[Federal Register Volume 85, Number 13 (Tuesday, January 21, 2020)]
[Proposed Rules]
[Pages 3492-3534]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2019-27431]
[[Page 3491]]
Vol. 85
Tuesday,
No. 13
January 21, 2020
Part II
Environmental Protection Agency
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40 CFR Part 49
Federal Implementation Plan for Managing Emissions From Oil and
Natural Gas Sources on Indian Country Lands Within the Uintah and Ouray
Indian Reservation in Utah; Proposed Rule
Federal Register / Vol. 85 , No. 13 / Tuesday, January 21, 2020 /
Proposed Rules
[[Page 3492]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 49
[EPA-R08-OAR-2015-0709; FRL-10003-12-Region 8]
RIN 2008-AA03
Federal Implementation Plan for Managing Emissions From Oil and
Natural Gas Sources on Indian Country Lands Within the Uintah and Ouray
Indian Reservation in Utah
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
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SUMMARY: The Environmental Protection Agency (EPA) is proposing to
promulgate a Federal Implementation Plan (FIP) under the Clean Air Act
(CAA) and the EPA's implementing regulations that consists of control
requirements for new, modified, and existing oil and natural gas
sources located on Indian country lands within the Uintah and Ouray
Indian Reservation (also referred to as the U&O Reservation) to address
air quality in and around the Uinta Basin Ozone Nonattainment Area in
northeast Utah. The proposed FIP would also continue the streamlined
approach to authorize new and modified minor oil and natural gas
production sources on the reservation that has been established through
national rulemakings. This proposed U&O FIP will establish emissions
control requirements for oil and natural gas activity that contribute
to the Uinta Basin's winter ozone problem; establish regulatory
requirements that are the same or consistent between Indian country and
neighboring jurisdictions within the Basin; and allow for reasonable
continued development of the Basin's oil and natural gas resources on
the Indian country lands within the U&O Reservation that are included
in the current Uinta Basin Ozone Nonattainment Area. VOC emissions
control requirements for existing oil and natural gas sources are
currently required in areas of the Basin under Utah jurisdiction, but
do not exist for most sources on the U&O Reservation. Additionally,
this proposed U&O FIP will ensure new development on the U&O
Reservation will not cause or contribute to a NAAQS violation. We are
proposing to determine that it is necessary and appropriate to
promulgate this proposed U&O FIP to protect air quality on the U&O
Reservation, under the authority provided in the CAA and the EPA's
Tribal Air Quality Planning and Management regulations. We designed
this proposed U&O FIP to protect air quality while also providing the
regulated community certainty that requirements will be consistent
across the Uinta Basin and allow for continued, responsible development
of new and modified minor oil and natural gas sources. Unless and until
replaced by a Tribal Implementation Plan, this proposed U&O FIP will be
implemented by the EPA, or by the Ute Indian Tribe if the EPA delegates
that authority to the Tribe.
DATES: Comments must be received on or before March 23, 2020. Under the
Paperwork Reduction Act (PRA), comments on the information collection
provisions are best assured of consideration if the Office of
Management and Budget (OMB) receives a copy of your comments on or
before February 20, 2020.
Public hearing: A public hearing for this proposal is scheduled to
be held on Thursday, February 6, 2020, at the Ute Indian Tribe
Administration Offices Auditorium, from 1 p.m. until 5 p.m., and again
from 6 p.m. until 8 p.m. (local time). The hearing will be held to
accept oral comments on this proposed U&O FIP.
ADDRESSES: The public hearing will be held at the Ute Indian Tribe
Administration Offices Auditorium, 6964 East 1000 South, Fort Duchesne,
Utah 84026. Submit your comments, identified by Docket ID No. EPA-R08-
OAR-2015-0709, by one of the following methods:
http://www.regulations.gov. Follow the online instructions
for submitting comments.
Mail: Carl Daly, Acting Director, Air and Radiation
Division, U.S. EPA, Region 8, Mail Code 8ARD, 1595 Wynkoop St., Denver,
CO 80202-1129.
Hand Delivery: Carl Daly, Acting Director, Air and
Radiation Division, U.S. Environmental Protection Agency (EPA), Region
8, Mail Code 8ARD, 1595 Wynkoop Street, Denver, Colorado 80202-1129.
Such deliveries are only accepted Monday through Friday, 8:00 a.m. to
4:30 p.m., excluding federal holidays. Special arrangements should be
made for deliveries of boxed information.
Instructions: Direct your comments to Docket ID No. EPA-R08-OAR-
2015-0709. The EPA's policy is that all comments received will be
included in the public docket without change and may be made available
online at http://www.regulations.gov, including any personal
information provided, unless the comment includes information claimed
to be Confidential Business Information (CBI) or other information for
which disclosure is restricted by statute. Do not submit information
that you consider to be CBI or otherwise protected through http://www.regulations.gov. The http://www.regulations.gov site is an
``anonymous access'' system, which means that the EPA will not know
your identity or contact information unless you provide it in the body
of your comment. If you submit an electronic comment, the EPA
recommends that you include your name and other contact information in
the body of your comment and with any disk or CD-ROM you submit. If the
EPA cannot read your comment due to technical difficulties and cannot
contact you for clarification, the EPA may not be able to consider your
comment. Electronic files should avoid the use of special characters,
any form of encryption, and be free of any defects or viruses. For
additional information about the EPA's public docket, visit the EPA
Docket Center homepage at www.epa.gov/epahome/dockets.htm.
Docket: All documents in the docket are listed in the http://www.regulations.gov index. In some instances, we reference documents
from the dockets for other rulemakings. For this proposed rule, we have
incorporated by reference Docket ID No. EPA-HQ-OAR-2010-0505,\1\ Docket
ID EPA-R08-OAR-2012-0479,\2\ Docket ID No. EPA-HQ-OAR-2003-0076, and
Docket ID No. EPA-HQ-OAR-2014-0606 into Docket ID EPA-R08-OAR-2015-
0709. Although listed in the index, some information is not publicly
available, e.g., CBI or other information for which disclosure is
restricted by statute. Certain other material, such as copyrighted
material, will be publicly available only in hard copy. Publicly
available docket materials are available either electronically at
http://www.regulations.gov or in hard copy at the following locations:
Air and Radiation Division, U.S. EPA, Region 8, Mail Code 8ARD, 1595
Wynkoop Street, Denver, Colorado 80202-1129; and Air Quality Program,
Ute Indian Tribe, P.O. Box 70, Fort Duchesne, Utah 84026-0190. The EPA
requests that if at all possible, you contact the persons listed
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in the FOR FURTHER INFORMATION CONTACT section if you wish to view the
hard copy of the docket. You may view the hard copy of the docket
Monday through Friday, 8:00 a.m. to 4:00 p.m., excluding federal
holidays.
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\1\ Final Rule: Oil and Natural Gas Sector: Emission Standards
for New, Reconstructed, and Modified Sources, See 81 FR 35823 (June
3, 2016); docket available at http://www.regulations.gov, accessed
August 16, 2019.
