gas well completions or workovers without hydraulic
fracturing, then you must report the information specified in
paragraphs (h)(1) through (4) of this section, as applicable.
(1) For each well with one or more gas well completions without
hydraulic fracturing and without flaring, report the information
specified in paragraphs (h)(1)(i) through (vi) of this section.
(i) Well ID number.
(ii) Number of well completions that vented gas directly to the
atmosphere without flaring.
(iii) Total number of hours that gas vented directly to the
atmosphere during venting for all completions without hydraulic
fracturing (``Tp'' for completions that vented directly to
the atmosphere as used in equation W-13B to Sec. 98.233). You may
delay reporting of this data element if you indicate in the annual
report that the well is a wildcat well or delineation well. If you
elect to delay reporting of this data element, you must report by the
date specified in paragraph (cc) of this section the total number of
hours that gas vented directly to the atmosphere during completions for
the well.
(iv) Average daily gas production rate for all completions without
hydraulic fracturing without flaring, in standard cubic feet per hour
(``Vp'' in equation W-13B to Sec. 98.233). You may delay
reporting of this data element if you indicate in the annual report
that the well is a wildcat well or delineation well. If you elect to
delay reporting of this data element, you must report by the date
specified in paragraph (cc) of this section the measured average daily
gas production rate during completions for the well.
(v) Annual CO2 emissions, in metric tons CO2,
that resulted from completions venting gas directly to the atmosphere
(``Es,p'' from equation W-13B to Sec. 98.233 for
completions that vented directly to the atmosphere, converted to mass
emissions according to Sec. 98.233(h)(1)).
(vi) Annual CH4 emissions, in metric tons
CH4, that resulted from completions venting gas directly to
the atmosphere (``Es,p'' from equation W-13B to Sec. 98.233
for completions that vented directly to the atmosphere, converted to
mass emissions according to Sec. 98.233(h)(1)).
(2) If your facility had well completions without hydraulic
fracturing and with flaring during the year and you calculated natural
gas emissions routed to the flare using continuous parameter monitoring
systems as specified in Sec. 98.233(n)(3)(i) and (ii)(A) and
continuous gas composition analyzers or sampling as specified in Sec.
98.233(n)(4), then you must report the information specified in
paragraphs (h)(2)(i) through (ii) and (viii) of this section, for each
well. If your facility had well completions without hydraulic
fracturing during the year that routed to flares and you calculated
natural gas emissions routed to the flare using the calculation methods
in Sec. 98.233(h) to determine natural gas volumes as specified in
Sec. 98.233(n)(3)(ii)(B), then you must report the information
specified in paragraphs (h)(2)(i) through (iv) and (viii) of this
section, for each well.
(i) Well ID number.
(ii) Number of well completions that flared gas.
(iii) Total number of hours that gas routed to a flare during
venting for all completions without hydraulic fracturing
(``Tp'' for completions that vented to a flare from equation
W-13B to Sec. 98.233). You may delay reporting of this data element if
you indicate in the annual report that the well is a wildcat well or
delineation well. If you elect to delay reporting of this data element,
you must report by the date specified in paragraph (cc) of this section
the total number of hours that gas vented to the flare during
completions for the well.
(iv) Average daily gas production rate for all completions without
hydraulic fracturing with flaring, in standard cubic feet per hour
(``Vp'' from equation W-13B to Sec. 98.233). You may delay
reporting of this data element if you indicate in the annual report
that the well is a wildcat well or delineation well. If you elect to
delay reporting of this data element, you must report by the date
specified in paragraph (cc) of this section the measured average daily
gas production rate during completions for the well.
(v) [Reserved]
(vi) [Reserved]
(vii) [Reserved]
(viii) Report the information specified in paragraphs
(h)(2)(viii)(A) through (D).
(A) Indicate whether you calculated natural gas emissions routed to
the flare using continuous parameter monitoring systems as specified in
Sec. 98.233(n)(3)(i) and (ii)(A) and continuous gas composition
analyzers or sampling as specified in Sec. 98.233(n)(4), or you
calculated natural gas emissions routed to the flare using the
calculation methods in Sec. 98.233(h) as specified in Sec.
98.233(n)(3)(ii)(B).
(B) Indicate whether natural gas emissions were routed to a flare
for the entire year or only part of the year.
(C) The unique name or ID for the flare stack as specified in
paragraph (n)(1) of this section.
(D) The unique ID for each stream routed to the flare as specified
in paragraph (n)(3) of this section.
(3) For each well with one or more gas well workovers without
hydraulic fracturing and without flaring, report the information
specified in paragraphs (h)(3)(i) through (iv) of this section.
[[Page 42305]]
(i) Well ID number.
(ii) Number of workovers that vented gas to the atmosphere without
flaring.
(iii) Annual CO2 emissions, in metric tons
CO2 per year, that resulted from workovers venting gas
directly to the atmosphere (``Es,wo'' in equation W-13A to
Sec. 98.233 for workovers that vented directly to the atmosphere,
converted to mass emissions as specified in Sec. 98.233(h)(1)).
(iv) Annual CH4 emissions, in metric tons CH4
per year, that resulted from workovers venting gas directly to the
atmosphere (``Es,wo'' in equation W-13A to Sec. 98.233 for
workovers that vented directly to the atmosphere, converted to mass
emissions as specified in Sec. 98.233(h)(1)).
(4) If your facility had well workovers without hydraulic
fracturing and with flaring during the year and you calculated natural
gas emissions routed to the flare using continuous parameter monitoring
systems as specified in Sec. 98.233(n)(3)(i) and (ii)(A) and
continuous gas composition analyzers or sampling as specified in Sec.
98.233(n)(4), then you must report the information specified in
paragraphs (h)(4)(i) through (ii) and (vi) of this section, for each
well. If your facility had well workovers without hydraulic fracturing
during the year that routed to flares and you calculated natural gas
emissions routed to the flare using the calculation methods in Sec.
98.233(h) to determine natural gas volumes as specified in Sec.
98.233(n)(3)(ii)(B), then you must report the information specified in
paragraphs (h)(4)(i) through (ii) and (vi) of this section, for each
well.
(i) Well ID number.
(ii) Number of workovers that flared gas.
(iii) [Reserved]
(iv) [Reserved]
(v) [Reserved]
(vi) Report the information specified in paragraphs (h)(4)(vi)(A)
through (D).
(A) Indicate whether you calculated natural gas emissions routed to
the flare using continuous parameter monitoring systems as specified in
Sec. 98.233(n)(3)(i) and (ii)(A) and continuous gas composition
analyzers or sampling as specified in Sec. 98.233(n)(4), or you
calculated natural gas emissions routed to the flare using the
calculation methods in Sec. 98.233(h) as specified in Sec.
98.233(n)(3)(ii)(B).
(B) Indicate whether natural gas emissions were routed to a flare
for the entire year or only part of the year.
(C) The unique name or ID for the flare stack as specified in
paragraph (n)(1) of this section.
(D) The unique ID for each stream routed to the flare as specified
in paragraph (n)(3) of this section.
(i) Blowdown vent stacks. You must indicate whether your facility
has blowdown vent stacks. If your facility has blowdown vent stacks,
then you must report whether emissions were calculated by equipment or
event type or by using flow meters or a combination of both. If you
calculated emissions by equipment or event type for any blowdown vent
stacks, then you must report the information specified in paragraph
(i)(1) of this section considering, in aggregate, all blowdown vent
stacks for which emissions were calculated by equipment or event type.
If you calculated emissions using flow meters for any blowdown vent
stacks, then you must report the information specified in paragraph
(i)(2) of this section considering, in aggregate, all blowdown vent
stacks for which emissions were calculated using flow meters. For the
onshore natural gas transmission pipeline segment, you must also report
the information in paragraph (i)(3) of this section. You must report
the information specified in paragraphs (i)(1) through (3) of this
section, as applicable, for each well-pad site (for onshore
production), each gathering and boosting site (for onshore petroleum
and natural gas gathering and boosting), or facility (for all other
applicable industry segments).
(1) Report by equipment or event type. If you calculated emissions
from blowdown vent stacks by the seven categories listed in Sec.
98.233(i)(2)(iv)(A) for onshore petroleum and natural gas production,
onshore natural gas processing, onshore natural gas transmission
compression, underground natural gas storage, LNG storage, LNG import
and export equipment, or onshore petroleum and natural gas gathering
and boosting industry segments, then you must report the information
specified in paragraphs (i)(1)(i) through (v) of this section, as
applicable. If a blowdown event resulted in emissions from multiple
equipment or event types, and the emissions cannot be apportioned to
the different equipment or event types, then you may report the
information in paragraphs (i)(1)(ii) through (v) of this section for
the equipment or event type that represented the largest portion of the
emissions for the blowdown event. For the onshore petroleum and natural
gas production and onshore petroleum and natural gas gathering and
boosting industry segments, if a blowdown event is not directly
associated with a specific well-pad site or gathering and boosting site
(e.g., a mid-field pipeline blowdown) or could be associated with
multiple well-pad or gathering and boosting sites, then you may report
the information in paragraphs (i)(1)(i) through (v) of this section for
either the nearest well-pad site or gathering and boosting site
upstream from the blowdown event or the well-pad site or gathering and
boosting site that represented the largest portion of the emissions for
the blowdown event, as appropriate. If you calculated emissions from
blowdown vent stacks by the eight categories listed in Sec.
98.233(i)(2)(iv)(B) for the natural gas distribution or onshore natural
gas transmission pipeline industry segments, then you must report the
information specified in paragraphs (i)(1)(ii) through (v) of this
section, as applicable. If a blowdown event resulted in emissions from
multiple equipment or event types, and the emissions cannot be
apportioned to the different equipment or event types, then you may
report the information in paragraphs (i)(1)(ii) through (v) of this
section for the equipment or event type that represented the largest
portion of the emissions for the blowdown event.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) Equipment or event type. For the onshore petroleum and natural
gas production, onshore natural gas processing, onshore natural gas
transmission compression, underground natural gas storage, LNG storage,
LNG import and export equipment, or onshore petroleum and natural gas
gathering and boosting industry segments, use the seven categories
listed in Sec. 98.233(i)(2)(iv)(A). For the natural gas distribution
or onshore natural gas transmission pipeline industry segments, use the
eight categories listed in Sec. 98.233(i)(2)(iv)(B).
(iii) Total number of blowdowns in the calendar year for the
equipment or event type (the sum of equation variable ``N'' from
equation W-14A or equation W-14B to Sec. 98.233, for all unique
physical volumes for the equipment or event type).
(iv) Annual CO2 emissions for the equipment or event
type, in metric tons CO2, calculated according to Sec.
98.233(i)(2)(iii).
(v) Annual CH4 emissions for the equipment or event
type, in metric tons CH4, calculated according to Sec.
98.233(i)(2)(iii).
(2) Report by flow meter. If you elect to calculate emissions from
blowdown vent stacks by using a flow meter according to Sec.
98.233(i)(3), then you
[[Page 42306]]
must report the information specified in paragraphs (i)(2)(i) through
(iii) of this section, as applicable. For the onshore petroleum and
natural gas production and onshore petroleum and natural gas gathering
and boosting industry segments, if a blowdown event is not directly
associated with a specific well-pad site or gathering and boosting site
(e.g., a mid-field pipeline blowdown) or could be associated with
multiple well-pad sites or gathering and boosting sites, then you may
report the information in paragraphs (i)(2)(i) through (iii) of this
section for either the nearest well-pad site or gathering and boosting
site upstream from the blowdown event or the well-pad site or gathering
and boosting site that represented the largest portion of the emissions
for the blowdown event, as appropriate.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) Annual CO2 emissions from all blowdown vent stacks
at the facility, well-pad site, or gathering and boosting site for
which emissions were calculated using flow meters, in metric tons
CO2 (the sum of all CO2 mass emission values
calculated according to Sec. 98.233(i)(3), for all flow meters).
(iii) Annual CH4 emissions from all blowdown vent stacks
at the facility, well-pad site, or gathering and boosting site for
which emissions were calculated using flow meters, in metric tons
CH4, (the sum of all CH4 mass emission values
calculated according to Sec. 98.233(i)(3), for all flow meters).
(3) Onshore natural gas transmission pipeline segment. Report the
information in paragraphs (i)(3)(i) through (iii) of this section for
each state.
(i) Annual CO2 emissions in metric tons CO2.
(ii) Annual CH4 emissions in metric tons CH4.
(iii) Annual number of blowdown events.
(j) Hydrocarbon liquids and produced water storage tanks. You must
indicate whether your facility sends hydrocarbon produced liquids and/
or produced water to atmospheric pressure storage tanks. If your
facility sends hydrocarbon produced liquids and/or produced water to
atmospheric pressure storage tanks, then you must indicate which
Calculation Method(s) you used to calculate GHG emissions, and you must
report the information specified in paragraphs (j)(1) and (2) of this
section, as applicable. If you used Calculation Method 1 or Calculation
Method 2 of Sec. 98.233(j), and any atmospheric pressure storage tanks
were observed to have malfunctioning dump valves during the calendar
year, then you must indicate that dump valves were malfunctioning and
must report the information specified in paragraph (j)(3) of this
section. For hydrocarbon liquids and produced water storage tanks that
were routed to flares for which you calculated natural gas emissions
routed to the flare using continuous parameter monitoring systems as
specified in Sec. 98.233(n)(3)(i) and (ii)(A) and continuous gas
composition analyzers or sampling as specified in Sec. 98.233(n)(4),
you must report the information specified in paragraph (j)(4) of this
section. For hydrocarbon liquids and produced water storage tanks that
were routed to flares for which you calculated natural gas emissions
routed to the flare using the calculation methods in Sec. 98.233(j) to
determine natural gas volumes as specified in Sec.
98.233(n)(3)(ii)(B), then you must report the applicable information in
paragraphs (j)(1) through (3) of this section and the information
specified in paragraph (j)(4) of this section.
(1) If you used Calculation Method 1 or Calculation Method 2 of
Sec. 98.233(j) to calculate GHG emissions, then you must report the
information specified in paragraphs (j)(1)(i) through (xvi) of this
section for each well-pad site (for onshore petroleum and natural gas
production), gathering and boosting site (for onshore petroleum and
natural gas gathering and boosting), or facility (for all other
applicable industry segments) and by calculation method and liquid
type, as applicable. Onshore petroleum and natural gas gathering and
boosting and onshore natural gas processing facilities do not report
the information specified in paragraph (j)(1)(ix) of this section.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) Calculation method used, and name of the software package used
if using Calculation Method 1.
(iii) The total annual hydrocarbon liquids or produced water volume
from gas-liquid separators and direct from wells or non-separator
equipment that is sent to applicable atmospheric pressure storage
tanks, in barrels. You may delay reporting of this data element for
onshore production if you indicate in the annual report that wildcat
wells and/or delineation wells are the only wells at the well-pad site
with hydrocarbon liquids or produced water production flowing to gas-
liquid separators or direct to atmospheric pressure storage tanks for
which you used the same calculation method. If you elect to delay
reporting of this data element, you must report by the date specified
in paragraph (cc) of this section the total volume of hydrocarbon
liquids or produced water from all wells and the well ID number(s) for
the well(s) included in this volume.
(iv) The average well, gas-liquid separator, or non-separator
equipment temperature, in degrees Fahrenheit.
(v) The average well, gas-liquid separator, or non-separator
equipment pressure, in pounds per square inch gauge.
(vi) For atmospheric pressure storage tanks receiving hydrocarbon
liquids, the average sales oil or stabilized hydrocarbon liquids API
gravity, in degrees.
(vii) If you used Calculation Method 1 of Sec. 98.233(j) to
calculate GHG emissions for atmospheric pressure storage tanks
receiving hydrocarbon liquids, the flow-weighted average concentration
(mole fraction) of CO2 in flash gas from atmospheric
pressure storage tanks (calculated as the sum of all products of the
concentration of CO2 in the flash gas for each storage tank
times the total quantity of flash gas for that storage tank, divided by
the sum of all flash gas emissions from storage tanks).
(viii) If you used Calculation Method 1 of Sec. 98.233(j) to
calculate GHG emissions for atmospheric pressure storage tanks
receiving hydrocarbon liquids, the flow-weighted average concentration
(mole fraction) of CH4 in flash gas from atmospheric
pressure storage tanks (calculated as the sum of all products of the
concentration of CH4 in the flash gas for each storage tank
times the total quantity of flash gas for that storage tank, divided by
the sum of all flash gas emissions from storage tanks).
(ix) The number of wells sending hydrocarbon liquids or produced
water to gas-liquid separators or directly to atmospheric pressure
storage tanks.