\2\ Final Rule: Federal Implementation Plan for Oil and Natural
Gas Well Production Facilities, Fort Berthold Indian Reservation,
North Dakota, See 78 FR 17835 (March 22, 2013); docket available at
http://www.regulations.gov, accessed August 16, 2019.
FOR FURTHER INFORMATION CONTACT: Ms. Claudia Smith, U.S. EPA, Region 8,
Air and Radiation Division, Mail Code 8ARD, 1595 Wynkoop Street,
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Denver, Colorado 80202-1129, (303) 312-6520, [email protected].
SUPPLEMENTARY INFORMATION:
Definitions
APA: Administrative Procedure Act.
Act or CAA: Clean Air Act, unless the context indicates
otherwise.
BTU: British Thermal Unit.
CBI: Confidential Business Information.
CDPHE: Colorado Department of Public Health and Environment's
Air Pollution Control Division.
CO: carbon monoxide.
EPA, we, us or our: The United States Environmental Protection
Agency.
FBIR: Fort Berthold Indian Reservation.
FIP: Federal Implementation Plan.
GOR: gas-to-oil ratio.
HAP: hazardous air pollutants.
LACT: lease automatic custody transfer.
MDEQ: Montana Department of Environmental Quality's Air
Resources Management Bureau.
NAAQS: National Ambient Air Quality Standards.
NAICS: North American Industry Classification System.
NDDoH: North Dakota Department of Health's Division of Air
Quality.
NESHAP: National Emission Standards for Hazardous Air
Pollutants.
NMED: New Mexico Environment Department's Air Quality Bureau.
NOX: nitrogen oxides.
NO2: nitrogen dioxide.
NSPS: New Source Performance Standards.
NSR: New Source Review.
ODEQ: Oklahoma Department of Environmental Quality's Air Quality
Division.
PM: particulate matter.
PSD: Prevention of Significant Deterioration.
PTE: potential to emit.
RCT: Railroad Commission of Texas, Oil and Gas Division.
RIA: Regulatory Impact Analysis
SCADA: Supervisory Control and Data Acquisition.
SIP: State Implementation Plan.
SO2: sulfur dioxide.
TAR: Tribal Authority Rule.
TAS: treatment in the same manner as a state.
TIP: Tribal Implementation Plan.
UDEQ: Utah Department of Environmental Quality's Division of Air
Quality.
U&O Reservation or the Reservation: Indian country lands within
the Uintah & Ouray Indian Reservation.
VOC: volatile organic compound(s).
VRU: vapor recovery unit.
WDEQ: Wyoming Department of Environmental Quality's Air Quality
Division.
The information presented in this preamble is organized as follows:
I. General Information
A. What entities are potentially affected by this proposal?
B. What should I consider as I prepare my comments to the EPA?
C. Where can I get a copy of this document and other related
information?
II. Purpose of This Action
III. Background
A. Uintah and Ouray Indian Reservation
B. Tribal Authority Rule
C. Federal Indian Country Minor NSR Rule
D. Air Quality and Attainment Status
E. Emissions Information
F. What is a FIP?
G. Oil and Natural Gas Sector in the Uinta Basin
IV. Development of the Proposed Rule
A. Rationale for the Proposed Rule
B. Uinta Basin Air Quality Solutions: Stakeholder Feedback
C. Ensuring Streamlined Construction Authorizations on the U&O
Reservation
D. Developing the Proposed Control Requirements
E. Effect on Determining Site-Specific Permitting Requirements
F. Evaluation of Emissions Impacts of the Proposed Rule
G. Costs and Benefits of the Proposed Rule
V. Summary of FIP Provisions
A. Introduction
B. Provisions for Delegation of Administration to the Tribe
C. General Provisions
D. Emissions Inventory Requirements
E. Compliance With the National Indian Country Oil and Natural
Gas Federal Implementation Plan for New and Modified True Minor Oil
and Natural Gas Sources in the Uinta Basin Ozone Nonattainment Area
F. VOC Emissions Control Requirements
G. Monitoring Requirements
H. Recordkeeping Requirements
I. Notification and Reporting Requirements
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs
C. Paperwork Reduction Act (PRA)
D. Regulatory Flexibility Act (RFA)
E. Unfunded Mandates Reform Act (UMRA)
F. Executive Order 13132: Federalism
G. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
H. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
J. National Technology Transfer and Advancement Act (NTTAA)
K. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
I. General Information
A. What entities are potentially affected by this proposal?
Entities potentially affected by this proposal include the Ute
Indian Tribe,\3\ as well as new, modified and existing sources that are
in the oil and natural gas production and natural gas processing
segments of the oil and natural gas sector and are on Indian country
\4\ lands within the U&O Reservation. All of the Ute Indian Tribe
Indian country lands of which the EPA is aware are located within the
exterior boundaries of the Reservation, and this proposed U&O FIP will
apply to all such lands. To the extent that there are Ute Indian Tribe
Dependent Indian Communities under 18 U.S.C. 1151(b) or allotted lands
under 18 U.S.C. 1151(c) that are located outside the exterior
boundaries of the Reservation, those lands will not be covered by this
proposed U&O FIP.\5\ In addition, this
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proposed rule will not apply to any sources on non-Indian-country
lands, including any non-Indian-country lands within the exterior
boundaries of the Reservation.\6\
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\3\ The Ute Indian Tribe is a federally recognized tribe
organized under the Indian Reorganization Act of 1934, with a
Constitution and By-Laws adopted by the Tribe on December 19, 1936
and approved by the Secretary of the Interior on January 19, 1937.
See Indian Entities Recognized and Eligible to Receive Services from
the United States Bureau of Indian Affairs, See 82 FR 4915 (January
17, 2017); 48 Stat. 984, 25 U.S.C. 5123 (IRA); Constitution and By-
Laws of the Ute Indian Tribe of the Uintah and Ouray Reservation,
available at https://www.loc.gov/law/help/american-indian-consts/PDF/37026342.pdf, accessed August 16, 2019.
\4\ Indian country is defined at 18 U.S.C. 1151 as: (a) All land
within the limits of any Indian reservation under the jurisdiction
of the United States Government, notwithstanding the issuance of any
patent, and, including rights-of-way running through the
reservation, (b) all dependent Indian communities within the borders
of the United States whether within the original or subsequently
acquired territory thereof, and whether within or without the limits
of a state, and (c) all Indian allotments, the Indian titles to
which have not been extinguished, including rights-of-way running
through the same.
\5\ Under the CAA, lands held in trust for the use of an Indian
tribe are reservation lands within the definition at 18 U.S.C.
1151(a), regardless of whether the land is formally designated as a
reservation. See Indian Tribes: Air Quality Planning and Management,
See 63 FR 7254, 7258 (1998) (``Tribal Authority Rule''); Arizona
Pub. Serv. Co. v. EPA, 211 F.3d 1280, 1285-86 (D.C. Cir. 2000).
EPA's references in this proposed U&O FIP to Indian country lands
within the exterior boundaries of the U&O Reservation include any
such tribal trust lands that may be acquired by the Ute Indian
Tribe.