(x) Count of atmospheric pressure storage tanks specified in
paragraphs (j)(1)(x)(A) through (F) of this section.
(A) The number of fixed roof atmospheric pressure storage tanks.
(B) The number of floating roof atmospheric pressure storage tanks.
(C) The number of atmospheric pressure storage tanks that vented
gas directly to the atmosphere and did not control emissions using a
vapor recovery system or one or more flares at any point during the
reporting year.
[[Page 42307]]
(D) The number of atmospheric pressure storage tanks that routed
emissions to a vapor recovery system at any point during the reporting
year.
(E) The number of atmospheric pressure storage tanks that routed
emissions to one or more flares at any point during the reporting year.
(F) The number of atmospheric pressure storage tanks in paragraph
(j)(1)(x)(D) or (E) of this section that had an open or not properly
seated thief hatch at some point during the year while the storage tank
was also routing emissions to a vapor recovery system and/or a flare.
(xi) For atmospheric pressure storage tanks receiving hydrocarbon
liquids, annual CO2 emissions, in metric tons
CO2, that resulted from venting gas directly to the
atmosphere, calculated according to Sec. 98.233(j)(1) and (2).
(xii) Annual CH4 emissions, in metric tons
CH4, that resulted from venting gas directly to the
atmosphere, calculated according to Sec. 98.233(j)(1) and (2).
(xiii) For the atmospheric pressure storage tanks receiving
hydrocarbon liquids identified in paragraphs (j)(1)(x)(D) of this
section, total CO2 mass, in metric tons CO2, that
was recovered during the calendar year using a vapor recovery system.
(xiv) For the atmospheric pressure storage tanks identified in
paragraphs (j)(1)(x)(D) of this section, total CH4 mass, in
metric tons CH4, that was recovered during the calendar year
using a vapor recovery system.
(xv) For the atmospheric pressure storage tanks identified in
paragraph (j)(1)(x)(F) of this section, the total volume of gas vented
through open thief hatches, in scf, during periods while the storage
tanks were also routing emissions to vapor recovery systems and/or
flares.
(2) If you used Calculation Method 3 to calculate GHG emissions,
then you must report the information specified in paragraphs (j)(2)(i)
through (iii) of this section.
(i) Report the information specified in paragraphs (j)(2)(i)(A)
through (H) of this section, at the facility level, for atmospheric
pressure storage tanks where emissions were calculated using
Calculation Method 3 of Sec. 98.233(j).
(A) The total annual hydrocarbon liquids throughput that is sent to
all atmospheric pressure storage tanks in the facility with emissions
calculated using Calculation Method 3, in barrels. You may delay
reporting of this data element for onshore production if you indicate
in the annual report that wildcat wells and/or delineation wells are
the only wells at the facility with hydrocarbon liquids production that
send hydrocarbon liquids to atmospheric pressure storage tanks for
which emissions were calculated using Calculation Method 3. If you
elect to delay reporting of this data element, you must report by the
date specified in paragraph (cc) of this section the total annual
hydrocarbon liquids throughput from all wells and the well ID number(s)
for the well(s) included in this volume.
(B) The total annual produced water throughput that is sent to all
atmospheric pressure storage tanks in the facility with emissions
calculated using Calculation Method 3, in barrels, specified in
paragraphs (j)(2)(i)(B)(1) through (3) of this section.
(1) Total volume of produced water with pressure less than or equal
to 50 psi.
(2) Total volume of produced water with pressure greater than 50
psi and less than or equal to 250 psi.
(3) Total volume of produced water with pressure greater than 250
psi.
(C) An estimate of the fraction of hydrocarbon liquids throughput
reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric
pressure storage tanks in the facility that controlled emissions with
flares.
(D) An estimate of the fraction of hydrocarbon liquids throughput
reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric
pressure storage tanks in the facility that controlled emissions with
vapor recovery systems.
(E) An estimate of the fraction of total produced water throughput
reported in paragraph (j)(2)(i)(B) of this section sent to atmospheric
pressure storage tanks in the facility that controlled emissions with
flares.
(F) An estimate of the fraction of total produced water throughput
reported in paragraph (j)(2)(i)(B) of this section sent to atmospheric
pressure storage tanks in the facility that controlled emissions with
vapor recovery systems.
(G) The number of fixed roof atmospheric pressure storage tanks in
the facility.
(H) The number of floating roof atmospheric pressure storage tanks
in the facility.
(ii) Report the information specified in paragraphs (j)(2)(ii)(A)
through (H) of this section for each well-pad site (for onshore
production), gathering and boosting site (for onshore petroleum and
natural gas gathering and boosting), or facility (for all other
applicable industry segments) with atmospheric pressure storage tanks
receiving hydrocarbon liquids whose emissions were calculated using
Sec. 98.233(j)(3)(i).
(A) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(B) The number of atmospheric pressure storage tanks that did not
control emissions with flares and for which emissions were calculated
using Calculation Method 3.
(C) The number of atmospheric pressure storage tanks that
controlled emissions with flares and for which emissions were
calculated using Calculation Method 3.
(D) The number of atmospheric pressure storage tanks that had an
open thief hatch at some point during the year while the storage tank
was also routing emissions to a vapor recovery system and/or a flare.
(E) The total number of separators, wells, or non-separator
equipment with annual average daily hydrocarbon liquids throughput
greater than 0 barrels per day and less than 10 barrels per day for
which you used Calculation Method 3 (``Count'' from equation W-15A to
Sec. 98.233).
(F) Annual CO2 emissions, in metric tons CO2,
that resulted from venting gas directly to the atmosphere, calculated
using equation W-15A to Sec. 98.233 and adjusted using the
requirements described in Sec. 98.233(j)(4), if applicable.
(G) Annual CH4 emissions, in metric tons CH4,
that resulted from venting gas directly to the atmosphere, calculated
using equation W-15A to Sec. 98.233 and adjusted using the
requirements described in Sec. 98.233(j)(4), if applicable.
(H) The total volume of gas vented through open thief hatches, in
scf, during periods while the atmospheric pressure storage tanks were
also routing emissions to vapor recovery systems and/or flares.
(iii) Report the information specified in paragraphs (j)(2)(iii)(A)
through (F) of this section for each well-pad site (for onshore
production), gathering and boosting site (for onshore petroleum and
natural gas gathering and boosting), or facility (for onshore natural
gas processing) with atmospheric pressure storage tanks receiving
produced water whose emissions were calculated using Sec.
98.233(j)(3)(ii).
(A) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(B) The number of atmospheric pressure storage tanks that did not
control emissions with flares and for which emissions were calculated
using Calculation Method 3.
[[Page 42308]]
(C) The number of atmospheric pressure storage tanks that
controlled emissions with flares and for which emissions were
calculated using Calculation Method 3.
(D) The number of atmospheric pressure storage tanks that had an
open thief hatch at some point during the year while the storage tank
was also routing emissions to a vapor recovery system and/or a flare.
(E) Annual CH4 emissions, in metric tons CH4,
that resulted from venting gas directly to the atmosphere, calculated
using equation W-15B to Sec. 98.233 and adjusted using the
requirements described in Sec. 98.233(j)(4), if applicable.
(F) The total volume of gas vented through open thief hatches, in
scf, during periods while the atmospheric pressure storage tanks were
also routing emissions to vapor recovery systems and/or flares.
(3) If you used Calculation Method 1 or Calculation Method 2 of
Sec. 98.233(j), and any gas-liquid separator liquid dump values did
not close properly during the calendar year, then you must report the
information specified in paragraphs (j)(3)(i) through (v) of this
section for each well-pad site (for onshore production), gathering and
boosting site (for onshore petroleum and natural gas gathering and
boosting), or facility (for all other applicable industry segments) by
liquid type.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) The total number of gas-liquid separators whose liquid dump
valves did not close properly during the calendar year.
(iii) The total time the dump valves on gas-liquid separators did
not close properly in the calendar year, in hours (sum of the
``Tdv'' values used in equation W-16 to Sec. 98.233).
(iv) For atmospheric pressure storage tanks receiving hydrocarbon
liquids, annual CO2 emissions, in metric tons
CO2, that resulted from dump valves on gas-liquid separators
not closing properly during the calendar year, calculated using
equation W-16 to Sec. 98.233.
(v) Annual CH4 emissions, in metric tons CH4,
that resulted from the dump valves on gas-liquid separators not closing
properly during the calendar year, calculated using equation W-16 to
Sec. 98.233.
(4) For atmospheric pressure storage tanks that were routed to
flares, report the information specified in paragraphs (j)(4)(i)
through (iv) of this section.
(i) Indicate whether you calculated natural gas emissions routed to
the flare using continuous parameter monitoring systems as specified in
Sec. 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas
composition analyzers or sampling as specified in Sec. 98.233(n)(4),
or you calculated natural gas emissions routed to the flare using the
calculation methods in Sec. 98.233(j) as specified in Sec.
98.233(n)(3)(ii)(B).
(ii) Indicate whether natural gas emissions were routed to a flare
for the entire year or only part of the year.
(iii) The unique name or ID for the flare stack as specified in
paragraph (n)(1) of this section to which the atmospheric pressure
storage tank vent was routed.
(iv) The unique ID for the stream routed to the flare as specified
in paragraph (n)(3) of this section from the atmospheric pressure
storage tank.
(k) Condensate storage tanks. You must indicate whether your
facility contains any condensate storage tanks. If your facility
contains at least one condensate storage tank, then you must report the
information specified in paragraphs (k)(1) and (2) of this section for
each condensate storage tank vent stack.
(1) For each condensate storage tank vent stack, report the
information specified in (k)(1)(i) through (iv) of this section.
(i) The unique name or ID number for the condensate storage tank
vent stack.
(ii) Indicate if a flare is attached to the condensate storage tank
vent stack.
(iii) Indicate whether scrubber dump valve leakage occurred for the
condensate storage tank vent according to Sec. 98.233(k)(1).
(iv) Which method specified in Sec. 98.233(k)(1) was used to
determine if dump valve leakage occurred.
(2) If scrubber dump valve leakage occurred for a condensate
storage tank vent stack, as reported in paragraph (k)(1)(iii) of this
section, and the vent stack vented directly to the atmosphere during
the calendar year, then you must report the information specified in
paragraphs (k)(2)(i) through (v) of this section for each condensate
storage vent stack where scrubber dump valve leakage occurred.
(i) Which method specified in Sec. 98.233(k)(2) was used to
measure the leak rate.
(ii) Measured leak rate (average leak rate from a continuous flow
measurement device), in standard cubic feet per hour.
(iii) Duration of time that the leak is counted as having occurred,
in hours, as determined in Sec. 98.233(k)(3) (may use best available
data if a continuous flow measurement device was used).
(iv) Annual CO2 emissions, in metric tons
CO2, that resulted from venting gas directly to the
atmosphere, calculated according to Sec. 98.233(k)(1) through (4).
(v) Annual CH4 emissions, in metric tons CH4,
that resulted from venting gas directly to the atmosphere, calculated
according to Sec. 98.233(k)(1) through (4).
(l) Well testing. You must indicate whether you performed gas well
or oil well testing, and if the testing of gas wells or oil wells
resulted in vented or flared emissions during the calendar year. If you
performed well testing that resulted in vented or flared emissions
during the calendar year, then you must report the information
specified in paragraphs (l)(1) through (4) of this section, as
applicable.
(1) For oil wells not routed to a flare, you must report the
information specified in paragraphs (l)(1)(i) through (vii) of this
section for each well tested.
(i) [Reserved]
(ii) Well ID number.
(iii) Number of well testing days for the tested well in the
calendar year.
(iv) Average gas to oil ratio for the tested well, in cubic feet of
gas per barrel of oil. You may delay reporting of this data element if
you indicate in the annual report that the well is a wildcat well or
delineation well. If you elect to delay reporting of this data element,
you must report by the date specified in paragraph (cc) of this section
the average gas to oil ratio for the tested well.
(v) Average flow rate for the tested well, in barrels of oil per
day. You may delay reporting of this data element if you indicate in
the annual report that the well is a wildcat well or delineation well.
If you elect to delay reporting of this data element, you must report
by the date specified in paragraph (cc) of this section the measured
average flow rate for the tested well.
(vi) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec. 98.233(l).
(vii) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec. 98.233(l).
(2) For oil wells routed to a flare and where you calculated
natural gas emissions routed to the flare using continuous parameter
monitoring systems as specified in Sec. 98.233(n)(3)(i) and
98.233(n)(3)(ii)(A) and continuous gas composition analyzers or
sampling as specified in Sec. 98.233(n)(4), then you must report the
information specified in paragraphs (l)(2)(i) through (ii) and (ix) of
this section, for each well tested. For oil wells routed to a flare and
where you calculated natural gas emissions routed
[[Page 42309]]
to the flare using the calculation methods in Sec. 98.233(l) to
determine natural gas volumes as specified in Sec.
98.233(n)(3)(ii)(B), then you must report the information specified in
paragraphs (l)(2)(i) through (v) and (ix) of this section. All reported
data elements should be specific to the well for which equation W-17A
to Sec. 98.233 was used and for which well testing emissions were
routed to flares.
(i) [Reserved]
(ii) Well ID number.
(iii) Number of well testing days for the tested well in the
calendar year.
(iv) Average gas to oil ratio for the tested well, in cubic feet of
gas per barrel of oil. You may delay reporting of this data element if
you indicate in the annual report that the well is a wildcat well or
delineation well. If you elect to delay reporting of this data element,
you must report by the date specified in paragraph (cc) of this section
the average gas to oil ratio for the tested well.
(v) Average flow rate for the tested well, in barrels of oil per
day. You may delay reporting of this data element if you indicate in
the annual report that the well is a wildcat well or delineation well.
If you elect to delay reporting of this data element, you must report
by the date specified in paragraph (cc) of this section the measured
average flow rate for the tested well.
(vi) [Reserved]
(vii)[Reserved]
(viii) [Reserved]
(ix) Indicate whether natural gas emissions from well testing were
routed to a flare and emissions are reported according to paragraph (n)
of this section, and if so, provide the information specified in
paragraphs (l)(2)(ix)(A) through (D).
(A) Indicate whether you calculated natural gas emissions routed to
the flare using continuous parameter monitoring systems as specified in
Sec. 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas
composition analyzers or sampling as specified in Sec. 98.233(n)(4),
or you calculated natural gas emissions routed to the flare using the
calculation methods in Sec. 98.233(l) as specified in Sec.
98.233(n)(3)(ii)(B).
(B) Indicate whether natural gas emissions were routed to a flare
for the entire year or only part of the year.
(C) The unique name or ID for the flare stack as specified in
paragraph (n)(1) of this section.
(D) The unique ID for each stream routed to the flare as specified
in paragraph (n)(3) of this section.
(3) For gas wells not routed to a flare, you must report the
information specified in paragraphs (l)(3)(i) through (vi) of this
section for each well tested.
(i) [Reserved]
(ii) Well ID number.
(iii) Number of well testing days for the tested well(s) in the
calendar year. You may delay reporting of this data element if you
indicate in the annual report that the well is a wildcat well or
delineation well. If you elect to delay reporting of this data element,
you must report by the date specified in paragraph (cc) of this section
the number of well testing days for the tested well.
(iv) Average annual production rate for the tested well, in actual
cubic feet per day. You may delay reporting of this data element if you
indicate in the annual report that the well is a wildcat well or
delineation well. If you elect to delay reporting of this data element,
you must report by the date specified in paragraph (cc) of this section
the measured average annual production rate for the tested well.
(v) Annual CO2 emissions, in metric tons CO2,
calculated according to Sec. 98.233(l).
(vi) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec. 98.233(l).
(4) For gas wells routed to a flare and where you calculated
natural gas emissions routed to the flare using continuous parameter
monitoring systems as specified in Sec. 98.233(n)(3)(i) and
98.233(n)(3)(ii)(A) and continuous gas composition analyzers or
sampling as specified in Sec. 98.233(n)(4), then you must report the
information specified in paragraphs (l)(4)(i) through (ii) and (viii)
of this section, for each well tested. For gas wells routed to a flare
and where you calculated natural gas emissions routed to the flare
using the calculation methods in Sec. 98.233(l) to determine natural
gas volumes as specified in Sec. 98.233(n)(3)(ii)(B), then you must
report the information specified in paragraphs (l)(4)(i) through (iv)
and (viii) of this section for each well tested. All reported data
elements should be specific to the well for which equation W-17B to
Sec. 98.233 was used and for which well testing emissions were routed
to flares.
(i) [Reserved]
(ii) Well ID number.
(iii) Number of well testing days for the tested well in the
calendar year. You may delay reporting of this data element if you
indicate in the annual report that the well is a wildcat well or
delineation well. If you elect to delay reporting of this data element,
you must report by the date specified in paragraph (cc) of this section
the number of well testing days for the tested well.
(iv) Average annual production rate for the tested well, in actual
cubic feet per day. You may delay reporting of this data element if you
indicate in the annual report that the well is a wildcat well and/or
delineation well and the only wells that are tested in the same basin
are wildcat wells and/or delineation wells. If you elect to delay
reporting of this data element, you must report by the date specified
in paragraph (cc) of this section the measured average annual
production rate for the tested well.
(v) [Reserved]
(vi)[Reserved]
(vii) [Reserved]
(viii) Indicate whether natural gas emissions from well testing
were routed to a flare and emissions are reported according to
paragraph (n) of this section, and if so, provide the information
specified in paragraphs (l)(4)(viii)(A) through (D).
(A) Indicate whether you calculated natural gas emissions routed to
the flare using continuous parameter monitoring systems as specified in
Sec. 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas
composition analyzers or sampling as specified in Sec. 98.233(n)(4),
or you calculated natural gas emissions routed to the flare using the
calculation methods in Sec. 98.233(l) as specified in Sec.
98.233(n)(3)(ii)(B).
(B) Indicate whether natural gas emissions were routed to a flare
for the entire year or only part of the year.
(C) The unique name or ID for the flare stack as specified in
paragraph (n)(1) of this section.
(D) The unique ID for each stream routed to the flare as specified
in paragraph (n)(3) of this section.
(m) Associated natural gas. You must indicate whether any
associated gas was vented or flared during the calendar year. If
associated gas was vented during the calendar year, then you must
report the information specified in paragraphs (m)(1) through (7) of
this section for each well for which associated gas was vented. If
associated gas was flared during the calendar year and you calculated
natural gas emissions routed to the flare using continuous parameter
monitoring systems as specified in Sec. 98.233(n)(3)(i) and
98.233(n)(3)(ii)(A) and continuous gas composition analyzers or
sampling as specified in Sec. 98.233(n)(4), then you must report the
information specified in paragraphs (m)(1) through (3) of this section,
for each well. If associated gas was flared and you calculated natural
gas emissions routed to the flare using the calculation methods in
Sec. 98.233(m) to determine natural gas volumes as specified in Sec.
98.233(n)(3)(ii)(B), then
[[Page 42310]]
you must report the information specified in paragraphs (m)(1) through
(6) of this section for each well.
(1) Well ID number.
(2) Indicate whether any associated gas was vented directly to the
atmosphere without flaring.
(3) Indicate whether any associated gas was flared and emissions
are reported according to paragraph (n) of this section, and, if so,
provide the information specified in paragraphs (m)(3)(i) through (iv).
(i) Indicate whether you calculated natural gas emissions routed to
the flare using continuous parameter monitoring systems as specified in
Sec. 98.233(n)(3)(i) and 98.233(n)(3)(ii)(A) and continuous gas
composition analyzers or sampling as specified in Sec. 98.233(n)(4),
or you calculated natural gas emissions routed to the flare using the
calculation methods in Sec. 98.233(m) as specified in Sec.
98.233(n)(3)(ii)(B).
(ii) Indicate whether natural gas emissions were routed to a flare
for the entire year or only part of the year.
(iii) The unique name or ID for the flare stack to which associated
natural gas is routed as specified in paragraph (n)(1) of this section.
(iv) The unique ID for each associated natural gas stream routed to
the flare as specified in paragraph (n)(3) of this section.
(4) Average gas to oil ratio, in standard cubic feet of gas per
barrel of oil during the reporting year. Do not report the GOR if you
vented or flared associated gas and used a continuous flow monitor to
determine the total volume of associated gas vented or routed to the
flare (i.e., if you did not use equation W-18 to Sec. 98.233 for the
well with associated gas venting or flaring emissions).
(5) Volume of oil produced by the well, in barrels, in the calendar
year only during the time periods in which associated gas was vented or
flared (``Vp'' used in equation W-18 to Sec. 98.233). You
may delay reporting of this data element if you indicate in the annual
report that the well is a wildcat well or delineation well. If you
elect to delay reporting of this data element, you must report by the
date specified in paragraph (cc) of this section the volume of oil
produced by the well during the time periods in which associated gas
venting and flaring was occurring. Do not report the volume of oil
produced if you vented or flared associated gas and used a continuous
flow monitor to determine the total volume of associated gas vented or
routed to the flare (i.e., if you did not use equation W-18 to Sec.
98.233 for the well with associated gas venting or flaring emissions).
(6) Total volume of associated gas sent to sales or used on site
and not sent to a vent or flare, in standard cubic feet, in the
calendar year only during time periods in which associated gas was
vented or flared (``SG'' value used in equation W-18 to Sec. 98.233).
You may delay reporting of this data element if you indicate in the
annual report that the well is a wildcat well or delineation well. If
you elect to delay reporting of this data element, you must report by
the date specified in paragraph (cc) of this section the measured total
volume of associated gas sent to sales for the well during the time
periods in which associated gas venting and flaring was occurring. Do
not report the volume of gas sent to sales if you vented or flared
associated gas and used a continuous flow monitor to determine the
total volume of associated gas vented or routed to the flare (i.e., if
you did not use equation W-18 to Sec. 98.233).
(7) If you had associated gas emissions vented directly to the
atmosphere without flaring, then you must report the information
specified in paragraphs (m)(7)(i) through (viii) of this section for
each well.
(i) [Reserved]
(ii) Indicate whether the associated gas volume vented from the
well was measured using a continuous flow monitor.
(iii) Indicate whether associated gas streams vented from the well
were measured with continuous gas composition analyzers.
(iv) Total volume of associated gas vented from the well, in
standard cubic feet.
(v) Flow-weighted average mole fraction of CH4 in
associated gas vented from the well.
(vi) Flow-weighted average mole fraction of CO2 in
associated gas vented from the well.
(vii) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec. 98.233(m)(3) and (4).
(viii) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec. 98.233(m)(3) and (4).
(n) Flare stacks. You must indicate if your facility has any flare
stacks. You must report the information specified in paragraphs (n)(1)
through (20) of this section for each flare stack at your facility.
(1) Unique name or ID for the flare stack. For the onshore
petroleum and natural gas production and onshore petroleum and natural
gas gathering and boosting industry segments, a different name or ID
may be used for a single flare stack for each location where it
operates at in a given calendar year.
(2) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(3) Unique IDs for each stream routed to the flare and the source
type that generated the stream, if you determine the flow of each
stream that is routed to the flare as specified in Sec.
98.233(n)(3)(ii) and/or you determine the gas composition for each
stream routed to the flare as specified in Sec. 98.233(n)(4)(iii). If
you determine flow or composition for a combined stream from multiple
source types, then report the source type that provides the most gas to
the combined stream. For source types not listed in Sec.
98.233(n)(3)(ii)(B)(1) through (7), report collectively as ``other.''
(4) Indicate the type of flare (i.e., open ground-level flare,
enclosed ground-level flare, open elevated flare, or enclosed elevated
flare).
(5) Indicate the type of flare assist (i.e., unassisted, air-
assisted with single speed fan/blower, air-assisted with dual speed
fan/blower, air-assisted with variable speed fan/blower, steam-
assisted, or pressure-assisted).
(6) Indicate whether the pilot flame or combustion flame was
monitored continuously, visually inspected, or both. If visually
inspected, report the number of inspections during the year. If the
pilot flame was monitored continuously, report the number of times all
continuous monitoring devices were out of service or otherwise
inoperable for a period of more than one week.
(7) Indicate whether you measured total flow at the inlet to the
flare as specified in Sec. 98.233(n)(3)(i) or whether you determined
flow for individual streams routed to the flare as specified in Sec.
98.233(n)(3)(ii). If you measured total flow, indicate whether the
volume of gas was determined using a continuous flow measurement device
or whether it was determined using parameter monitoring and engineering
calculations. If you determined flow for individual streams, indicate
for each stream whether flow was determined using a continuous flow
measurement device, parameter monitoring and engineering calculations,
or other simulation or engineering calculation methods. If you switched
from one method to another during the year, then indicate multiple
methods were used.
(8) Indicate whether a continuous gas composition analyzer was used
at the inlet to the flare as specified in
[[Page 42311]]
Sec. 98.233(n)(4)(i), whether composition at the inlet to the flare
was determined based on sampling and analysis as specified in Sec.
98.233(n)(4)(ii), or if composition was determined for individual
streams as specified in Sec. 98.233(n)(4)(iii). If you determined
composition for individual streams, indicate for each stream whether
composition was determined using a continuous gas composition analyzer,
sampling and analysis, or other simulation or engineering calculation
methods. If you switched from one method to another during the year,
then indicate multiple methods were used.
(9) Indicate whether you directly measured annual average HHV of
the inlet stream to the flare as specified in Sec. 98.233(n)(8)(i),
calculated the annual average HHV of the inlet stream to the flare
based on composition of the inlet stream as specified in Sec.
98.233(n)(8)(ii), directly measured the annual average HHV of
individual streams routed to the flare as specified in Sec.
98.233(n)(8)(iii), or calculated the annual average HHV of individual
streams based on their composition as specified in Sec.
98.233(n)(8)(iv).
(10) Annual average HHV of the inlet stream to the flare determined
as specified in Sec. 98.233(n)(8)(i) or (ii); both the calculated
flow-weighted annual average HHV of the inlet stream to the flare and
each individual stream HHV determined as specified in Sec.
98.233(n)(8)(iii)(B) or (iv)(B); or each individual stream HHV, if you
determined HHVs for each individual stream routed to the flare and you
used these HHVs to calculate N2O emissions for each stream
as specified in Sec. 98.233(n)(8)(iii)(A) or (iv)(A).
(11) Volume of gas sent to the flare, in standard cubic feet
(``Vs'' in equations W-19 and W-20 to Sec. 98.233, where
Vs is the total flow at the flare inlet if you measure inlet
flow to the flare in accordance with Sec. 98.233(n)(3)(i) or the sum
of the Vs values for individual streams if you measure or
determine flow of individual streams in accordance with Sec.
98.233(n)(3)(ii)). If you measure or determine the volume of gas for
each stream routed to the flare as specified in Sec. 98.233(n)(3)(ii),
then also report the annual volume of each stream, adjusted to exclude
any estimated volume that bypassed the flare or determined to have
leaked from the closed vent system, and indicate that the flow has been
adjusted to account for bypass volume or leaks.
(12) Fraction of the feed gas sent to an un-lit flare based on
total time when continuous monitoring of the pilot or periodic
inspections indicated the flare was not lit and measured or calculated
flow during the times when the flare was not lit (``ZU'' in
equation W-19 to Sec. 98.233).
(13) Flare destruction efficiency, expressed as the fraction of
hydrocarbon compounds in gas that is destroyed by a burning flare, but
may or may not be completely oxidized to CO2 (Sec.
98.233(n)(1)). If you used multiple methods during the year, report the
flow-weighted average destruction efficiency based on each tier that
applied. Report the efficiency fraction to three decimal places.
(i) If you use tier 1, report the following:
(A) Number of days in periods of 15 or more consecutive days when
you did not conform with all cited provisions in Sec. 98.233(n)(1)(i).
(B) [Reserved]
(ii) If you use tier 2, report the following:
(A) Indicate if you are subject to part 60, subpart OOOOb of this
chapter or an applicable approved state plan or applicable Federal plan
in part 62 of this chapter or if you are electing to comply with the
flare monitoring requirements in part 60, subpart OOOOb of this chapter
or an applicable approved state plan or applicable Federal plan in part
62 of this chapter.
(B) If you are not required to comply with part 60, subpart OOOOb
of this chapter or an applicable approved state plan or applicable
Federal plan in part 62 of this chapter, indicate whether you are
electing to comply with Sec. 98.233(n)(1)(ii)(A), (B), (C), or (D).
(C) If you are not required to comply with part 60, subpart OOOOb
of this chapter or an applicable approved state plan or applicable
Federal plan in part 62 of this chapter and the flare is an enclosed
ground level flare or an enclosed elevated flare, indicate if your most
recent performance test was conducted using the method in Sec.
60.5413b(b) of this chapter (as specified in Sec.
98.233(n)(1)(ii)(A)), the method in Sec. 60.5413b(d) of this chapter
(as specified in Sec. 98.233(n)(1)(ii)(C)), or if it was conducted
using OTM-52.
(D) Number of days in periods of 15 or more consecutive days when
you did not conform with all cited provisions in Sec.
98.233(n)(1)(ii).
(iii) Indicate if you use an alternative test method approved under
Sec. 60.5412b(d) of this chapter or an applicable approved state plan
or applicable Federal plan in part 62 of this chapter. If you use an
approved alternative test method, indicate the approved destruction
efficiency for the method, the date when you started to use the method,
and the name or ID of the method.
(14) Annual average mole fraction of CH4 in the feed gas
to the flare if you measure composition of the inlet gas as specified
in Sec. 98.233(n)(3)(i) or (ii) (``XCH4'' in equation W-19
to Sec. 98.233), or the annual average CH4 mole fractions
for each stream if you determine composition of each stream routed to
the flare as specified in Sec. 98.233(n)(4)(iii).
(15) Except as specified in paragraph (n)(20) of this section,
annual average mole fraction of CO2 in the feed gas to the
flare if you measure composition of the inlet gas as specified in Sec.
98.233(n)(4)(i) or (ii) (``XCO2'' in equation W-20 to Sec.
98.233), or the annual average CO2 mole fractions for each
stream if you determine composition of each stream routed to the flare
as specified in Sec. 98.233(n)(4)(iii).
(16) Annual CO2 emissions, in metric tons CO2
(refer to equation W-20 to Sec. 98.233).
(17) Annual CH4 emissions, in metric tons CH4
(refer to equation W-19 to Sec. 98.233).
(18) Annual N2O emissions, in metric tons N2O
(refer to equation W-40 to Sec. 98.233).
(19) Estimated disaggregated CH4, CO2, and
N2O emissions attributed to each source type as determined
in Sec. 98.233(n)(10) (i.e., AGR vents, dehydrator vents, well venting
during completions and workovers with hydraulic fracturing, gas well
venting during completions and workovers without hydraulic fracturing,
hydrocarbon liquids and produced water storage tanks, well testing
venting and flaring, associated gas venting and flaring, other flared
sources).
(20) Indicate whether a CEMS was used to measure emissions from the
flare. If a CEMS was used, then you are not required to report the
CO2 mole fraction in paragraph (n)(15) of this section.
(o) Centrifugal compressors. You must indicate whether your
facility has centrifugal compressors. You must report the information
specified in paragraphs (o)(1) and (2) of this section for all
centrifugal compressors at your facility. For each compressor source or
manifolded group of compressor sources that you conduct as found leak
measurements as specified in Sec. 98.233(o)(2) or (4), you must report
the information specified in paragraph (o)(3) of this section. For each
compressor source or manifolded group of compressor sources that you
conduct continuous monitoring as specified in Sec. 98.233(o)(3) or
(5), you must report the information specified in paragraph (o)(4) of
this section. Centrifugal
[[Page 42312]]
compressors in onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting that calculate
emissions according to Sec. 98.233(o)(10)(iii) are not required to
report information in paragraphs (o)(1) through (4) of this section and
instead must report the information specified in paragraph (o)(5) of
this section.
(1) Compressor activity data. Report the information specified in
paragraphs (o)(1)(i) through (xi) of this section, as applicable, for
each centrifugal compressor located at your facility.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) Unique name or ID for the centrifugal compressor.
(iii) Hours in operating-mode.
(iv) Hours in standby-pressurized-mode.
(v) Hours in not-operating-depressurized-mode.
(vi) If you conducted volumetric emission measurements as specified
in Sec. 98.233(o)(1):
(A) Indicate whether the compressor was measured in operating-mode.
(B) Indicate whether the compressor was measured in standby-
pressurized-mode.
(C) Indicate whether the compressor was measured in not-operating-
depressurized-mode.
(vii) Indicate whether the compressor has blind flanges installed
and associated dates.
(viii) Indicate whether the compressor has wet or dry seals.
(ix) If the compressor has wet seals, the number of wet seals.
(x) If the compressor has dry seals, the number of dry seals.
(xi) Power output of the compressor driver (hp).
(2) Compressor source. (i) For each compressor source at each
compressor, report the information specified in paragraphs (o)(2)(i)(A)
through (C) of this section.
(A) Centrifugal compressor name or ID. Use the same ID as in
paragraph (o)(1)(ii) of this section.