In 2014, the U.S. Court of Appeals for the D.C. Circuit
addressed EPA's authority to promulgate a FIP establishing certain
CAA permitting programs in Indian country. Oklahoma Dept. of
Environmental Quality v. EPA, 740 F. 3d 185 (D.C. Cir. 2014). In
that case, the court recognized EPA's authority to promulgate a FIP
to directly administer CAA programs on Indian reservations but
invalidated the FIP at issue as applied to non-reservation areas of
Indian country in the absence of a demonstration of an Indian
tribe's jurisdiction over such non-reservation area. Because the
current proposed rule would apply only on Indian country lands that
are within the exterior boundaries of the U&O Reservation, i.e., on
Reservation lands, it is unaffected by the Oklahoma court decision.
\6\ As a result of a series of federal court decisions, there
are some non-Indian-country lands within the exterior boundaries of
the Uintah and Ouray Indian Reservation. See note 19.
Table 1--Source Categories Affected by This Proposed Action
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Examples of regulated entities/description of
Industry category NAICS code industry category
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Oil and Gas Production/Operations........ 21111 Exploration for crude petroleum and natural gas;
drilling, completing, and equipping wells; operation
of separators, emulsion breakers, desilting
equipment, and field gathering lines for crude
petroleum and natural gas; and all other activities
in the preparation of oil and gas up to the point of
shipment from the producing property.
.............. Production of crude petroleum, the mining and
extraction of oil from oil shale and oil sands, the
production of natural gas, sulfur recovery from
natural gas, and the recovery of hydrocarbon liquids
from oil and gas field gases.
Crude Petroleum and Natural Gas 211111 Exploration, development and/or the production of
Extraction. petroleum or natural gas from wells in which the
hydrocarbons will initially flow or can be produced
using normal pumping techniques or production of
crude petroleum from surface shales or tar sands or
from reservoirs in which the hydrocarbons are
semisolids.
Natural Gas Liquid Extraction............ 211112 Recovery of liquid hydrocarbons from oil and gas
field gases; and sulfur recovery from natural gas.
Drilling Oil and Gas Wells............... 213111 Drilling oil and gas wells for others on a contract
or fee basis, including spudding in, drilling in,
redrilling, and directional drilling.
Support Activities for Oil and Gas 213112 Performing support activities on a contract or fee
Operations. basis for oil and gas operations (except site
preparation and related construction activities)
such as exploration (except geophysical surveying
and mapping); excavating slush pits and cellars,
well surveying; running, cutting, and pulling
casings, tubes, and rods; cementing wells, shooting
wells; perforating well casings; acidizing and
chemically treating wells; and cleaning out,
bailing, and swabbing wells.
Engines (Spark Ignition and Compression 2211 Provision of electric power to support oil and
Ignition) for Electric Power Generation. natural gas production where access to the electric
grid is unavailable.
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This list is not intended to be exhaustive, but rather provides a
guide for readers regarding entities potentially affected by this
action. To determine whether your source could be affected by this
action, you should examine the proposed U&O FIP applicability criteria
in Sec. 49.4169. If you have any questions regarding the applicability
of this action to a particular entity, contact the appropriate person
listed in the FOR FURTHER INFORMATION CONTACT section.
B. What should I consider as I prepare my comments to the EPA?
Submitting CBI. Do not submit this information to the EPA through
regulations.gov or email. Clearly mark the part or all of the
information that you claim to be CBI. For CBI information in a disk or
CD ROM that you mail to the EPA, mark the outside of the disk or CD ROM
as CBI and then identify electronically within the disk or CD ROM the
specific information that is claimed as CBI. In addition to one
complete version of the comment that includes information claimed as
CBI, a copy of the comment that does not contain the information
claimed as CBI must be submitted for inclusion in the public docket.
Information so marked will not be disclosed except in accordance with
procedures set forth in 40 CFR part 2. Send or deliver information
identified as CBI only to the following address: Mr. Aaron Zull, c/o
Air and Radiation Division U.S. EPA, Region 8, Mail Code 8ARD, 1595
Wynkoop St., Denver, CO 80202-1129, and Attention Docket ID No. EPA-
R08-OAR-2015-0709.
Docket. The docket number for this action is EPA-R08-OAR-2015-0709.
Preparing comments. When submitting comments, remember to:
Identify the rulemaking by docket number and other
identifying information (subject heading, Federal Register date and
page number).
Respond to specific questions and link comments to
specific CFR references when appropriate.
Explain why you agree or disagree and suggest
alternatives. Include specific regulatory text that implements your
requested changes.
Explain technical information and/or data that you used to
as the basis of your comment and provide references to the supporting
information.
If you estimate potential costs or burdens, explain how
you arrived at your estimate in sufficient detail to allow for it to be
reproduced.
Provide specific examples to illustrate your concerns and
suggest alternatives.
Explain your views as clearly as possible, avoiding the
use of profanity or personal threats.
Make sure to submit your comments by the comment period
deadline identified.
C. Where can I get a copy of this document and other related
information?
In addition to being available in the docket, an electronic copy of
this proposal will also be posted at: https://www.epa.gov/air-quality-implementation-plans/approved-air-quality-implementation-plans-region-8
(Approved Air Quality Implementation Plans in Region 8 page).
II. Purpose of This Action
In this action, the EPA is proposing to exercise its authority
under sections 301(a) and 301(d)(4) of the CAA and 40 CFR 49.11 to
promulgate FIP provisions that are necessary and appropriate to protect
air quality on the U&O Reservation and in nearby communities. The
purpose of this proposed U&O FIP is threefold. First, this proposed U&O
FIP would improve air quality in the
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U&O Reservation by addressing emissions from oil and natural gas
activity that contribute to the winter ozone problem in the
physiographic region known as the Uinta Basin,\7\ within which the U&O
Reservation is located, and where ambient ozone levels have exceeded
both the 2008 and the 2015 ozone NAAQS.\8\ The EPA designated portions
of the Uinta Basin, including large portions of the U&O Reservation, as
nonattainment for the 2015 ozone NAAQS.\9\
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\7\ For the purpose of this rulemaking, the EPA defines the
geographic scope of the Uinta Basin to be consistent with the Uinta
Basin 2014 Air Agencies Oil and Gas Emissions Inventory (herein
after referred to as the 2014 Uinta Basin Emissions Inventory),
which encompasses Duchesne and Uintah counties. The 2014 Uinta Basin
Emissions Inventory is available at: https://deq.utah.gov/air-quality/2014-air-agencies-oil-and-gas-emissions-inventory-uinta-basin, accessed August 16, 2019.
\8\ The 2015 ozone NAAQS is 70 parts per billion (ppb) (40 CFR
50.19). The 2008 ozone NAAQS is 75 ppb. Historical ozone NAAQS
information is available at: https://www.epa.gov/ozone-pollution/table-historical-ozone-national-ambient-air-quality-standards-naaqs,
accessed August 16, 2019.