(B) Centrifugal compressor source (wet seal, dry seal, isolation
valve, or blowdown valve).
(C) Unique name or ID for the leak or vent. If the leak or vent is
connected to a manifolded group of compressor sources, use the same
leak or vent ID for each compressor source in the manifolded group. If
multiple compressor sources are released through a single vent for
which continuous measurements are used, use the same leak or vent ID
for each compressor source released via the measured vent. For a single
compressor using as found measurements, you must provide a different
leak or vent ID for each compressor source.
(ii) For each leak or vent, report the information specified in
paragraphs (o)(2)(ii)(A) through (E) of this section.
(A) Indicate whether the leak or vent is for a single compressor
source or manifolded group of compressor sources and whether the
emissions from the leak or vent are released to the atmosphere, routed
to a flare, combustion, or vapor recovery system.
(B) Indicate whether an as found measurement(s) as identified in
Sec. 98.233(o)(2) or (4) was conducted on the leak or vent.
(C) Indicate whether continuous measurements as identified in Sec.
98.233(o)(3) or (5) were conducted on the leak or vent.
(D) Report emissions as specified in paragraphs (o)(2)(ii)(D)(1)
and (2) of this section for the leak or vent. If the leak or vent is
routed to a flare, combustion, or vapor recovery system, you are not
required to report emissions under this paragraph.
(1) Annual CO2 emissions, in metric tons CO2.
(2) Annual CH4 emissions, in metric tons CH4.
(E) If the leak or vent is routed to flare, combustion, or vapor
recovery system, report the percentage of time that the respective
device was operational when the compressor source emissions were routed
to the device.
(3) As found measurement sample data. If the measurement methods
specified in Sec. 98.233(o)(2) or (4) are conducted, report the
information specified in paragraph (o)(3)(i) of this section. If the
calculation specified in Sec. 98.233(o)(6)(ii) is performed, report
the information specified in paragraph (o)(3)(ii) of this section.
(i) For each as found measurement performed on a leak or vent,
report the information specified in paragraphs (o)(3)(i)(A) through (F)
of this section.
(A) Name or ID of leak or vent. Use same leak or vent ID as in
paragraph (o)(2)(i)(C) of this section.
(B) Measurement date.
(C) Measurement method. If emissions were not detected when using a
screening method, report the screening method. If emissions were
detected using a screening method, report only the method subsequently
used to measure the volumetric emissions.
(D) Measured flow rate, in standard cubic feet per hour.
(E) For each compressor attached to the leak or vent, report the
compressor mode during which the measurement was taken.
(F) If the measurement is for a manifolded group of compressor
sources, indicate whether the measurement location is prior to or after
comingling with non-compressor emission sources.
(ii) For each compressor mode-source combination where a reporter
emission factor as calculated in equation W-23 to Sec. 98.233 was used
to calculate emissions in equation W-22 to Sec. 98.233, report the
information specified in paragraphs (o)(3)(ii)(A) through (D) of this
section.
(A) The compressor mode-source combination.
(B) The compressor mode-source combination reporter emission
factor, in standard cubic feet per hour (EFs,m in equation
W-23 to Sec. 98.233).
(C) The total number of compressors measured in the compressor
mode-source combination in the current reporting year and the preceding
two reporting years (Countm in equation W-23 to Sec.
98.233).
(D) Indicate whether the compressor mode-source combination
reporter emission factor is facility-specific or based on all of the
reporter's applicable facilities.
(4) Continuous measurement data. If the measurement methods
specified in Sec. 98.233(o)(3) or (5) are conducted, report the
information specified in paragraphs (o)(4)(i) through (iv) of this
section for each continuous measurement conducted on each leak or vent
associated with each compressor source or manifolded group of
compressor sources.
(i) Name or ID of leak or vent. Use same leak or vent ID as in
paragraph (o)(2)(i)(C) of this section.
(ii) Measured volume of flow during the reporting year, in million
standard cubic feet.
(iii) Indicate whether the measured volume of flow during the
reporting year includes compressor blowdown emissions as allowed for in
Sec. 98.233(o)(3)(ii) and (o)(5)(iii).
(iv) If the measurement is for a manifolded group of compressor
sources, indicate whether the measurement location is prior to or after
comingling with non-compressor emission sources.
(5) Onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting. Centrifugal
compressors with wet seal degassing vents in onshore petroleum and
natural gas production and onshore petroleum and natural gas gathering
and boosting that calculate emissions
[[Page 42313]]
according to Sec. 98.233(o)(10)(iii) must report the information
specified in paragraphs (o)(5)(i) through (iv) of this section. You
must report the information specified in paragraphs (o)(5)(i) through
(iv) of this section, as applicable, for each well-pad site (for
onshore petroleum and natural gas production) or each gathering and
boosting site (for onshore petroleum and natural gas gathering and
boosting).
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) Report the following activity data.
(A) Total number of centrifugal compressors at the facility.
(B) Number of centrifugal compressors that have wet seals.
(C) Number of centrifugal compressors that have atmospheric wet
seal oil degassing vents (i.e., wet seal oil degassing vents where the
emissions are released to the atmosphere rather than being routed to
flares, combustion, or vapor recovery systems).
(iii) Annual CO2 emissions, in metric tons
CO2, from centrifugal compressors with atmospheric wet seal
oil degassing vents.
(iv) Annual CH4 emissions, in metric tons
CH4, from centrifugal compressors with atmospheric wet seal
oil degassing vents.
(p) Reciprocating compressors. You must indicate whether your
facility has reciprocating compressors. You must report the information
specified in paragraphs (p)(1) and (2) of this section for all
reciprocating compressors at your facility. For each compressor source
or manifolded group of compressor sources that you conduct as found
leak measurements as specified in Sec. 98.233(p)(2) or (4), you must
report the information specified in paragraph (p)(3) of this section.
For each compressor source or manifolded group of compressor sources
that you conduct continuous monitoring as specified in Sec.
98.233(p)(3) or (5), you must report the information specified in
paragraph (p)(4) of this section. Reciprocating compressors in onshore
petroleum and natural gas production and onshore petroleum and natural
gas gathering and boosting that calculate emissions according to Sec.
98.233(p)(10)(iii) are not required to report information in paragraphs
(p)(1) through (4) of this section and instead must report the
information specified in paragraph (p)(5) of this section.
(1) Compressor activity data. Report the information specified in
paragraphs (p)(1)(i) through (viii) of this section, as applicable, for
each reciprocating compressor located at your facility.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) Unique name or ID for the reciprocating compressor.
(iii) Hours in operating-mode.
(iv) Hours in standby-pressurized-mode.
(v) Hours in not-operating-depressurized-mode.
(vi) If you conducted volumetric emission measurements as specified
in Sec. 98.233(p)(1):
(A) Indicate whether the compressor was measured in operating-mode.
(B) Indicate whether the compressor was measured in standby-
pressurized-mode.
(C) Indicate whether the compressor was measured in not-operating-
depressurized-mode.
(vii) Indicate whether the compressor has blind flanges installed
and associated dates.
(viii) Power output of the compressor driver (hp).
(2) Compressor source. (i) For each compressor source at each
compressor, report the information specified in paragraphs (p)(2)(i)(A)
through (C) of this section.
(A) Reciprocating compressor name or ID. Use the same ID as in
paragraph (p)(1)(i) of this section.
(B) Reciprocating compressor source (isolation valve, blowdown
valve, or rod packing).
(C) Unique name or ID for the leak or vent. If the leak or vent is
connected to a manifolded group of compressor sources, use the same
leak or vent ID for each compressor source in the manifolded group. If
multiple compressor sources are released through a single vent for
which continuous measurements are used, use the same leak or vent ID
for each compressor source released via the measured vent. For a single
compressor using as found measurements, you must provide a different
leak or vent ID for each compressor source.
(ii) For each leak or vent, report the information specified in
paragraphs (p)(2)(ii)(A) through (E) of this section.
(A) Indicate whether the leak or vent is for a single compressor
source or manifolded group of compressor sources and whether the
emissions from the leak or vent are released to the atmosphere, routed
to a flare, combustion, or vapor recovery system.
(B) Indicate whether an as found measurement(s) as identified in
Sec. 98.233(p)(2) or (4) was conducted on the leak or vent.
(C) Indicate whether continuous measurements as identified in Sec.
98.233(p)(3) or (5) were conducted on the leak or vent.
(D) Report emissions as specified in paragraphs (p)(2)(ii)(D)(1)
and (2) of this section for the leak or vent. If the leak or vent is
routed to a flare, combustion, or vapor recovery system, you are not
required to report emissions under this paragraph.
(1) Annual CO2 emissions, in metric tons CO2.
(2) Annual CH4 emissions, in metric tons CH4.
(E) If the leak or vent is routed to a flare, combustion, or vapor
recovery system, report the percentage of time that the respective
device was operational when the compressor source emissions were routed
to the device.
(3) As found measurement sample data. If the measurement methods
specified in Sec. 98.233(p)(2) or (4) are conducted, report the
information specified in paragraph (p)(3)(i) of this section. If the
calculation specified in Sec. 98.233(p)(6)(ii) is performed, report
the information specified in paragraph (p)(3)(ii) of this section.
(i) For each as found measurement performed on a leak or vent,
report the information specified in paragraphs (p)(3)(i)(A) through (F)
of this section.
(A) Name or ID of leak or vent. Use same leak or vent ID as in
paragraph (p)(2)(i)(C) of this section.
(B) Measurement date.
(C) Measurement method. If emissions were not detected when using a
screening method, report the screening method. If emissions were
detected using a screening method, report only the method subsequently
used to measure the volumetric emissions.
(D) Measured flow rate, in standard cubic feet per hour.
(E) For each compressor attached to the leak or vent, report the
compressor mode during which the measurement was taken.
(F) If the measurement is for a manifolded group of compressor
sources, indicate whether the measurement location is prior to or after
comingling with non-compressor emission sources.
(ii) For each compressor mode-source combination where a reporter
emission factor as calculated in equation W-28 to Sec. 98.233 was used
to calculate emissions in equation W-27 to Sec. 98.233, report the
information specified in paragraphs (p)(3)(ii)(A) through (D) of this
section.
(A) The compressor mode-source combination.
(B) The compressor mode-source combination reporter emission
factor, in
[[Page 42314]]
standard cubic feet per hour (EFs,m in equation W-28 to
Sec. 98.233).
(C) The total number of compressors measured in the compressor
mode-source combination in the current reporting year and the preceding
two reporting years (Countm in equation W-28 to Sec.
98.233).
(D) Indicate whether the compressor mode-source combination
reporter emission factor is facility-specific or based on all of the
reporter's applicable facilities.
(4) Continuous measurement data. If the measurement methods
specified in Sec. 98.233(p)(3) or (5) are conducted, report the
information specified in paragraphs (p)(4)(i) through (iv) of this
section for each continuous measurement conducted on each leak or vent
associated with each compressor source or manifolded group of
compressor sources.
(i) Name or ID of leak or vent. Use same leak or vent ID as in
paragraph (p)(2)(i)(C) of this section.
(ii) Measured volume of flow during the reporting year, in million
standard cubic feet.
(iii) Indicate whether the measured volume of flow during the
reporting year includes compressor blowdown emissions as allowed for in
Sec. 98.233(p)(3)(ii) and (p)(5)(iii).
(iv) If the measurement is for a manifolded group of compressor
sources, indicate whether the measurement location is prior to or after
comingling with non-compressor emission sources.
(5) Onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting. Reciprocating
compressors in onshore petroleum and natural gas production and onshore
petroleum and natural gas gathering and boosting that calculate
emissions according to Sec. 98.233(p)(10)(iii) must report the
information specified in paragraphs (p)(5)(i) through (iv) of this
section. You must report the information specified in paragraphs
(p)(5)(i) through (iv) of this section, as applicable, for each well-
pad site (for onshore petroleum and natural gas production) or each
gathering and boosting site (for onshore petroleum and natural gas
gathering and boosting).
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) Report the following activity data.
(A) Total number of reciprocating compressors at the facility.
(B) Number of reciprocating compressors that have rod packing
emissions vented directly to the atmosphere (i.e., rod packing vents
where the emissions are released to the atmosphere rather than being
routed to flares, combustion, or vapor recovery systems).
(iii) Annual CO2 emissions, in metric tons
CO2, from reciprocating compressors with rod packing
emissions vented directly to the atmosphere.
(iv) Annual CH4 emissions, in metric tons
CH4, from reciprocating compressors with rod packing
emissions vented directly to the atmosphere.
(q) Equipment leak surveys. For any components subject to or
complying with the requirements of Sec. 98.233(q), you must report the
information specified in paragraphs (q)(1) and (2) of this section. You
must report the information specified in paragraphs (q)(1) and (2) of
this section, as applicable, for each well-pad site (for onshore
production), gathering and boosting site (for onshore petroleum and
natural gas gathering and boosting), or facility (for all other
applicable industry segments). Natural gas distribution facilities with
emission sources listed in Sec. 98.232(i)(1) must also report the
information specified in paragraph (q)(3) of this section.
(1) You must report the information specified in paragraphs
(q)(1)(i) through (ix) of this section.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) Except as specified in paragraph (q)(1)(iii) of this section,
the number of complete equipment leak surveys performed during the
calendar year.
(iii) Natural gas distribution facilities performing equipment leak
surveys across a multiple year leak survey cycle must report the number
of years in the leak survey cycle.
(iv) Except for natural gas distribution facilities and onshore
natural gas transmission pipeline facilities, indicate whether any of
the leak detection surveys used in calculating emissions per Sec.
98.233(q)(2) were conducted for compliance with any of the standards in
paragraphs (q)(1)(iv)(A) through (E) of this section. Report the
indication per well-pad site, gathering and boosting site, or facility,
not per component type, as applicable.
(A) The well site or compressor station fugitive emissions
standards in Sec. 60.5397a of this chapter.
(B) The well site, centralized production facility, or compressor
station fugitive emissions standards in Sec. 60.5397b or Sec.
60.5398b of this chapter.
(C) The well site, centralized production facility, or compressor
station fugitive emissions standards in an applicable approved state
plan or applicable Federal plan in part 62 of this chapter.
(D) The standards for equipment leaks at onshore natural gas
processing plants in Sec. 60.5400b or Sec. 60.5401b of this chapter.
(E) The standards for equipment leaks at onshore natural gas
processing plants in an applicable approved state plan or applicable
Federal plan in part 62 of this chapter.
(v) For facilities in onshore petroleum and natural gas production,
onshore petroleum and natural gas gathering and boosting, onshore
natural gas transmission compression, underground natural gas storage,
LNG storage, and LNG import and export equipment, indicate whether you
elected to comply with Sec. 98.233(q) according to Sec.
98.233(q)(1)(iv) for any equipment components at your well-pad site,
gathering and boosting site, or facility.
(vi) Report each type of method described in Sec. 98.234(a) that
was used to conduct leak surveys.
(vii) Report whether emissions were calculated using Calculation
Method 1 (leaker factor emission calculation methodology) and/or using
Calculation Method 2 (leaker measurement methodology).
(viii) For facilities in onshore petroleum and natural gas
production and onshore petroleum and natural gas gathering and
boosting, report the number of major equipment (as listed in table W-1
to this subpart) by service type for which leak detection surveys were
conducted and emissions calculated according to Sec. 98.233(q).
(ix) For facilities in onshore petroleum and natural gas production
and onshore petroleum and natural gas gathering and boosting, report
the number of major equipment (as listed in table W-1 to this subpart)
in vacuum service as defined in Sec. 98.238.
(2) You must indicate whether your facility contains any of the
component types subject to or complying with Sec. 98.233(q) that are
listed in Sec. 98.232(c)(21), (d)(7), (e)(7) or (8), (f)(5) through
(8), (g)(4), (g)(6) or (7), (h)(5), (h)(7) or (8), (i)(1), (j)(10),
(m)(3)(ii) or (m)(4)(ii) for your facility's industry segment. For each
component type and leak detection method combination that is located at
your well-pad site, gathering and boosting site, or facility, you must
report the information specified in paragraphs (q)(2)(i) through (ix)
of this section. If a component type is located at your well-pad site,
gathering and boosting site, or facility
[[Page 42315]]
and no leaks were identified from that component, then you must report
the information in paragraphs (q)(2)(i) through (ix) of this section
but report a zero (``0'') for the information required according to
paragraphs (q)(2)(vi) through (ix) of this section. If you used
Calculation Method 1 (leaker factor emission calculation methodology)
for some complete leak surveys and used Calculation Method 2 (leaker
measurement methodology) for some complete leak surveys, you must
report the information specified in paragraphs (q)(2)(i) through (ix)
of this section separately for component surveys using Calculation
Method 1 and Calculation Method 2.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) Component type.
(iii) Leak detection method used for the screening survey (e.g.,
Method 21 as specified in Sec. 98.234(a)(2)(i); Method 21 as specified
in Sec. 98.234(a)(2)(ii); and OGI and other leak detection methods as
specified in Sec. 98.234(a)(1), (3), or (5)).
(iv) Emission factor or measurement method used (e.g., default
emission factor; site-specific emission factor developed according to
Sec. 98.233(q)(4); or direct measurement according to Sec.
98.233(q)(3)).
(v) Total number of components surveyed by type and leak detection
method in the calendar year.
(vi) Total number of the surveyed component types by leak detection
method that were identified as leaking in the calendar year (``xp'' in
equation W-30 to Sec. 98.233 for the component type or the number of
leaks measured for the specified component type according to the
provisions in Sec. 98.233(q)(3)).
(vii) Average time the surveyed components are assumed to be
leaking and operational, in hours (average of ``Tp,z'' from
equation W-30 to Sec. 98.233 for the component type or average
duration of leaks for the specified component type determined according
to the provisions in Sec. 98.233(q)(3)(ii)).
(viii) Annual CO2 emissions, in metric tons
CO2, for the component type as calculated using equation W-
30 to Sec. 98.233 or Sec. 98.233(q)(3)(vii) (for surveyed components
only).
(ix) Annual CH4 emissions, in metric tons
CH4, for the component type as calculated using equation W-
30 to Sec. 98.233 or Sec. 98.233(q)(3)(vii) (for surveyed components
only).
(3) Natural gas distribution facilities with emission sources
listed in Sec. 98.232(i)(1) must also report the information specified
in paragraphs (q)(3)(i) through (viii) and, if applicable, (q)(3)(ix)
of this section.
(i) Number of above grade transmission-distribution transfer
stations surveyed in the calendar year.
(ii) Number of meter/regulator runs at above grade transmission-
distribution transfer stations surveyed in the calendar year
(``CountMR,y'' from equation W-31 to Sec. 98.233, for the
current calendar year).
(iii) Average time that meter/regulator runs surveyed in the
calendar year were operational, in hours (average of
``Tw,y'' from equation W-31 to Sec. 98.233, for the current
calendar year).
(iv) Number of above grade transmission-distribution transfer
stations surveyed in the current leak survey cycle.
(v) Number of meter/regulator runs at above grade transmission-
distribution transfer stations surveyed in current leak survey cycle
(sum of ``CountMR,y'' from equation W-31 to Sec. 98.233,
for all calendar years in the current leak survey cycle).
(vi) Average time that meter/regulator runs surveyed in the current
leak survey cycle were operational, in hours (average of
``Tw,y'' from equation W-31 to Sec. 98.233, for all years
included in the leak survey cycle).
(vii) Meter/regulator run CO2 emission factor based on
all surveyed transmission-distribution transfer stations in the current
leak survey cycle, in standard cubic feet of CO2 per
operational hour of all meter/regulator runs (``EFs,MR,i''
for CO2 calculated using equation W-31 to Sec. 98.233).
(viii) Meter/regulator run CH4 emission factor based on
all surveyed transmission-distribution transfer stations in the current
leak survey cycle, in standard cubic feet of CH4 per
operational hour of all meter/regulator runs (``EFs,MR,i''
for CH4 calculated using equation W-31 to Sec. 98.233).
(ix) If your natural gas distribution facility performs equipment
leak surveys across a multiple year leak survey cycle, you must also
report:
(A) The total number of meter/regulator runs at above grade
transmission-distribution transfer stations at your facility
(``CountMR'' in equation W-32B to Sec. 98.233).
(B) Average estimated time that each meter/regulator run at above
grade transmission-distribution transfer stations was operational in
the calendar year, in hours per meter/regulator run
(``Tw,avg'' in equation W-32B to Sec. 98.233).
(C) Annual CO2 emissions, in metric tons CO2,
for all above grade transmission-distribution transfer stations at your
facility.
(D) Annual CH4 emissions, in metric tons CH4,
for all above grade transmission-distribution transfer stations at your
facility.
(r) Equipment leaks by population count. If your facility is
subject to the requirements of Sec. 98.233(r), then you must report
the information specified in paragraphs (r)(1) through (3) of this
section, as applicable. You must report the information specified in
paragraphs (r)(1) through (3) of this section, as applicable, for each
well-pad site (for onshore petroleum and natural gas production),
gathering and boosting site (for onshore petroleum and natural gas
gathering and boosting), or facility (for all other applicable industry
segments).
(1) You must indicate whether your facility contains any of the
emission source types required to use equation W-32A to Sec. 98.233.
You must report the information specified in paragraphs (r)(1)(i)
through (vi) of this section separately for each emission source type
required to use equation W-32A to Sec. 98.233 that is located at your
facility. For each well-pad site and gathering and boosting site at
onshore petroleum and natural gas production facilities and onshore
petroleum and natural gas gathering and boosting facilities, you must
report the information specified in paragraphs (r)(1)(i) through (vi)
of this section separately by equipment type and service type.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) Emission source type. Onshore petroleum and natural gas
production facilities and onshore petroleum and natural gas gathering
and boosting facilities must report the equipment type and service
type.
(iii) Total number of the emission source type at the well-pad
site, gathering and boosting site, or facility, as applicable
(``Counte'' in equation W-32A to Sec. 98.233).
(iv) Average estimated time that the emission source type was
operational in the calendar year, in hours (``Te'' in
equation W-32A to Sec. 98.233).
(v) Annual CO2 emissions, in metric tons CO2,
for the emission source type.
(vi) Annual CH4 emissions, in metric tons
CH4, for the emission source type.
(2) Natural gas distribution facilities must also report the
information specified in paragraphs (r)(2)(i) through (v) of this
section.
[[Page 42316]]
(i) Number of above grade transmission-distribution transfer
stations at the facility.
(ii) Number of above grade metering-regulating stations that are
not transmission-distribution transfer stations at the facility.
(iii) Total number of meter/regulator runs at above grade metering-
regulating stations that are not above grade transmission-distribution
transfer stations (``CountMR'' in equation W-32B to Sec.
98.233).
(iv) Average estimated time that each meter/regulator run at above
grade metering-regulating stations that are not above grade
transmission-distribution transfer stations was operational in the
calendar year, in hours per meter/regulator run (``Tw,avg''
in equation W-32B to Sec. 98.233).
(v) If your facility has above grade metering-regulating stations
that are not above grade transmission-distribution transfer stations
and your facility also has above grade transmission-distribution
transfer stations, you must also report:
(A) Annual CO2 emissions, in metric tons CO2,
from above grade metering-regulating stations that are not above grade
transmission-distribution transfer stations.
(B) Annual CH4 emissions, in metric tons CH4,
from above grade metering regulating stations that are not above grade
transmission-distribution transfer stations.
(3) You must indicate whether your facility contains any emission
source types in vacuum service as defined in Sec. 98.238. If your
facility contains equipment in vacuum service, you must report the
information specified in paragraphs (r)(3)(i) through (iii) of this
section separately for each emission source type in vacuum service that
is located at your well-pad site, gathering and boosting site, or
facility, as applicable.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) Emission source type.
(iii) Total number of the emission source type at the well-pad
site, gathering and boosting site, or facility, as applicable.
(s) Offshore petroleum and natural gas production. You must report
the information specified in paragraphs (s)(1) through (3) of this
section for your facility.
(1) The BOEM Facility ID(s) that correspond(s) to your facility, if
applicable.
(2) If you adjusted emissions according to Sec. 98.233(s)(1)(ii)
or (s)(2)(ii), report the information specified in paragraphs (s)(2)(i)
and (ii) of this section.
(i) Facility operating hours for the year of the most recent
emissions calculated according to Sec. 98.233(s)(1)(ii) or Sec.
98.233(s)(2)(ii) prior to the current reporting year.
(ii) Facility operating hours for the current reporting year.
(3) For each emission source type listed in the most recent
monitoring and calculation methods published by BOEM as referenced in
30 CFR 550.302 through 304, report the information specified in
paragraphs (s)(3)(i) through (iii) of this section.
(i) Annual CO2 emissions, in metric tons CO2.
(ii) Annual CH4 emissions, in metric tons
CH4.
(iii) Annual N2O emissions, in metric tons
N2O.
(t) [Reserved]
(u) [Reserved]
(v) [Reserved]
(w) EOR injection pumps. You must indicate whether CO2
EOR injection was used at your facility during the calendar year and if
any EOR injection pump blowdowns occurred during the year. If any EOR
injection pump blowdowns occurred during the calendar year, then you
must report the information specified in paragraphs (w)(1) through (8)
of this section for each EOR injection pump system.
(1) Sub-basin ID.
(2) EOR injection pump system identifier.
(3) Pump capacity, in barrels per day.
(4) Total volume of EOR injection pump system equipment chambers,
in cubic feet (``Vv'' in equation W-37 to Sec. 98.233).
(5) Number of blowdowns for the EOR injection pump system in the
calendar year.
(6) Density of critical phase EOR injection gas, in kilograms per
cubic foot (``Rc'' in equation W-37 to Sec. 98.233).
(7) Mass fraction of CO2 in critical phase EOR injection
gas (``GHGCO2'' in equation W-37 to Sec. 98.233).
(8) Annual CO2 emissions, in metric tons CO2,
from EOR injection pump system blowdowns.
(x) EOR hydrocarbon liquids. You must indicate whether hydrocarbon
liquids were produced through EOR operations. If hydrocarbon liquids
were produced through EOR operations, you must report the information
specified in paragraphs (x)(1) through (4) of this section for each
sub-basin category with EOR operations.
(1) Sub-basin ID.
(2) Total volume of hydrocarbon liquids produced through EOR
operations in the calendar year, in barrels (``Vhl'' in
equation W-38 to Sec. 98.233).
(3) Average CO2 retained in hydrocarbon liquids
downstream of the storage tank, in metric tons per barrel under
standard conditions (``Shl'' in equation W-38 to Sec.
98.233).
(4) Annual CO2 emissions, in metric tons CO2,
from CO2 retained in hydrocarbon liquids produced through
EOR operations downstream of the storage tank (``MassCO2''
in equation W-38 to Sec. 98.233).
(y) Other large release events. You must indicate whether there
were any other large release events from your facility during the
reporting year and indicate whether your facility was notified of a
potential super-emitter release under the provisions of Sec. 60.5371,
60.5371a, or 60.5371b of this chapter or an applicable approved state
plan or applicable Federal plan in part 62 of this chapter. If there
were any other large release events, you must report the total number
of other large release events from your facility that occurred during
the reporting year and, for each other large release event, report the
information specified in paragraphs (y)(1) through (10) of this
section. If you received a super-emitter release notification under the
provisions of Sec. 60.5371, 60.5371a, or 60.5371b of this chapter or
an applicable approved state plan or applicable Federal plan in part 62
of this chapter that the EPA has not determined to contain a
demonstrable error according to the provisions in Sec. 98.233(y)(6),
you must include the emissions from that source or event within your
subpart W report unless you can provide certification that the facility
does not own or operate the equipment at the location identified in the
notification using the methods specified in Sec. 98.233(y)(6).
Regardless, if you received a super-emitter release notification under
the provisions of Sec. Sec. 60.5371, 60.5371a, or 60.5371b of this
chapter or an applicable approved state plan or applicable Federal plan
in part 62 of this chapter, you must also report the information
specified in paragraph (y)(11) of this section.
(1) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(2) Unique release event identification number (e.g., Event 1,
Event 2).
(3) The latitude and longitude of the release in decimal degrees to
at least
[[Page 42317]]
four digits to the right of the decimal point.
(4) The approximate start date, start time, and duration (in hours)
of the release event, and an indication of how the start date and time
were determined (determined based on pressure monitor, temperature
monitor, other monitored process parameter (specify), assigned based on
last monitoring or measurement survey showing no large release (specify
monitoring or measurement survey method), or used the 91-day default
start date).
(5) A general description of the event. Include:
(i) Identification of the equipment involved in the release.
(ii) A description of how the release occurred, from one of the
following categories: maintenance event, fire/explosion, gas well
blowout, oil well blowout, gas well release, oil well release, pressure
relief, large leak, and other (specify).
(iii) An indication of whether the release exceeded a threshold in
Sec. 98.233(y)(1)(i) or in Sec. 98.233(y)(1)(ii).
(iv) A description of the technology or method used to identify the
release.
(v) An indication of whether the release was identified under the
provisions of Sec. 60.5371, 60.5371a, or 60.5371b of this chapter or
an applicable approved state plan or applicable Federal plan in part 62
of this chapter and, if the release was identified under the provisions
of Sec. Sec. 60.5371, 60.5371a, or 60.5371b of this chapter or an
applicable approved state plan or applicable Federal plan in part 62 of
this chapter, a unique notification ID number for the notification as
assigned in paragraph (y)(11)(i) of this section.
(vi) An indication of whether a portion of the natural gas released
was combusted during the release, and if so, the fraction of the
natural gas released that was estimated to be combusted and the assumed
combustion efficiency for the combusted natural gas.
(6) The total volume of gas released during the event in standard
cubic feet.
(7) The volume fraction of CO2 in the gas released
during the event.
(8) The volume fraction of CH4 in the gas released
during the event.
(9) Annual CO2 emissions, in metric tons CO2,
from the release event that occurred during the reporting year.
(10) Annual CH4 emissions, in metric tons
CH4, from the release event that occurred during the
reporting year and the maximum CH4 emissions rate, in
kilograms per hour, determined for any period of the event according to
the provisions Sec. 98.233(y)(2)(i).
(11) Report the total number of super-emitter release notifications
received from the EPA under the provisions of Sec. Sec. 60.5371,
60.5371a, or 60.5371b of this chapter or an applicable approved state
plan or applicable Federal plan in part 62 of this chapter for this
facility for events that occurred during the reporting year that were
not determined by the EPA to have a demonstratable error in the
notification and, for each such super-emitter release notification,
report the information specified in paragraphs (y)(11)(i) through (v)
of this section.
(i) Unique notification identification number (e.g.,
Notification_01, Notification_02). If a unique notification number was
provided with a notification received under the provisions of Sec.
60.5371, 60.5371a, or 60.5371b of this chapter, an applicable approved
state plan, or applicable Federal plan in part 62 of this chapter,
report the number associated with the event provided in the
notification.
(ii) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only) to which the notification was attributed.
(iii) Based on any assessment or investigation triggered by the
notification, indicate if the emissions were from normal operations, a
planned maintenance event, leaking equipment, malfunctioning equipment
or device, or undetermined cause.
(iv) An indication of whether the emissions identified via the
notification are included in annual emissions reported under this
subpart and, if so, the source type under which the emissions
identified via the notification are reported (from the list of source
types required to be reported as specified in Sec. 98.232 for the
facility's applicable industry segment). If the emissions were reported
following the requirements of Sec. 98.233(y) as an other large release
event, report the unique release event identification number assigned
to the other large release event as reported in paragraph (y)(2) of
this section. If the emissions identified via the notification are not
included in the annual emissions reported under this subpart, you must
provide certification that the facility does not own or operate the
equipment at the location identified in the notification as specified
in Sec. 98.233(y)(6)(i) or provide certification that the facility
conducted a complete investigation of the site as specified in Sec.
98.233(y)(6)(ii) and does not own or operate the emitting equipment at
the location identified in the notification.
(v) Provide an indication if you received a super-emitter release
notification from the EPA after December 31 of the reporting year for
which investigations are on-going such that the annual report that has
been submitted may be revised and resubmitted pending the outcome of
the super-emitter investigation.
(z) Combustion equipment. If your facility is required by Sec.
98.232(c)(22), (i)(7), or (j)(12) to report emissions from combustion
equipment, then you must indicate whether your facility has any
combustion units subject to reporting according to paragraph
(a)(1)(xx), (a)(8)(vi), or (a)(9)(xiii) of this section. If your
facility contains any combustion units subject to reporting according
to paragraph (a)(1)(xx), (a)(8)(vi), or (a)(9)(xiii) of this section,
then you must report the information specified in paragraphs (z)(1) and
(2) of this section, as applicable. You must report the information
specified in paragraphs (z)(1) and (2) of this section, as applicable,
for each well-pad site (for onshore petroleum and natural gas
production), gathering and boosting site (for onshore petroleum and
natural gas gathering and boosting), or facility (for all other
applicable industry segments).