\9\ On April 30, 2018, the EPA designated portions of the Uinta
Basin below a contiguous external perimeter of 6,250 ft. as
nonattainment for the 2015 ozone NAAQS. This includes land under
both state and tribal jurisdiction. For more information, see
https://www.epa.gov/ozone-designations/additional-designations-2015-ozone-standards, accessed August 16, 2019.
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As recently as February 2019, the Uinta Basin experienced very poor
air quality. The problem is caused by emissions of VOC and
NOX reacting in the presence of sunlight and widespread snow
cover during temperature inversion conditions to form ground-level
ozone at levels that exceed the ozone NAAQS and are, therefore,
detrimental to public health. The main sources in the Basin responsible
for VOC and NOX emissions are existing sources in the oil
and natural gas sector. As explained in section III.D. (Air Quality
Information), available information indicates that winter ozone
formation in the Basin is driven by local emissions and is
significantly more sensitive to changes in VOC emissions than
NOX emissions. As explained in section III.E. (Emissions
Information), available information indicates that the large majority
of VOC emissions in the Basin are from existing oil and natural gas
activity, and the large majority of those emissions are from existing
sources on the U&O Reservation and in the nonattainment area. VOC
emissions control requirements for existing oil and natural gas sources
currently exist in areas of the Basin under Utah jurisdiction, but do
not exist in the U&O Reservation and are necessary to protect air
quality.
The CAA does not require an attainment plan for Marginal ozone
nonattainment areas.\10\ Accordingly, this proposed U&O FIP is not
intended to bring the Uinta Basin back into attainment with the ozone
standard. However, we do anticipate that this proposed U&O FIP will
make a meaningful improvement in air quality through the reduction of
VOC, which are an ozone precursor, while also allowing continued
construction authorization of new development in the Basin and the
positive economic impact that development brings to the Tribe.
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\10\ The requirements for Marginal ozone nonattainment areas are
specified in Clean Air Act Title I, Part D, subpart 2 (see 42 U.S.C.
7511a(a)) and requirements include: (1) Comprehensive, accurate,
current inventory of actual ozone precursor emissions from all
sources; (2) Corrections, if necessary, to existing implementation
plans to meet specific requirements, including for nonattainment
major source permitting; (3) Triennial emissions inventory updates;
and (4) General offset requirements for new and modified major
sources.
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This proposed action is driven by the EPA's authority and
responsibility to protect air quality in Indian country arising from
provisions in sections 301(a) and 301(d)(4) of the CAA and 40 CFR
49.11. Regarding permitting of new or modified sources of air pollution
in nonattainment areas in Indian country, the reviewing authority must
demonstrate that construction authorization of minor sources would not
cause or contribute to a NAAQS violation in the nonattainment area (see
49.155(a)(7)(ii)) and that construction authorization of major sources
would provide a net air quality benefit in the nonattainment area (see
40 CFR 49.169(b)(4)). While the CAA Indian country nonattainment permit
program for major sources specifies offset requirements as the method
to make such a demonstration (see 40 CFR 49.169(b)(3)), the CAA Indian
country nonattainment permit program for minor sources is not
prescriptive as to how to make such a demonstration. The requirements
in this proposed U&O FIP resulting in VOC emission reductions from
existing sources would improve air quality and also allow the EPA to
rely on those reductions to meet the NAAQS protection requirements for
continued construction authorization of new or modified minor sources
in the nonattainment area.
Regarding the focus on VOC emission reductions in this proposed U&O
FIP, according to the Uinta Basin Ozone Studies, which consist of field
studies conducted in the Basin from 2011 to 2014,\11\ improvements in
ozone levels in the Basin are most likely to come from VOC emissions
reductions from existing oil and natural gas sources. After a careful
analysis of emissions data provided by industry in the 2014 Uinta Basin
Emissions Inventory, we have determined that most of the existing oil
and natural gas sources on the U&O Reservation are largely uncontrolled
for VOC and other emissions. Therefore, in developing this rule, we
have concentrated on determining the most effective control
requirements to reduce VOC emissions from oil and natural gas sources
to address the winter ozone exceedances.
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\11\ Utah DEQ: Ozone in the Uinta Basin: Overview web page with
reports on Uinta Basin ozone field studies from 2011 to 2014:
https://deq.utah.gov/air-quality/ozone-in-the-uinta-basin, accessed
August 16, 2019. The RIA for this rule contains detailed discussion
of the studies and can be viewed in the docket for this rulemaking
(Docket ID No. EPA-R08-OAR-2015-0709).
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Second, the proposed control requirements are intended to be the
same as or consistent with the requirements applicable to similar
sources on Utah-regulated lands, to promote a more consistent
regulatory environment across the Basin. Where we are proposing to
regulate existing equipment or activities that are regulated by EPA
standards for the oil and natural gas sector, we also have consulted
those EPA standards.
We are proposing to make the final rule effective on the date of
publication. We are proposing that compliance with the FIP for sources
that construct on or after the effective date of the final rule would
be required upon startup. Compliance for sources that commence
construction before the effective date of the final rule would be
required no later than 18 months after the effective date of the final
rule.
Finally, given the number of oil and natural gas projects in the
Basin that are already approved or are in the federal review and
approval process through evaluations conducted under the National
Environmental Policy Act (NEPA) by other federal agencies,\12\ in the
coming years the EPA could receive a large number of applications for
authorization to construct new and modified synthetic minor oil and
natural gas sources on the U&O Reservation and registrations of new and
modified true minor oil and natural gas sources on the U&O Reservation
under the National O&NG FIP. We
[[Page 3496]]
recently took action to reinstate the streamlined construction
authorization mechanism available for true minor oil and natural gas
sources in Indian country through the National O&NG FIP (codified at 40
CFR part 49, subpart C, Sec. Sec. 49.101-49.105) \13\ for the portions
of the U&O Reservation that are included in the area of the Uinta Basin
that has been designated nonattainment for the 2015 ozone NAAQS.\14\ In
the separate action, we amended the National O&NG FIP to extend its
geographic coverage to the Indian country portions of the U&O
Reservation that are part of the Uinta Basin Ozone Nonattainment Area.
In addition to providing a streamlined construction authorization
mechanism to new and modified true minor oil and natural gas
sources,\15\ the National O&NG FIP requires compliance with a suite of
eight federal oil and natural gas sector emissions standards \16\ for
new and modified sources, as applicable. The existing source emissions
reductions achieved under the proposed FIP, once implemented, would
allow the EPA to demonstrate that both permitting the construction of
new and modified synthetic minor oil and natural gas sources and
registration of new and modified true minor oil and natural gas sources
under the National O&NG FIP would be protective of the NAAQS on the U&O
Reservation. This will be described in greater detail in Sections IV.C.
and V.E.
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\12\ Spreadsheet titled ``Uinta Basin OG NEPA Evaluations
9.11.19.pdf'', available in the Docket for this rulemaking (Docket
ID No. EPA-R08-OAR-2015-0709), lists oil and natural gas production
projects in the Uinta Basin that have been subject to evaluation
under NEPA.
\13\ Final Rule: Federal Implementation Plan for True Minor
Sources in Indian Country in the Oil and Natural Gas Production and
Natural Gas Processing Segments of the Oil and Natural Gas Sector;
Amendments to the Federal Minor New Source Review Program in Indian
Country to Address Requirements for True Minor Sources in the Oil
and Natural Gas Sector, 81 FR 35943 (June 3, 2016); docket No. EPA-
HQ-OAR-2014-0606, available at http://www.regulations.gov, accessed
August 16, 2019.
\14\ Final Rule: Amendments to Federal Implementation Plan for
Managing Air Emissions from True Minor Sources in Indian Country in
the Oil and Natural Gas Production and Natural Gas Processing
Segments of the Oil and Natural Gas Sector, 84 FR 21240 (May 14,
2019); Docket No. EPA-HQ-OAR-2014-0606, available at http://www.regulations.gov, accessed August 16, 2019.
\15\ As defined in the Federal Minor New Source Review Program
in Indian Country at 40 CFR 49.152, a true minor source is a source
that emits or has the potential to emit regulated NSR pollutants in
amounts that are less than the major source thresholds in Sec.
49.167 (federal preconstruction permit program for major sources in
nonattainment areas in Indian country) or Sec. 52.21 (federal
preconstruction permit program for major sources in attainment/
unclassifiable areas), as applicable, but equal to or greater than
the minor NSR thresholds in Sec. 49.153 (federal preconstruction
permit program for minor sources in Indian country), without the
need to take an enforceable restriction to reduce its potential to
emit to such levels.
\16\ See 40 CFR 49.105. The National O&NG FIP specifies that
sources must comply with, as applicable, the following standards:
NESHAP 40 CFR part 63, subpart DDDDD; NESHAP 40 CFR part 63, subpart
ZZZZ; NSPS IIII 40 CFR part 60, subpart IIII; NSPS 40 CFR part 60,
subpart JJJJ; NSPS 40 CFR part 60, subpart Kb; NSPS 40 CFR part 60,
subpart OOOOa; NESHAP 40 CFR part 63, subpart HH; and NSPS 40 CFR
part 60, subpart KKKK.
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In this action we are proposing to continue the streamlined
construction authorization mechanism permanently for true minor oil and
natural gas sources on the Indian country portions of the U&O
Reservation that are part of the Uinta Basin Ozone Nonattainment Area
through a different regulatory mechanism than the one we employed in
our recent final action (i.e., amending the National O&NG FIP).
Instead, in this action we are proposing to apply the requirements of
the National O&NG FIP (through 40 CFR part 49, subpart K) to the
portions of the U&O Reservation that are included in the Uinta Basin
Nonattainment Area. The effect of this proposal, if finalized as
proposed, will be the permanent continuation of uninterrupted
streamlined construction authorizations on the U&O Reservation; the
advantage of using the different regulatory mechanism that we are
proposing here is that the requirements (or at least reference to them)
for the Indian country portions of the U&O Reservation that are part of
the Uinta Basin Ozone Nonattainment Area relative to oil and natural
gas will be located in one place in the Code of Federal Regulations,
which we believe provides a more efficient and user-friendly
approach.\17\ This will be described in greater detail in Sections
IV.C. and V.E.
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\17\ If this action as proposed is finalized, then the EPA's
intent would be to propose to withdraw its other action in which it
amended the National O&NG FIP to provide streamlined construction
authorizations as it would be redundant and no longer needed.
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In the preamble to the final National O&NG FIP published on June 3,
2016, we indicated that the most appropriate means for addressing air
quality concerns on specific reservations due to impacts from oil and
natural gas activity is through area- or reservation-specific FIPs and
not through the National O&NG FIP. Further, we stated that such FIPs
may need to include requirements for existing, new and modified sources
beyond those in the National O&NG FIP.\18\ Consistent with that
approach, this action would impose some requirements for new and
modified sources that are in addition to what is required by the eight
federal oil and natural gas sector emissions standards incorporated in
the National O&NG FIP. Therefore, new and modified true minor oil and
natural gas sources on the U&O Reservation that would use the National
O&NG FIP for construction authorization may have to comply with other
requirements for certain equipment or activities not covered by the
eight federal standards, as applicable under this action, in addition
to the requirements in the National O&NG FIP.\19\ We are relying on the
VOC emissions reductions in this action to support the limited
extension of the National O&NG FIP to the Indian country portion of the
Uinta Basin Ozone Nonattainment Area.
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\18\ See 81 FR 35964 and 35968.
\19\ As described in detail later, this action proposes to
exempt certain equipment and activities that are subject to the
emissions control requirements of certain federal standards, a
subset of the eight federal standards in the National O&NG FIP, from
having to comply the emissions control requirements in this action
for those same equipment and activities, but there are other
equipment, such as small and remote glycol dehydrators, that are not
regulated by those federal standards, but are proposed to be
regulated in this action.
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Emissions from existing oil and natural gas sources have been shown
to be the largest contributor to VOC emissions on the U&O Reservation
and in the Uinta Basin, and therefore, the largest contributor to
elevated winter ozone levels in the area. Implementing this proposed
U&O FIP at existing oil and natural gas sources on the U&O Reservation
will result in significant annual VOC reductions, thus improving air
quality within the Basin.
The combination of this proposed U&O FIP (when finalized) and the
National O&NG FIP amendments is intended to: (1) Improve air quality on
the U&O Reservation; (2) promote a more consistent regulatory
environment across the Basin; and (3) ensure that the emissions
reductions achieved from this proposed U&O FIP can be the basis for new
development and a streamlined construction authorization mechanism for
new or modified true minor oil and natural gas sources wishing to
locate or expand on the Indian country portions of the ozone
nonattainment area through the National O&NG FIP amendments.
III. Background
A. Uintah and Ouray Indian Reservation
The Uintah and Ouray Indian Reservation was formed from the Uintah
Valley and Uncompahgre Reservations, which were established by
executive order in 1861 and 1882, respectively.\20\ In 1886 the
Department of the Interior merged the two reservations to create the
U&O Reservation, and in 1948 Congress expanded the Reservation with
[[Page 3497]]
the Hill Creek Extension.\21\ The U&O Reservation's boundaries have
been further addressed and explained in a series of federal court
decisions.\22\
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\20\ See Exec. Order of Oct. 3, 1861, reprinted in 1 Charles J.
Kappler, Indian Affairs: Laws and Treaties 900 (1904); confirmed by
Congress in the Act of May 5, 1864, ch. 77, 13 Stat. 63; Exec. Order
of Jan. 5, 1882, reprinted in Indian Affairs: Laws and Treaties at
901.