(1) Indicate whether the combustion units include: External fuel
combustion units with a rated heat capacity less than or equal to 5
million Btu per hour; or, internal fuel combustion units that are not
compressor-drivers, with a rated heat capacity less than or equal to 1
mmBtu/hr (or the equivalent of 130 horsepower). If the facility
contains external fuel combustion units with a rated heat capacity less
than or equal to 5 million Btu per hour or internal fuel combustion
units that are not compressor-drivers, with a rated heat capacity less
than or equal to 1 million Btu per hour (or the equivalent of 130
horsepower), then you must report the information specified in
paragraphs (z)(1)(i) through (iii) of this section for each unit type.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) The type of combustion unit.
(iii) The total number of combustion units.
(2) Indicate whether the combustion units include: External fuel
combustion units with a rated heat capacity greater than 5 million Btu
per hour; internal fuel combustion units that are not compressor-
drivers, with a rated heat capacity greater than 1 million Btu per hour
(or the equivalent of 130
[[Page 42318]]
horsepower); or, internal fuel combustion units of any heat capacity
that are compressor-drivers. For each type of combustion unit at your
facility, you must report the information specified in paragraphs
(z)(2)(i) through (iv) and (z)(2)(viii) through (x) of this section,
except for internal fuel combustion units that are not compressor-
drivers, with a rated heat capacity greater than 1 million Btu per hour
(or the equivalent of 130 horsepower) or internal fuel combustion units
of any heat capacity that are compressor-drivers that combust natural
gas meeting the criteria in Sec. 98.233(z), which must report the
information specified in paragraphs (z)(2)(i) through (x) of this
section. Information must be reported for each combustion unit type,
fuel type, and method for determining the CH4 emission
factor combination, as applicable.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) The type of combustion unit including external fuel combustion
units with a rated heat capacity greater than 5 million Btu per hour;
internal fuel combustion units that are not compressor-drivers, with a
rated heat capacity greater than 1 million Btu per hour (or the
equivalent of 130 horsepower); or internal fuel combustion units of any
heat capacity that are compressor-drivers.
(iii) The type of fuel combusted.
(iv) The quantity of fuel combusted in the calendar year, in
thousand standard cubic feet, gallons, or tons.
(v) The equipment type, including reciprocating 2-stroke-lean burn,
reciprocating 4-stroke lean-burn, reciprocating 4-stroke rich-burn, and
gas turbine.
(vi) The method used to determine the methane emission factor,
including the default emission factor from table W-7 to this subpart,
OEM data, or performance tests in Sec. 98.234(i) for natural gas
described in Sec. 98.233(z)(1) or (2), or performance tests in Sec.
98.234(i) or default combustion efficiency for fuels described in
section Sec. 98.233(z)(3).
(vii) The value of the CH4 emission factor (kg
CH4/mmBtu). If multiple performance tests were performed in
the same reporting year, the arithmetic average value of CH4
emission factor (kg CH4/mmBtu). This information is not
required if CH4 emissions were calculated per Sec.
98.233(z)(3)(ii)(D).
(viii) Annual CO2 emissions, in metric tons
CO2, calculated according to Sec. 98.233(z)(1) through (3).
(ix) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec. 98.233(z)(1) through (3).
(x) Annual N2O emissions, in metric tons N2O,
calculated according to Sec. 98.233(z)(1) through (3).
(aa) Industry segment-specific information. Each facility must
report the information specified in paragraphs (aa)(1) through (11) of
this section, for each applicable industry segment, determined using a
flow meter that meets the requirements of Sec. 98.234(b) for
quantities that are sent to sale or through the facility and determined
by using best available data for other quantities. If a quantity
required to be reported is zero, you must report zero as the value.
(1) For onshore petroleum and natural gas production, report the
data specified in paragraphs (aa)(1)(i) and (iv) of this section.
(i) Report the information specified in paragraphs (aa)(1)(i)(A)
through (C) of this section for the basin as a whole, unless otherwise
specified.
(A) The quantity of gas produced in the calendar year from wells,
in thousand standard cubic feet. This includes gas that is routed to a
pipeline, vented or flared, or used in field operations. This does not
include gas injected back into reservoirs or shrinkage resulting from
lease condensate production.
(B) The quantity of natural gas produced from producing wells that
is sent to sale in the calendar year, in thousand standard cubic feet.
(C) The quantity of crude oil and condensate produced from
producing wells that is sent to sale in the calendar year, in barrels.
(ii) Report the information specified in paragraphs (aa)(1)(ii)(A)
through (M) of this section for each unique sub-basin category.
(A) State.
(B) County.
(C) Formation type.
(D) The number of producing wells at the end of the calendar year
(exclude only those wells permanently shut-in and plugged).
(E) The number of producing wells acquired during the calendar
year.
(F) The number of producing wells divested during the calendar
year.
(G) The number of wells completed during the calendar year.
(H) The number of wells permanently shut-in and plugged during the
calendar year.
(I) Average mole fraction of CH4 in produced gas.
(J) Average mole fraction of CO2 in produced gas.
(K) If an oil sub-basin, report the average GOR of all wells, in
thousand standard cubic feet per barrel.
(L) If an oil sub-basin, report the average API gravity of all
wells.
(M) If an oil sub-basin, report average low pressure separator
pressure, in pounds per square inch gauge.
(iii) Report the information specified in paragraphs
(aa)(1)(iii)(A) through (D) of this section for each well located in
the facility.
(A) Well ID number.
(B) Well-pad ID.
(C) For each well permanently shut-in and plugged during the
calendar year, the quantity of natural gas produced that is sent to
sale in the calendar year, in thousand standard cubic feet.
(D) For each well permanently shut-in and plugged during the
calendar year, the quantity of crude oil and condensate produced that
is sent to sale in the calendar year, in barrels.
(iv) Report the information specified in paragraphs (aa)(1)(iv)(A)
through (C) of this section for each well-pad site located in the
facility.
(A) A unique name or ID number for the well-pad.
(B) Sub-basin ID.
(C) The latitude and longitude of the well-pad representing the
geographic centroid or center point of the well-pad in decimal degrees
to at least four digits to the right of the decimal point.
(2) For offshore production, report the quantities specified in
paragraphs (aa)(2)(i) through (iv) of this section.
(i) The quantity of natural gas produced from producing wells that
is sent to sale in the calendar year, in thousand standard cubic feet.
(ii) The quantity of crude oil and condensate produced from
producing wells that is sent to sale in the calendar year, in barrels.
(iii) For each well permanently shut-in and plugged during the
calendar year, the quantity of natural gas produced that is sent to
sale in the calendar year, in thousand standard cubic feet.
(iv) For each well permanently shut-in and plugged during the
calendar year, the quantity of crude oil and condensate produced that
is sent to sale in the calendar year, in barrels.
(3) For natural gas processing, if your facility fractionates NGLs
and also reported as a supplier to subpart NN of this part, you must
report the information specified in paragraphs (aa)(3)(ii) and
(aa)(3)(v) through (ix) of this section. Otherwise, report the
information specified in paragraphs (aa)(3)(i) through (ix) of this
section.
(i) The quantity of natural gas received at the gas processing
plant for processing in the calendar year, in thousand standard cubic
feet.
[[Page 42319]]
(ii) The quantity of processed (residue) gas leaving the gas
processing plant in the calendar year, in thousand standard cubic feet.
(iii) The cumulative quantity of all NGLs (bulk and fractionated)
received at the gas processing plant in the calendar year, in barrels.
(iv) The cumulative quantity of all NGLs (bulk and fractionated)
leaving the gas processing plant in the calendar year, in barrels.
(v) Average mole fraction of CH4 in natural gas
received.
(vi) Average mole fraction of CO2 in natural gas
received.
(vii) Indicate whether the facility fractionates NGLs.
(viii) Indicate whether the facility reported as a supplier to
subpart NN of this part under the same e-GGRT identification number in
the calendar year.
(ix) The quantity of residue gas leaving that has been processed by
the facility and any gas that passes through the facility to sales
without being processed by the facility.
(4) For natural gas transmission compression, report the quantity
specified in paragraphs (aa)(4)(i) through (v) of this section.
(i) The quantity of natural gas transported through the compressor
station in the calendar year, in thousand standard cubic feet.
(ii) Number of compressors.
(iii) Total compressor power rating of all compressors combined, in
horsepower.
(iv) Average upstream pipeline pressure, in pounds per square inch
gauge.
(v) Average downstream pipeline pressure, in pounds per square inch
gauge.
(5) For underground natural gas storage, report the quantities
specified in paragraphs (aa)(5)(i) through (iii) of this section.
(i) The quantity of gas injected into storage in the calendar year,
in thousand standard cubic feet.
(ii) The quantity of natural gas withdrawn from storage and sent to
sale in the calendar year, in thousand standard cubic feet.
(iii) Total storage capacity, in thousand standard cubic feet.
(6) For LNG import equipment, report the quantity of LNG imported
that is sent to sale in the calendar year, in thousand standard cubic
feet.
(7) For LNG export equipment, report the quantity of LNG exported
that is sent to sale in the calendar year, in thousand standard cubic
feet.
(8) For LNG storage, report the quantities specified in paragraphs
(aa)(8)(i) through (iii) of this section.
(i) The quantity of LNG added into storage in the calendar year, in
thousand standard cubic feet.
(ii) The quantity of LNG withdrawn from storage and sent to sale in
the calendar year, in thousand standard cubic feet.
(iii) Total storage capacity, in thousand standard cubic feet.
(9) [Reserved]
(10) For onshore petroleum and natural gas gathering and boosting
facilities, report the quantities specified in paragraphs (aa)(10)(i)
through (v) of this section.
(i) The quantity of gas received by the gathering and boosting
facility in the calendar year, in thousand standard cubic feet.
(ii) The quantity of natural gas transported from the gathering and
boosting facility in the calendar year, in thousand standard cubic
feet.
(iii) The quantity of all hydrocarbon liquids received by the
gathering and boosting facility in the calendar year, in barrels.
(iv) The quantity of all hydrocarbon liquids transported from the
gathering and boosting facility in the calendar year, in barrels.
(v) Report the information specified in paragraphs (aa)(10)(v)(A)
through (E) of this section for each gathering and boosting site
located in the facility for which there were emissions in the calendar
year.
(A) A unique name or ID number for the gathering and boosting site.
(B) Gathering and boosting site type (gathering compressor station,
centralized oil production site, gathering pipeline, or other fence-
line site).
(C) State.
(D) For gathering compressor stations, centralized oil production
sites, and other fence-line sites, county.
(E) For gathering compressor stations, centralized oil production
sites, and other fence-line sites, the latitude and longitude of the
gathering and boosting site representing the geographic centroid or
center point of the site in decimal degrees to at least four digits to
the right of the decimal point.
(11) For onshore natural gas transmission pipeline facilities,
report the quantities specified in paragraphs (aa)(11)(i) through (vi)
of this section.
(i) The quantity of natural gas received at all custody transfer
stations in the calendar year, in thousand standard cubic feet. This
value may include meter corrections, but only for the calendar year
covered by the annual report.
(ii) The quantity of natural gas withdrawn from underground natural
gas storage and LNG storage (regasification) facilities owned and
operated by the onshore natural gas transmission pipeline owner or
operator that are not subject to this subpart in the calendar year, in
thousand standard cubic feet.
(iii) The quantity of natural gas added to underground natural gas
storage and LNG storage (liquefied) facilities owned and operated by
the onshore natural gas transmission pipeline owner or operator that
are not subject to this subpart in the calendar year, in thousand
standard cubic feet.
(iv) The quantity of natural gas transported through the facility
and transferred to third parties such as LDCs or other transmission
pipelines, in thousand standard cubic feet.
(v) The quantity of natural gas consumed by the transmission
pipeline facility for operational purposes, in thousand standard cubic
feet.
(vi) The miles of transmission pipeline for each state in the
facility.
(bb) Missing data. For any missing data procedures used, report the
information in Sec. 98.3(c)(8) and the procedures used to substitute
an unavailable value of a parameter, except as provided in paragraphs
(bb)(1) and (2) of this section.
(1) For quarterly measurements, report the total number of quarters
that a missing data procedure was used for each data element rather
than the total number of hours.
(2) For annual or biannual (once every two years) measurements, you
do not need to report the number of hours that a missing data procedure
was used for each data element.
(cc) Delay in reporting for wildcat wells and delineation wells. If
you elect to delay reporting the information in paragraph (g)(5)(i) or
(ii), (g)(5)(iii)(A) or (B), (h)(1)(iv), (h)(2)(iv), (j)(1)(iii),
(j)(2)(i)(A), (l)(1)(v), (l)(2)(v), (l)(3)(iv), (l)(4)(iv), (m)(5) or
(6), (dd)(1)(iii), (dd)(1)(vi)(A), (B), or (C), (dd)(3)(iii)(A), or
(dd)(3)(iii)(D)(1), (2), or (3) of this section, you must report the
information required in that paragraph no later than the date 2 years
following the date specified in Sec. 98.3(b) introductory text.
(dd) Drilling mud degassing. You must indicate whether there were
mud degassing operations at your facility, and if so, which methods (as
specified in Sec. 98.233(dd)) were used to calculate emissions. For
wells for which your facility performed mud degassing operations and
used Calculation Method 1, then you must report the information
specified in paragraph (dd)(1) of this section. For wells for which
your facility performed mud degassing operations and used Calculation
Method
[[Page 42320]]
2, then you must report the information specified in paragraph (dd)(2)
of this section. For wells for which your facility performed mud
degassing operations and used Calculation Method 3, then you must
report the information specified in paragraph (dd)(3) of this section.
(1) For each well for which you used Calculation Method 1 to
calculate natural gas emissions from mud degassing, report the
information specified in paragraphs (dd)(1)(i) through (viii) of this
section.
(i) Well ID number.
(ii) Approximate total depth below surface, in feet.
(iii) Target hydrocarbon-bearing stratigraphic formation to which
the well is drilled.
(iv) Total time that drilling mud is circulated in the well
(Tr in equation W-41 to Sec. 98.233 and Tp in
equation W-43 to Sec. 98.233), in minutes, beginning with initial
penetration of the first hydrocarbon-bearing zone until drilling mud
ceases to be circulated in the wellbore. You may delay reporting of
this data element for a representative well if you indicate in the
annual report that one or more wells to which the calculated
CH4 emissions rate for the representative well
(ERs,CH4,r in equation W-42 to Sec. 98.233) is applied is a
wildcat well or delineation well. You may delay reporting of this data
element for any well if you indicate in the annual report that the well
is a wildcat or delineation well. If you elect to delay reporting of
this data element, you must report by the date specified in paragraph
(cc) of this section the total time that drilling mud is circulated in
the well, in minutes.
(v) The composition of the drilling mud: water-based, oil-based, or
synthetic.
(vi) If the well is not a representative well, Well ID number of
the representative well used to derive the CH4 emission rate
used to calculate CH4 emissions for this well.
(vii) If the well is a representative well, report the information
specified in paragraphs (dd)(1)(vi)(A) through (D) of this section.
(A) Average mud rate (MRr in equation W-41 to Sec.
98.233), in gallons per minute. You may delay reporting of this data
element if you indicate in the annual report that one or more wells to
which the calculated CH4 emissions rate for the
representative well (ERs,CH4,r in equation W-42 to Sec.
98.233) is applied is a wildcat well or delineation well. If you elect
to delay reporting of this data element, you must report by the date
specified in paragraph (cc) of this section the average mud rate, in
gallons per minute.
(B) Average concentration of natural gas in the drilling mud
(Xn in equation W-41 to Sec. 98.233), in parts per million.
You may delay reporting of this data element if you indicate in the
annual report that the well is a wildcat well or delineation well. If
you elect to delay reporting of this data element, you must report by
the date specified in paragraph (cc) of this section the average
concentration of natural gas in the drilling mud in parts per million.
(C) Measured mole fraction for CH4 in natural gas
entrained in the drilling mud (GHGCH4 in equation W-41 to
Sec. 98.233). You may delay reporting of this data element if you
indicate in the annual report that the well is a wildcat well or
delineation well. If you elect to delay reporting of this data element,
you must report by the date specified in paragraph (cc) of this section
the measured mole fraction for CH4 in natural gas entrained
in the drilling mud.
(D) Calculated CH4 emissions rate in standard cubic feet
per minute (ERs,CH4,r in equation W-42 to Sec. 98.233). You
may delay reporting of this data element if you indicate in the annual
report that that one or more wells to which the calculated
CH4 emissions rate for the representative well
(ERs,CH4,r in equation W-42 to Sec. 98.233) is applied is a
wildcat or delineation well. If you elect to delay reporting of this
data element, you must report by the date specified in paragraph (cc)
of this section the calculated CH4 emissions rate in
standard cubic feet per minute.