\21\ U.S. Office of Indian Affairs, Dept. of the Interior,
Annual Report of the Commissioner of Indian Affairs, at 226 (1886);
62 Stat. 72 (1948).
\22\ See Ute Indian Tribe v. Utah, 521 F. Supp. 1072 (D. Utah
1981); Ute Indian Tribe v. Utah, 716 F.2d 1298 (10th Cir. 1983); Ute
Indian Tribe v. Utah, 773 F.2d 1087 (10th Cir. 1985) (en banc),
cert. denied, 479 U.S. 994 (1986); Hagen v. Utah, 510 U.S. 399
(1994); Ute Indian Tribe v. Utah, 935 F. Supp. 1473 (D. Utah 1996);
Ute Indian Tribe v. Utah, 114 F.3d 1513 (10th Cir. 1997), cert.
denied, 522 U.S. 1107 (1998); Ute Indian Tribe v. Utah, 790 F.3d
1000 (10th Cir. 2015), cert. denied, 136 S. Ct. 1451 (2016); and Ute
Indian Tribe v. Myton, 835 F.3d 1255 (10th Cir. 2016), cert.
dismissed, 137 S. Ct. 2328 (2017).
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B. Tribal Authority Rule
Section 301(d) of the Clean Air Act (CAA) authorizes the EPA to
treat Indian tribes in the same manner as states for purposes of
implementing the CAA over their entire reservations and over any other
areas within their jurisdiction, and directs the EPA to promulgate
regulations specifying those provisions of the CAA for which such
treatment is appropriate.\23\ It also authorizes the EPA, when the EPA
determines that the treatment of Indian tribes as identical to states
is inappropriate or administratively infeasible, to provide by
regulation other means by which the EPA will directly administer the
CAA.\24\ Acting principally under that authority, on February 12, 1998,
the EPA promulgated the Tribal Authority Rule (TAR).\25\ In the TAR, we
determined that it was appropriate to treat eligible tribes in the same
manner as states for all CAA statutory and regulatory purposes, except
a list of specified CAA provisions and implementing regulations
thereunder.\26\ That list of excluded provisions includes specific plan
submittal and implementation deadlines for NAAQS-related requirements,
among them the CAA section 110(a)(2)(C) requirement to submit a program
(including a permit program as required in parts C and D of the CAA) to
regulate the modification and construction of any stationary source as
necessary to assure that the NAAQS are achieved. Other provisions for
which we determined that we would not treat tribes in the same manner
as states include CAA section 110(a)(1) (SIP submittal) and CAA section
110(c)(1) (directing the EPA to promulgate a FIP ``within 2 years''
after we find that a state has failed to submit a required plan or has
submitted an incomplete plan, or within 2 years after we disapprove all
or a portion of a plan).
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\23\ 42 U.S.C. 7601(d)(1) and (2); See 63 FR 7254-57 (February
12, 1998) (explaining that CAA section 301(d) includes a delegation
of authority from Congress to eligible Indian tribes to implement
CAA programs over all air resources within the exterior boundaries
of their Reservations).
\24\ 42 U.S.C. 7601(d)(4).
\25\ ``Indian Tribes: Air Quality Planning and Management.'' see
63 FR 7254 (February 12, 1998); 40 CFR 49.1-49.11.
\26\ 40 CFR 49.3-.4. To be eligible for treatment in a similar
manner as a state (TAS) under the Tribal Authority Rule, a tribe
must meet four requirements: (1) Be a federally recognized tribe;
(2) have a governing body carrying out substantial governmental
duties and functions; (3) propose to carry out functions pertaining
to the management and protection of air resources of the tribe's
reservation or other areas within the tribe's jurisdiction; and (4)
be reasonably expected to be capable of carrying out the functions.
40 CFR 49.6. A tribe interested in administering a particular CAA
program or function may apply to the appropriate regional
administrator for a determination of whether it meets these TAS
eligibility criteria with respect to that program or function. 40
CFR 49.7.
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The TAR preamble clarified that by including CAA section 110(c)(1)
on the list at 40 CFR 49.4, the ``EPA is not relieved of its general
obligation under the CAA to ensure the protection of air quality
throughout the nation, including throughout Indian country.'' \27\ The
preamble confirmed that the ``EPA will continue to be subject to the
basic requirement to issue a FIP for affected tribal areas within some
reasonable time.'' \28\ Consistent with those statements, the TAR
includes a provision requiring the EPA to ``promulgate without
unreasonable delay such Federal implementation plan provisions as are
necessary or appropriate to protect air quality,'' unless a complete
tribal implementation plan is submitted or approved.\29\
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\27\ See 63 FR at 7265 (February 12, 1998).
\28\ Id.
\29\ 40 CFR 49.11(a).
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The Ute Indian Tribe has not applied for TAS for the purpose of
administering a Tribal Implementation Plan (TIP) under the CAA; nor has
it submitted a TIP for review and approval. Thus, with respect to the
U&O Reservation, there is currently no submitted or EPA-approved tribal
plan that would address the air quality purposes described earlier. The
FIP the EPA is proposing provides such a plan and applies to all Indian
country lands within the exterior boundaries of the U&O Reservation.
C. Federal Indian Country Minor NSR Rule
1. What is the Federal Indian Country Minor NSR rule?
In 2006, acting under the authority provided in CAA section 301(d)
and in the TAR, we proposed the FIP regulation: ``Review of New Sources
and Modifications in Indian Country'' (Indian Country NSR rule).\30\ As
a part of this regulation, the EPA made a finding that it was necessary
or appropriate to protect air quality by proposing a FIP to establish a
program to regulate the modification and construction of minor
stationary sources consistent with the requirements of section
110(a)(2)(c) of the CAA, where there was no EPA-approved tribal minor
NSR permit program in Indian country to regulate construction of new
and modified minor sources and minor modifications of major sources. We
call this part of the Indian Country NSR rule the Federal Indian
Country Minor NSR rule. In developing that FIP, we sought \31\ to
``establish a flexible preconstruction permitting program for minor
sources in Indian country that is comparable to similar programs in
neighboring states in order to create a more consistent regulatory
environment for owners/operators within and outside of Indian
country.'' The Federal Indian Country Minor NSR rule provides a
mechanism for issuing preconstruction permits for the construction of
new minor sources and certain modifications of major and minor sources
in areas covered by the rule. In developing the rule, the EPA conducted
extensive outreach and consultation, along with a 7-month public
comment period that ended on March 20, 2007. The comments provided
detailed information specific to Indian country and the final Federal
Indian Country Minor NSR rule incorporated many of the suggestions we
received. We promulgated final rules on July 1, 2011,\32\ and the FIP
became effective on August 30, 2011.
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\30\ ``Review of New Sources and Modifications in Indian
Country,'' Proposed Rule, See 71 FR 48696 (Aug. 21, 2006).
\31\ See 76 FR 38754 (July 1, 2011).
\32\ ``Review of New Sources and Modifications in Indian
Country,'' Final Rule, See 76 FR 38748 (July 1, 2011).
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The Federal Indian Country Minor NSR rule applies to existing, new,
and modified minor stationary sources and to minor modifications at
existing major stationary sources in Indian country \33\ where there is
no EPA-approved program in place. Tribes can elect to develop and
implement their own EPA-approved program under the TAR,\34\ but
[[Page 3498]]
are not required to do so.\35\ In the absence of an EPA-authorized
program, the EPA implements the program. Tribes can request
administrative delegation of the federal program from the EPA and may
be authorized by the EPA to implement agreed upon rules or provisions
on behalf of the Agency.