(viii) Annual CH4 emissions, in metric tons
CH4, from well drilling mud degassing, calculated according
to Sec. 98.233(dd)(1).
(2) For each well for which you used Calculation Method 2 to
calculate natural gas emissions from mud degassing, report the
information specified in paragraphs (dd)(2)(i) through (iv) of this
section.
(i) Well ID number.
(ii) Total number of drilling days (DDp in equation W-44
to Sec. 98.233).
(iii) The composition of the drilling mud: water-based, oil-based,
or synthetic.
(iv) Annual CH4 emissions, in metric tons
CH4, from drilling mud degassing, calculated according to
Sec. 98.233(dd)(2).
(3) For each well for which you used Calculation Method 3 to
calculate natural gas emissions from mud degassing, report the
information specified in paragraphs (dd)(3)(i) through (iv) of this
section.
(i) Well ID number.
(ii) For the time periods you used Calculation Method 1 to
calculate natural gas emissions from mud degassing, report the
information specified in paragraphs (dd)(3)(ii)(A) through (G) of this
section.
(A) Approximate total depth below surface, in feet.
(B) Target hydrocarbon-bearing stratigraphic formation to which the
well is drilled.
(C) Total time that drilling mud is circulated in the well
(Tr in equation W-41 to Sec. 98.233 and Tp in
equation W-43 to Sec. 98.233), in minutes, beginning with initial
penetration of the first hydrocarbon-bearing zone until drilling mud
ceases to be circulated in the wellbore. You may delay reporting of
this data element for a representative well if you indicate in the
annual report that that one or more wells to which the calculated
CH4 emissions rate for the representative well
(ERs,CH4,r in equation W-42 to Sec. 98.233) is applied is a
wildcat well or delineation well. You may delay reporting of this data
element for any well if you indicate in the annual report that the well
is a wildcat well or delineation well. If you elect to delay reporting
of this data element, you must report by the date specified in
paragraph (cc) of this section the total time that drilling mud is
circulated in the well, in minutes.
(D) The composition of the drilling mud: water-based, oil-based, or
synthetic.
(E) If the well is not a representative well, Well ID number of the
representative well used to derive the CH4 emission rate
used to calculate CH4 emissions for this well.
(F) If the well is a representative well, report the information
specified in paragraphs (dd)(3)(ii)(F)(1) through (4) of this section.
(1) Average mud rate (MRr in equation W-41 to Sec.
98.233), in gallons per minute. You may delay reporting of this data
element if you indicate in the annual report that one or more wells to
which the calculated CH4 emissions rate for the
representative well (ERs,CH4,r in equation W-42 to Sec.
98.233) is applied is a wildcat well or delineation well. If you elect
to delay reporting of this data element, you must report by the date
specified in paragraph (cc) of this section the average mud rate, in
gallons per minute.
(2) Average concentration of natural gas in the drilling mud
(Xn in equation W-41 to Sec. 98.233), in parts per million.
You may delay reporting of this data element if you indicate in the
annual report that the well is a wildcat well or delineation well. If
you elect to delay reporting of this data element, you must
[[Page 42321]]
report by the date specified in paragraph (cc) of this section the
average concentration of natural gas in the drilling mud in parts per
million.
(3) Measured mole fraction for CH4 in natural gas
entrained in the drilling mud (GHGCH4 in equation W-41 to
Sec. 98.233). You may delay reporting of this data element if you
indicate in the annual report that the well is a wildcat well or
delineation well. If you elect to delay reporting of this data element,
you must report by the date specified in paragraph (cc) of this section
the measured mole fraction for CH4 in natural gas entrained
in the drilling mud.
(4) Calculated CH4 emissions rate in standard cubic feet
per minute (ERs,CH4,r in equation W-42 to Sec. 98.233). You
may delay reporting of this data element if you indicate in the annual
report that one or more wells to which the calculated CH4
emissions rate for the representative well (ERs,CH4,r in
equation W-42 to Sec. 98.233) is applied is a wildcat well or
delineation well. If you elect to delay reporting of this data element,
you must report by the date specified in paragraph (cc) of this section
the calculated CH4 emissions rate in standard cubic feet per
minute.
(G) Annual CH4 emissions, in metric tons CH4,
from well drilling mud degassing, calculated according to Sec.
98.233(dd)(1).
(iii) For the time periods for each well for which you used
Calculation Method 2 to calculate natural gas emissions from mud
degassing, report the information specified in paragraphs
(dd)(3)(iii)(A) through (C) of this section.
(A) Total number of drilling days (DDp in equation W-44
to Sec. 98.233).
(B) The composition of the drilling mud: water-based, oil-based, or
synthetic.
(C) Annual CH4 emissions, in metric tons CH4,
from drilling mud degassing, calculated according to Sec.
98.233(dd)(2).
(iv) Total annual CH4 emissions, in metric tons
CH4, from drilling mud degassing, calculated from summing
the annual CH4 emissions calculated from Sec.
98.233(dd)(3)(iii)(E) and Sec. 98.233(dd)(3)(iv)(C).
(ee) Crankcase vents. You must indicate whether your facility
performs any crankcase venting from reciprocating internal combustion
engines. For all reciprocating internal combustion engines with
crankcase vents, you must report the information specified in paragraph
(ee)(1) of this section for each well-pad site (for onshore petroleum
and natural gas production), gathering and boosting site (for onshore
petroleum and natural gas gathering and boosting), or facility (for all
other applicable industry segments). For each reciprocating internal
combustion engine that you conduct measurements as specified in Sec.
98.233(ee)(1), you must report the information specified in paragraph
(ee)(2) of this section. For reciprocating internal combustion engines
with CH4 emissions calculated as specified in Sec.
98.233(ee)(2), you must report the information specified in paragraph
(ee)(3) of this section for each well-pad site (for onshore petroleum
and natural gas production), gathering and boosting site (for onshore
petroleum and natural gas gathering and boosting), or facility (for all
other applicable industry segments).
(1) The information and number of reciprocating internal combustion
engines with crankcase vents as specified in paragraphs (ee)(1)(i)
through (v) of this section, as applicable. If a reciprocating internal
combustion engine with crankcase vents was vented directly to the
atmosphere for part of the year and routed to a flare during another
part of the year, then include the engine in each of the applicable
counts specified in paragraphs (ee)(1)(iii) and (iv) of this section.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) The total number of reciprocating internal combustion engines
with crankcase vents.
(iii) The total number of reciprocating internal combustion engines
with crankcase vents that operated and were vented directly to the
atmosphere.
(iv) The total number of reciprocating internal combustion engines
with crankcase vents that operated and were routed to a flare.
(v) The total number of reciprocating internal combustion engines
with crankcase vents that were in a manifolded group containing a
compressor vent source with emissions reported under paragraph (o) or
(p) of this section.
(2) Reciprocating internal combustion engines with crankcase vents
that calculate emissions according to Sec. 98.233(ee)(1) must report
the information specified in paragraphs (ee)(2)(i) and (ii) of this
section, as applicable.
(i) For each measurement performed on a crankcase vent, report the
information specified in paragraphs (ee)(2)(i)(A) through (F) of this
section.
(A) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(B) Unique name or ID for the reciprocating internal combustion
engine.
(C) Measurement date.
(D) Measurement method. If emissions were not detected when using a
screening method, report the screening method. If emissions were
detected using a screening method, report only the method subsequently
used to measure the volumetric emissions.
(E) Measured flow rate, in standard cubic feet per hour.
(F) If the measurement is for a manifolded group of crankcase vent
sources, indicate the number of reciprocating internal compressor
engines that were operating during measurement.
(ii) Annual CH4 emissions from the reciprocating
internal combustion engine crankcase vent, in metric tons
CH4.
(3) Reciprocating internal combustion engines with crankcase vents
that calculate emissions according to Sec. 98.233(ee)(2) must report
the information specified in paragraphs (ee)(3)(i) through (iv) of this
section.
(i) Well-pad ID (for the onshore petroleum and natural gas
production industry segment only) or gathering and boosting site ID
(for the onshore petroleum and natural gas gathering and boosting
industry segment only).
(ii) Total number of reciprocating internal combustion engines with
crankcase vents that were operational at some point in the calendar
year at the well-pad site, gathering and boosting site, or facility, as
applicable.
(iii) Total time that the reciprocating internal combustion engines
with crankcase venting were operational in the calendar year, in hours
(``T'' in equation W-46 to Sec. 98.233).
(iv) Annual CH4 emissions, in metric tons
CH4, calculated according to Sec. 98.233(ee)(2).
0
18. Amend Sec. 98.237 by adding paragraph (g) to read as follows:
Sec. 98.237 Records that must be retained.
* * * * *
(g) For each situation when you fail to fully conform with all
cited provisions in either Sec. 98.233(n)(1)(i) or (ii) for a period
of 15 consecutive days and you utilized the Tier 3 default destruction
and combustion efficiency values, you must document these periods when
the non-conformance began, and the date when full conformance was re-
established.
0
19. Effective July 15, 2024, amend Sec. 98.238 by adding definitions
[[Page 42322]]
``Centralized oil production site,'' ``Gathering and boosting site,''
``Gathering compressor station,'' ``Gathering pipeline site,'' and
``Well-pad site'' in alphabetical order to read as follows:
Sec. 98.238 Definitions.
* * * * *
Centralized oil production site means any permanent combination of
one or more hydrocarbon liquids storage tanks located on one or more
contiguous or adjacent properties that does not also contain a
permanent combination of one or more compressors that are part of the
onshore petroleum and natural gas gathering and boosting facility that
gathers hydrocarbon liquids from multiple well-pads. A centralized oil
production site is a type of gathering and boosting site for purposes
of this subpart.
* * * * *
Gathering and boosting site means a single gathering compressor
station as defined in this section, centralized oil production site as
defined in this section, gathering pipeline site as defined in this
section, or other fence-line site within the onshore petroleum and
natural gas gathering and boosting industry segment.
* * * * *
Gathering compressor station means any permanent combination of one
or more compressors located on one or more contiguous or adjacent
properties that are part of the onshore petroleum and natural gas
gathering and boosting facility that move natural gas at increased
pressure through gathering pipelines or into or out of storage. A
gathering compressor station is a type of gathering and boosting site
for purposes of this subpart.
Gathering pipeline site means all of the gathering pipelines within
a single state. A gathering pipeline site is a type of gathering and
boosting site for purposes of this subpart.
* * * * *
Well-pad site means all equipment on or associated with a single
well-pad. Specifically, the well-pad site includes all equipment on a
single well-pad plus all equipment associated with that single well-
pad.
* * * * *
0
20. Amend Sec. 98.238 by:
0
a. Removing the definition ``Acid gas removal vent emissions'' a;
0
b. Adding definitions ``Acid gas removal unit (AGR) vent emissions,''
``Atmospheric pressure storage tank,'' and ``Automated liquids
unloading'' in alphabetical order;
0
c. Revising the definitions ``Compressor mode'' and ``Compressor
source;''
0
d. Adding definitions ``Crankcase venting,'' ``Drilling mud,''
``Drilling mud degassing,'' ``Enclosed combustion device,'' and
``Equivalent stratigraphic interval'' in alphabetical order;
0
e. Removing the second definition ``Facility with respect to natural
gas distribution for purposes of reporting under this subpart and for
the corresponding subpart A requirements'';
0
f. Revising the definitions ``Flare stack emissions'' and ``Forced
extraction of natural gas liquids'';
0
g. Revising the definitions ``Gathering and boosting system'' and
``Gathering and boosting system owner or operator''; and
0
h. Adding definitions ``In vacuum service,'' ``Manual liquids
unloading,'' ``Mud rate,'' ``Nitrogen removal unit (NRU),'' ``Nitrogen
removal unit vent emissions,'' ``Other large release event,''
``Produced water,'' ``Routed to combustion,'' ``Target hydrocarbon-
bearing stratigraphic formation,'' ``Transmission company interconnect
M&R station,'' ``Well blowout,'' and ``Well release'' in alphabetical
order.
The additions and revisions read as follows:
Sec. 98.238 Definitions.
* * * * *
Acid gas removal unit (AGR) vent emissions mean the acid gas
separated from the acid gas absorbing medium (e.g., an amine solution)
and released with methane and other light hydrocarbons to the
atmosphere.
* * * * *
Atmospheric pressure storage tank means a vessel (excluding sumps)
operating at atmospheric pressure that is designed to contain an
accumulation of crude oil, condensate, intermediate hydrocarbon
liquids, or produced water and that is constructed entirely of non-
earthen materials (e.g., wood, concrete, steel, plastic) that provide
structural support. Atmospheric pressure storage tanks include both
fixed roof tanks and floating roof tanks. Floating roof tanks include
tanks with either an internal floating roof or an external floating
roof.
Automated liquids unloading means an unloading that is performed
without manual interference. Examples of automated liquids unloadings
include a timing and/or pressure device used to optimize intermittent
shut-in of the well before liquids choke off gas flow or to open and
close valves, continually operating equipment that does not require
presence of an operator such as rod pumping units, automated and
unmanned plunger lifts, or other unloading activities that do not
entail a physical presence at the well-pad,
* * * * *
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 source means the source of certain venting or leaking
emissions from a centrifugal or reciprocating compressor. For
centrifugal compressors, ``source'' refers to blowdown valve leakage
through the blowdown vent, unit isolation valve leakage through an open
blowdown vent without blind flanges, wet seal oil degassing vents, and
dry seal vents. For reciprocating compressors, ``source'' refers to
blowdown valve leakage through the blowdown vent, unit isolation valve
leakage through an open blowdown vent without blind flanges, and rod
packing emissions.
* * * * *
Crankcase venting means the process of venting or removing blow-by
from the void spaces of an internal combustion engine outside of the
combustion cylinders to prevent excessive pressure build-up within the
engine. This does not include ingestive systems that vent blow-by into
the engine where it is returned to the combustion process (e.g., closed
crankcase ventilation system, closed breather system) or if the vent
blow-by is routed to another closed vent system.
* * * * *
Drilling mud means a mixture of clays and additives with water,
oil, or synthetic materials. While drilling, the drilling mud is
continuously pumped through the drill string and out the bit to cool
and lubricate the drill bit, and move cuttings through the wellbore to
the surface.
Drilling mud degassing means the practice of safely removing
pockets of free gas entrained in the drilling mud once it is outside of
the wellbore.
* * * * *
Enclosed combustion device means a flare that uses a closed flame.
* * * * *
Equivalent stratigraphic interval means the depth of the same
stratum of rock in the Earth's subsurface.
* * * * *
Flare stack emissions means CO2 in gas routed to a
flare, CO2 from partial combustion of hydrocarbons in gas
routed to a flare, CH4 emissions resulting from the
incomplete
[[Page 42323]]
combustion of hydrocarbons in gas routed to a flare, and N2O
resulting from operation of a flare.
Forced extraction of natural gas liquids means removal of ethane or
higher carbon number hydrocarbons existing in the vapor phase in
natural gas, by removing ethane or heavier hydrocarbons derived from
natural gas into natural gas liquids by means of a forced extraction
process. Forced extraction processes include but are not limited to
refrigeration, absorption (lean oil), cryogenic expander, and
combinations of these processes. Forced extraction does not include in
and of itself natural gas dehydration, the collection or gravity
separation of water or hydrocarbon liquids from natural gas at ambient
temperature or heated above ambient temperatures, the condensation of
water or hydrocarbon liquids through passive reduction in pressure or
temperature, a Joule-Thomson valve, a dew point depression valve, or an
isolated or standalone Joule-Thomson skid.
* * * * *
Gathering and boosting system means a single network of pipelines,
compressors and process equipment, including equipment to perform
natural gas compression, dehydration, and acid gas removal, that has
one or more connection points to gas and oil production or one or more
other gathering and boosting systems and a downstream endpoint,
typically a gas processing plant, transmission pipeline, LDC pipeline,
or other gathering and boosting system.
Gathering and boosting system owner or operator means any person
that holds a contract in which they agree to transport petroleum or
natural gas from one or more onshore petroleum and natural gas
production wells or one or more other gathering and boosting systems to
a downstream endpoint, typically a natural gas processing facility,
another gathering and boosting system, a natural gas transmission
pipeline, or a distribution pipeline, or any person responsible for
custody of the petroleum or natural gas transported.
* * * * *
In vacuum service means equipment operating at an internal pressure
which is at least 5 kilopascals (kPa) (0.7 psia) below ambient
pressure.
* * * * *
Manual liquids unloading means an unloading when field personnel
attend to the well at the well-pad, for example to manually plunge a
well at the site using a rig or other method, to open a valve to direct
flow to an atmospheric tank to clear the well, or to manually shut-in
the well to allow pressure to build in the well-bore. Manual unloadings
may be performed on a routine schedule or on ``as needed'' basis.
* * * * *
Mud rate means the pumping rate of the mud by the mud pumps,
usually measured in gallons per minute (gpm).
* * * * *
Nitrogen removal unit (NRU) means a process unit that separates
nitrogen from natural gas using various separation processes (e.g.,
cryogenic units, membrane units).
Nitrogen removal unit vent emissions means the nitrogen gas
separated from the natural gas and released with methane and other
gases to the atmosphere.
* * * * *
Other large release event means any planned or unplanned
uncontrolled release to the atmosphere of gas, liquids, or mixture
thereof, from wells and/or other equipment that result in emissions for
which there are no methodologies in Sec. 98.233 other than under Sec.
98.233(y) to appropriately estimate these emissions. Other large
release events include, but are not limited to, well blowouts, well
releases, pressure relief valve releases from process equipment other
than hydrocarbon liquids storage tanks, storage tank cleaning and other
maintenance activities, and releases that occur as a result of an
accident, equipment rupture, fire, or explosion. Other large release
events also include failure of equipment or equipment components such
that a single equipment leak or release has emissions that exceed the
emissions calculated for that source using applicable methods in Sec.
98.233(a) through (h), (j) through (s), (w), (x), (dd), or (ee) by the
threshold in Sec. 98.233(y)(1)(ii). Other large release events do not
include blowdowns for which emissions are calculated according to the
provisions in Sec. 98.233(i).
* * * * *
Produced water means the water (brine) brought up from the
hydrocarbon-bearing strata during the extraction of oil and gas, and
can include formation water, injection water, and any chemicals added
downhole or during the oil/water separation process.
* * * * *
Routed to combustion means, for onshore petroleum and natural gas
production facilities, natural gas distribution facilities, and onshore
petroleum and natural gas gathering and boosting facilities, that
emissions are routed to stationary or portable fuel combustion
equipment specified in Sec. 98.232(c)(22), (i)(7), or (j)(12), as
applicable. For all other industry segments in this subpart, routed to
combustion means that emissions are routed to a stationary fuel
combustion unit subject to subpart C of this part (General Stationary
Fuel Combustion Sources).
* * * * *
Target hydrocarbon-bearing stratigraphic formation means the
stratigraphic interval intended to be the primary hydrocarbon producing
formation.
* * * * *
Transmission company interconnect M&R station means a metering and
pressure regulating stations with an inlet pressure above 100 psig
located at a point of transmission pipeline to transmission pipeline
interconnect.
* * * * *
Well blowout means a complete loss of well control for a long
duration of time resulting in an emissions release.
* * * * *
Well release means a short duration of uncontrolled emissions
release from a well followed by a period of controlled emissions
release in which control techniques were successfully implemented.
* * * * *
0
21. Remove tables W-1A, W-1B, W-1C, W-1D, and W-1E to subpart W of part
98 and add table W-1 to subpart W of part 98 in numerical order to read
as follows:
[[Page 42324]]
Table W-1 to Subpart W of Part 98--Default Whole Gas Population Emission
Factors
------------------------------------------------------------------------
Emission factor
Industry segment Source type/component (scf whole gas/
hour/unit)
------------------------------------------------------------------------
Population Emission Factors--Pneumatic Device Vents and Pneumatic Pumps,
Gas Service \1\
------------------------------------------------------------------------
Onshore petroleum and Continuous Low Bleed 6.8
natural gas production. Pneumatic Device
Vents \2\.
Onshore petroleum and Continuous High Bleed 21
natural gas gathering and Pneumatic Device
boosting. Vents \2\.
Intermittent Bleed 8.8
Pneumatic Device
Vents \2\.
Pneumatic Pumps \3\.. 13.3
Onshore natural gas Continuous Low Bleed 6.8
processing. Pneumatic Device
Vents \2\.
Onshore natural gas Continuous High Bleed 30
transmission compression. Pneumatic Device
Vents \2\.
Underground natural Intermittent Bleed 2.3
gas storage. Pneumatic Device
Vents \2\.
Natural gas
distribution.
------------------------------------------------------------------------
Population Emission Factors--Major Equipment, Gas Service \1\
------------------------------------------------------------------------
Onshore petroleum and Wellhead............. 8.87
natural gas production.
Onshore petroleum and Separator............ 9.65
natural gas gathering and
boosting.
Meters/Piping........ 7.04
Compressor........... 13.8
Dehydrator........... 8.09
Heater............... 5.22
Storage Vessel....... 1.83
------------------------------------------------------------------------
Population Emission Factors--Major Equipment, Crude Service
------------------------------------------------------------------------
Onshore petroleum and natural Wellhead............. 4.13
gas production.
Separator............ 4.77
Meters/Piping........ 12.4
Compressor........... 13.8
Dehydrator........... 8.09
Heater............... 3.2
Storage Vessel....... 1.91
------------------------------------------------------------------------
Population Emission Factors--Gathering Pipelines, by Material Type \4\
------------------------------------------------------------------------
Onshore petroleum and natural Protected Steel...... 0.93
gas gathering and boosting.
Unprotected Steel.... 8.2
Plastic/Composite.... 0.28
Cast Iron............ 8.4
------------------------------------------------------------------------
\1\ For multi-phase flow that includes gas, use the gas service emission
factors.
\2\ Emission factor is in units of ``scf whole gas/hour/device.''
\3\ Emission factor is in units of ``scf whole gas/hour/pump.''
\4\ Emission factors are in units of ``scf whole gas/hour/mile of
pipeline.''
0
22. Revise table W-2 to subpart W of part 98 to read as follows:
Table W-2 to Subpart W of Part 98--Default Whole Gas Leaker Emission Factors
----------------------------------------------------------------------------------------------------------------
Emission factor (scf whole gas/hour/component)
--------------------------------------------------------------------------
If you survey using If you survey using If you survey using any
Equipment components Method 21 as specified Method 21 as specified of the methods in Sec.
in Sec. in Sec. 98.234(a)(1), (3), or
98.234(a)(2)(i) 98.234(a)(2)(ii) (5)
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas
Gathering and Boosting--All Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve................................ 9.6 5.5 16
Flange............................... 6.9 4.0 11
Connector (other).................... 4.9 2.8 7.9
Open-Ended Line \1\.................. 6.3 3.6 10
Pressure Relief Valve................ 7.8 4.5 13
Pump Seal............................ 14 8.3 23
Other \2\............................ 9.1 5.3 15
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--Onshore Petroleum and Natural Gas Production--All Components, Oil Service
----------------------------------------------------------------------------------------------------------------
Valve................................ 5.6 3.3 9.2
Flange............................... 2.7 1.6 4.4
Connector (other).................... 5.6 3.2 9.1
[[Page 42325]]
Open-Ended Line...................... 1.6 0.93 2.6
Pump \3\............................. 3.7 2.2 6.0
Other \2\............................ 2.2 1.0 2.9
----------------------------------------------------------------------------------------------------------------
\1\ The open-ended lines component type includes blowdown valve and isolation valve leaks emitted through the
blowdown vent stack for centrifugal and reciprocating compressors when using the population emission factor
approach as specified in Sec. 98.233(o)(10)(iv) or (p)(10)(iv).
\2\ ``Others'' category includes any equipment leak emission point not specifically listed in this table, as
specified in Sec. 98.232(c)(21) and (j)(10).
\3\ The pumps component type in oil service includes agitator seals.
0
23. Remove tables W-3A and W-3B to subpart W of part 98 and add table
W-3 to subpart W of part 98 in numerical order to read as follows:
Table W-3 to Subpart W of Part 98--Default Total Hydrocarbon Population Emission Factors
----------------------------------------------------------------------------------------------------------------
Emission factor (scf total
Industry segment Source type/component hydrocarbon/ hour/
component)
----------------------------------------------------------------------------------------------------------------
Population Emission Factors--Storage Wellheads, Gas Service
----------------------------------------------------------------------------------------------------------------
Underground natural gas storage.............. Connector........................... 0.01
Valve............................... 0.1
Pressure Relief Valve............... 0.17
Open-Ended Line..................... 0.03
----------------------------------------------------------------------------------------------------------------
0
24. Remove tables W-4A and W-4B to subpart W of part 98 and add table
W-4 to subpart W of part 98 in numerical order to read as follows:
Table W-4 to Subpart W of Part 98--Default Total Hydrocarbon Leaker Emission Factors
----------------------------------------------------------------------------------------------------------------
Emission factor (scf total hydrocarbon/hour/
component)
--------------------------------------------------
If you survey
Equipment components If you survey If you survey using any of
using Method 21 using Method 21 the methods in
as specified in as specified in Sec.
Sec. Sec. 98.234(a)(1),
98.234(a)(2)(i) 98.234(a)(2)(ii) (3), or (5)
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression--
Compressor Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\.................................................... 14.84 9.51 24.2
Connector.................................................... 5.59 3.58 9.13
Open-Ended Line.............................................. 17.27 11.07 28.2
Pressure Relief Valve........................................ 39.66 25.42 64.8
Meter........................................................ 19.33 12.39 31.6
Other \2\.................................................... 4.1 2.63 6.70
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--Onshore Natural Gas Processing, Onshore Natural Gas Transmission Compression--Non-
Compressor Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\.................................................... 6.42 4.12 10.5
Connector.................................................... 5.71 3.66 9.3
Open-Ended Line.............................................. 11.27 7.22 18.4
Pressure Relief Valve........................................ 2.01 1.29 3.28
Meter........................................................ 2.93 1.88 4.79
Other \2\.................................................... 4.1 2.63 6.70
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--Underground Natural Gas Storage--Storage Station, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\.................................................... 14.84 9.51 24.2
Connector (other)............................................ 5.59 3.58 9.13
Open-Ended Line.............................................. 17.27 11.07 28.2
Pressure Relief Valve........................................ 39.66 25.42 64.8
Meter and Instrument......................................... 19.33 12.39 31.6
[[Page 42326]]
Other \2\.................................................... 4.1 2.63 6.70
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--Underground Natural Gas Storage--Storage Wellheads, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \1\.................................................... 4.5 3.2 7.35
Connector (other than flanges)............................... 1.2 0.7 1.96
Flange....................................................... 3.8 2.0 6.21
Open-Ended Line.............................................. 2.5 1.7 4.08
Pressure Relief Valve........................................ 4.1 2.5 6.70
Other \2\.................................................... 4.1 2.5 6.70
----------------------------------------------------------------------------------------------------------------
\1\ Valves include control valves, block valves and regulator valves.
\2\ Other includes any potential equipment leak emission point in gas service that is not specifically listed in
this table, as specified in Sec. 98.232(d)(7) for onshore natural gas processing, Sec. 98.232(e)(8) for
onshore natural gas transmission compression, and as specified in Sec. 98.232(f)(6) and (8) for underground
natural gas storage.
0
25. Remove tables W-5A and W-5B to subpart W of part 98 and add table
W-5 to subpart W of part 98 in numerical order to read as follows:
Table W-5 to Subpart W of Part 98--Default Methane Population Emission
Factors
------------------------------------------------------------------------
Emission
Source type/ factor (scf
Industry segment component methane/hour/
component)
------------------------------------------------------------------------
Population Emission Factors--LNG Storage Compressor, Gas Service
------------------------------------------------------------------------
LNG storage....................... Vapor Recovery 4.17
Compressor \1\.
LNG import and export equipment...
------------------------------------------------------------------------
Population Emission Factors--Below Grade Transmission-Distribution
Transfer Station Components and Below Grade Metering-Regulating Station
\2\ Components, Gas Service \3\
------------------------------------------------------------------------
Natural gas distribution.......... Below Grade T-D 0.30
Transfer Station.
Below Grade M&R 0.30
Station.
------------------------------------------------------------------------
Population Emission Factors--Distribution Mains, Gas Service \4\
------------------------------------------------------------------------
Natural gas distribution.......... Unprotected Steel... 5.1
Protected Steel..... 0.57
Plastic............. 0.17
Cast Iron........... 6.9
------------------------------------------------------------------------
Population Emission Factors--Distribution Services, Gas Service \5\
------------------------------------------------------------------------
Natural gas distribution.......... Unprotected Steel... 0.086
Protected Steel..... 0.0077
Plastic............. 0.0016
Copper.............. 0.03
------------------------------------------------------------------------
Population Emission Factors--Interconnect, Direct Sale, or Farm Tap
Stations \2\ \3\
------------------------------------------------------------------------
Onshore natural gas transmission Transmission Company 166
pipeline. Interconnect M&R
Station.
Direct Sale or Farm 1.3
Tap Station.
------------------------------------------------------------------------
Population Emission Factors--Transmission Pipelines, Gas Service \4\
------------------------------------------------------------------------
Onshore natural gas transmission Unprotected Steel... 0.74
pipeline.
Protected Steel..... 0.041
Plastic............. 0.061
Cast Iron........... 27
------------------------------------------------------------------------
\1\ Emission Factor is in units of ``scf methane/hour/compressor.''
\2\ Excluding customer meters.
\3\ Emission Factor is in units of ``scf methane/hour/station.''
[[Page 42327]]
\4\ Emission Factor is in units of ``scf methane/hour/mile.''
\5\ Emission Factor is in units of ``scf methane/hour/number of
services.''
0
26. Remove tables W-6A and W-6B to subpart W of part 98 and add table
W-6 to subpart W of part 98 in numerical order to read as follows:
Table W-6 to Subpart W of Part 98--Default Methane Leaker Emission Factors
----------------------------------------------------------------------------------------------------------------
Emission factor (scf methane/hour/ component)
--------------------------------------------------
If you survey
If you survey If you survey using any of
Equipment components using Method 21 using Method 21 the methods in
as specified in as specified in Sec.
Sec. Sec. 98.234(a)(1),
98.234(a)(2)(i) 98.234(a)(2)(ii) (3), or (5)
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--LNG Storage and LNG Import and Export Equipment--Storage Components and Terminals
Components, LNG Service
----------------------------------------------------------------------------------------------------------------
Valve........................................................ 1.19 0.23 1.94
Pump Seal.................................................... 4.00 0.73 6.54
Connector.................................................... 0.34 0.11 0.56
Other \1\.................................................... 1.77 0.99 2.9
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--LNG Storage and LNG Import and Export Equipment--Storage Components and Terminals
Components, Gas Service
----------------------------------------------------------------------------------------------------------------
Valve \2\.................................................... 14.84 9.51 24.2
Connector.................................................... 5.59 3.58 9.13
Open-Ended Line.............................................. 17.27 11.07 28.2
Pressure Relief Valve........................................ 39.66 25.42 64.8
Meter and Instrument......................................... 19.33 12.39 31.6
Other \3\.................................................... 4.1 2.63 6.70
----------------------------------------------------------------------------------------------------------------
Leaker Emission Factors--Natural Gas Distribution--Transmission-Distribution Transfer Station \4\ Components,
Gas Service
----------------------------------------------------------------------------------------------------------------
Connector.................................................... 1.69 ................ 2.76
Block Valve.................................................. 0.557 ................ 0.91
Control Valve................................................ 9.34 ................ 15.3
Pressure Relief Valve........................................ 0.27 ................ 0.44
Orifice Meter................................................ 0.212 ................ 0.35
Regulator.................................................... 0.772 ................ 1.26
Open-ended Line.............................................. 26.131 ................ 42.7
----------------------------------------------------------------------------------------------------------------
\1\ ``Other'' equipment type for components in LNG service should be applied for any equipment type other than
connectors, pumps, or valves.
\2\ Valves include control valves, block valves and regulator valves.
\3\ ``Other'' equipment type for components in gas service should be applied for any equipment type other than
valves, connectors, flanges, open-ended lines, pressure relief valves, and meters and instruments, as
specified in Sec. 98.232(g)(6) and (7) and Sec. 98.232(h)(7) and (8).
\4\ Excluding customer meters.
0
27. Revise table W-7 to subpart W of part 98 to read as follows:
Table W-7 to Subpart W of Part 98--Default Methane Emission Factors for
Internal Combustion Equipment
------------------------------------------------------------------------
Emission
factor (kg
Internal combustion equipment type CH4/mmBtu)
------------------------------------------------------------------------
Reciprocating Engine, 2-stroke lean-burn................... 0.658
Reciprocating Engine, 4-stroke lean-burn................... 0.522
Reciprocating Engine, 4-stroke rich-burn................... 0.045
Gas Turbine................................................ 0.004
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[FR Doc. 2024-08988 Filed 5-13-24; 8:45 am]
BILLING CODE 6560-50-P