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\33\ 40 CFR 49.153. Existing sources are only subject to the
registration requirements unless they undergo modification.
\34\ To be eligible to develop and implement an EPA-approved
program, under the Tribal Authority Rule a tribe must meet four
requirements: (1) Be a federally-recognized tribe; (2) have a
functioning government carrying out substantial duties and powers;
(3) propose to carry out functions pertaining to air resources of
the reservation or other areas within the tribe's jurisdiction; and
(4) be reasonably expected to be capable of carrying out the
program. See 40 CFR 40 CFR 49.1-49.11.
\35\ Tribes can also establish permit fees under a tribal
permitting program pursuant to tribal law, as do most states.
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Any existing, new, or modified stationary source in the oil and
natural gas sector that emits or has the potential to emit (PTE) a
regulated NSR pollutant in amounts equal to or greater than the minor
NSR thresholds in the Federal Indian Country Minor NSR rule, but less
than the amount that would qualify the source as a major source or a
major modification for purposes of the PSD or nonattainment major NSR
programs, must submit a registration form to the EPA containing
information on, among other things, source-wide actual emissions of NSR
regulated pollutants, information on the methods used to calculate the
emissions, and descriptions of the various emitting activities and
equipment operated at the source. Existing, new, and modified oil and
natural gas sources that commenced construction before October 3, 2016,
complied with the Federal Indian Country Minor NSR Permit Program by
registering under the Existing Source Registration Program at 40 CFR
49.160. Beginning October 3, 2016, the owner/operator of any new true
minor oil and natural gas source must comply with the National O&NG FIP
or apply for and obtain a site-specific true minor NSR permit before
beginning construction. Likewise, the owner/operator of any existing
stationary source (minor or major) must comply with the National O&NG
FIP or apply for and obtain a minor NSR permit before beginning
construction of a physical or operational change that will increase the
allowable emissions of the stationary source in amounts equal to or
above the specified threshold amounts, if the change does not otherwise
trigger PSD or nonattainment major or minor NSR permitting
requirements.\36\
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\36\ A source may, however, be subject to certain monitoring,
recordkeeping, and reporting (MRR) requirements under the major NSR
program, if the change has a reasonable possibility of resulting in
a major modification. A source may be subject to both the Federal
Indian Country Minor NSR rule and the reasonable possibility MRR
requirements of the major NSR program(s).
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2. What are the minor NSR thresholds?
The ``minor NSR thresholds'' establish cutoff levels for each
regulated NSR pollutant. If a source has a PTE in amounts lower than
the thresholds,\37\ then it is exempt from the Federal Indian Country
Minor NSR rule for that pollutant. New or modified sources that have a
PTE in amounts that are: (1) Equal to or greater than the minor NSR
thresholds; and (2) less than the major NSR thresholds (generally 100
or 250 tons per year (tpy)) are ``minor sources'' of emissions and
subject to the Federal Indian Country Minor NSR rule requirements at 40
CFR 49.151 through 49.161. Modifications at existing major sources that
have PTE equal to or greater than the minor NSR thresholds, but less
than the major NSR significant emission rates (range 10-100 tpy,
depending on the pollutant) are also ``minor sources'' of emissions and
subject to the Federal Indian Country Minor NSR rule requirements.
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\37\ See 40 CFR 49.153 and Table 1.
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The minor NSR thresholds for VOC emissions for sources in Indian
country are 2 tpy in nonattainment areas and 5 tpy in attainment and
unclassifiable areas. Portions of the U&O Reservation are currently
designated unclassifiable for the 2008 ozone NAAQS. As discussed
previously and further in Section D (Air Quality and Attainment
Status), other portions of the U&O Reservation are included in the
Uinta Basin Ozone Nonattainment Area, and, therefore, the minor NSR
thresholds for VOC are 2 tpy in those portions of the reservation.
D. Air Quality and Attainment Status
With respect to air quality, ozone levels in the Uinta Basin, in
which the U&O Reservation is located, have reached unhealthy levels
that warrant action. The 2015 8-hour ozone NAAQS is 70 parts per
billion (ppb).\38\ Compliance with the NAAQS is determined by
comparison to a ``design value'' based on a three-year average of the
fourth highest daily maximum 8-hour average ozone levels measured in a
year at each monitoring site. The state of Utah, the National Park
Service (NPS), and the Ute Indian Tribe operate ozone,
PM2.5, and NO2 monitors in and around the Uinta
Basin. The ambient air concentrations measured at some of these
stations show that ozone levels in the Uinta Basin have repeatedly
violated both the 2008 and 2015 ozone NAAQS. Based on 2012-2017
regulatory air quality monitoring data, ozone design values exceed the
2015 ozone NAAQS at five monitoring sites in the Uinta Basin. The
highest valid ozone design value in the Uinta Basin for 2012-2017 was
from the Ouray monitor at 88 ppb.\39\ Additionally, higher single 8-
hour average ozone concentrations were observed at some monitoring
sites, before the sites were designated as regulatory monitors.\40\ For
example, 8-hour average ozone concentrations reached values as high as
141 ppb at the Ouray monitor in March 2013. This concentration
corresponds to an Air Quality Index value of 211, which is
characterized as ``Very Unhealthy.'' \41\ As discussed previously, the
EPA designated areas in the Uinta Basin as marginal nonattainment for
the 2015 ozone standard.\42\ The EPA is issuing this notice of proposed
rulemaking (NPRM) today because we have concluded that it is necessary
and appropriate to take action to protect air quality on the U&O
Reservation due to these elevated ozone levels.
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\38\ Revised Ozone NAAQS was signed by EPA Administrator Gina
McCarthy on October 1, 2015, See 80 FR 65292 (October 26, 2015).
\39\ Valid design values are the regulatory statistic to
determine compliance with a NAAQS. They are calculated in accordance
with the appropriate NAAQS-specific appendix to 40 CFR part 50. For
the 2008 Ozone NAAQS (75 ppb), the appropriate appendix is 40 CFR
part 50, Appendix P, and for the 2015 Ozone NAAQS (70 ppb) it is 40
CFR part 50, Appendix U. Regulatory ozone data is available at
https://www.epa.gov/air-trends/ozone-trends, accessed August 16,
2019.
\40\ A ``regulatory'' monitor is a monitor that meets EPA's air
quality monitoring requirements for siting, equipment selection,
data sampling protocols, quality assurance and so on under EPA's
monitoring regulations at 40 CFR part 58.
\41\ The Air Quality Index (AQI) is a normalized system to allow
the public to compare health risks of different air pollutants on a
common scale. The AQI is divided into six levels of health concern:
Good, Moderate, Unhealthy for Sensitive Groups, Unhealthy, Very
Unhealthy, and Hazardous.
\42\ Affected areas include portions of Uintah and Duchesne
counties below 6,250 feet, including portions of the U&O
Reservation.
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Ambient ozone is a secondary pollutant that is formed from the two
primary precursor emissions of VOC and NOX. Ozone is not
emitted directly into the air but is created when VOC and
NOX react in the presence of sunlight. Air quality data and
studies in the Uinta Basin show that winter ozone levels above the
ozone NAAQS are due to a combination of the unique meteorological and
topographical features of the Basin, and abundant local ground level
emissions of VOC and NOX. The unique meteorological and
topographic features in the Uinta Basin are strong and persistent
temperature inversions forming over snow covered ground and elevated
terrain completely surrounding a low basin. The stable atmosphere
allows the emissions to accumulate and react with sunlight but prevents
the emissions from escaping the temperature inversion layer and
dispersing. Therefore, ozone continues to form while the unique
[[Page 3499]]
meteorological conditions persist.\43\ The state of Utah conducted
special field studies in the Uinta Basin from 2011 to 2014 to
understand the emissions sources that contribute to winter ozone.
Reports for the winter ozone field studies for each year are available
on the UDEQ web page.\44\ These studies found that the oil and natural
gas production sector is the most significant anthropogenic contributor
of VOC and NOX emissions in the Basin. The studies also
concluded that ozone production in the Basin is sensitive to reductions
in VOC emissions but relatively less sensitive to reductions in
NOX emissions. Thus, ozone levels in the Uinta Basin are
being more significantly influenced by VOC emissions than by
NOX emissions.
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\43\ The RIA for this proposed rule contains a more detailed
discussion of winter ozone and can be viewed in the docket for this
rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
\44\ ``Ozone in the Uinta Basin,'' https://deq.utah.gov/air-quality/ozone-in-the-uinta-basin, August 16, 2019.
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The EPA has determined that the proposed action would result in
large reductions of VOC emissions, and relatively small increases in
NOX emissions, and that this result is expected to reduce
ambient ozone and reduce the severity of exceedances of the 2008 and
2015 ozone NAAQS. As discussed in more detail later, the proposed
action includes a requirement for owners/operators to submit emissions
inventories on a triennial basis. This information will enable the
successful partnership to continue among the EPA, the UDEQ, the Tribe
and industry in maintaining an accurate oil and natural gas emissions
inventory for the Uinta Basin to be used, in part, as a tool for
managing the Basin's air quality.
We have previously informed the public of our intent to undertake
action specific to the U&O Reservation; as noted earlier, in the
preamble to the National O&NG FIP, we indicated that: ``For the Uintah
and Ouray Reservation, we have sufficient concerns about the air
quality impacts from existing sources that we plan to propose a
separate U&O FIP.'' \45\ After further review, the EPA concludes that
action is needed to address poor air quality on the U&O Reservation.
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\45\ See 81 FR at 35963 (June 3, 2016).
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E. Emissions Information
In 2017, the EPA, in partnership with the UDEQ and the Ute Indian
Tribe, developed the 2014 Uinta Basin Emissions Inventory, an emission
inventory of oil and natural gas activity in the Uinta Basin that was
populated with data provided by oil and natural gas operators in the
Basin.\46\ We are also aware of several other available sources of
information on air emissions from oil and natural gas activity in the
Uinta Basin, including: (1) The 2014 National Emissions Inventory (2014
NEI); \47\ (2) a study by the Western Regional Air Partnership (WRAP);
\48\ (3) existing minor source registration data submitted to the EPA
per the Federal Indian Country Minor NSR Program; \49\ and (4) the EPA
Greenhouse Gas Reporting Program, subpart W Petroleum and Natural Gas
Systems.\50\ They are discussed in more detail in the Regulatory Impact
Analysis (RIA) for this proposed rule.\51\
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\46\ The inventory and supporting analysis can be viewed in the
docket for this rule (Docket ID No. EPA-R08-OAR-2015-0709),
Microsoft Excel spreadsheet titled ``2014 UB EI summary data U&O FIP
NPRM''. The complete, detailed dataset for the 2014 Uinta Basin
Emission Inventory can also be viewed in the docket in a SQLite
database titled ``OGEI_v2.2_2014FINAL.db''. We are proposing in this
proposed U&O FIP to require owners and operators to submit triennial
emissions inventories, like a requirement proposed by the UDEQ in
October of 2017. These triennial updates will provide information on
how emissions are changing in the Basin from the 2014 baseline. See
Section V (Summary of FIP Provisions).
\47\ 2014 National Emissions Inventory (2014 NEI), available at
https://www.epa.gov/air-emissions-inventories/2014-nei-data,
accessed August 16, 2019. The UDEQ has submitted the 2014 Uinta
Basin Emissions Inventory to the 2014 NEI, but the publicly
available NEI has not yet been updated to include the Uinta Basin
inventory. Analysis of the 2014 NEI for the purposes of this
proposed U&O FIP was prepared using the version publicly available
before the UDEQ.
\49\ Data from existing minor source registration reports
submitted under 40 CFR 49.160 of the Federal Indian Country Minor
NSR Program by operators of sources on the Indian country lands
within the U&O Reservation.
\48\Western Regional Air Partnership (WRAP), O&G Emissions
Workgroup: Phase III Inventory, Uinta Basin Reports, 2012 Mid-Term
Projection Technical Memo, ``Development of 2012 Oil and Gas
Emissions Projections for the Uinta Basin'', March 25, 2009,
available at http://www.wrapair2.org/Phase III.aspx, accessed August
16, 2019. Some of the 2014 Uinta Basin Emissions Inventory was
generated from prorating the 2012 WRAP estimates (which prorated and
adjusted their 2006 work) to 2014 activity levels.
\50\ EPA Greenhouse Gas Reporting Program (GHGRP) Petroleum and
Natural Gas Systems, available at https://www.epa.gov/ghgreporting/ghgrp-petroleum-and-natural-gas-systems, accessed August 16, 2019.
\51\ The RIA can be viewed in the docket for this rulemaking
(Docket ID No. EPA-R08-OAR-2015-0709).
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The 2014 NEI provides a general picture of the relative
contribution of oil and natural gas emissions compared to other
industry sectors, indicating that emissions from the production segment
of the oil and natural gas sector were estimated to be the largest
anthropogenic contributor of both VOC and NOX emissions in
the Uinta Basin. The WRAP study provides a general picture of the
relative emissions contribution in the Basin from various oil and
natural gas equipment and activities on Indian country lands. The
existing minor source registration data provide a general picture of
the large percentage of unpermitted and likely uncontrolled minor
emissions sources on the U&O Reservation. The EPA Greenhouse Gas
Reporting Program, subpart W, provides annual reports by operators of
activity levels and methane emissions from oil and natural gas
operations in the Uinta Basin. The 2014 Uinta Basin Emissions Inventory
is a comprehensive source of oil and natural gas source VOC emissions
data for the Uinta Basin that provided information for the cost and
benefit analysis supporting this rulemaking.
The 2014 Uinta Basin Emissions Inventory indicates that the
majority of existing oil and natural gas sources in the region are on
the U&O Reservation. Most of these existing oil and natural gas sources
on the U&O Reservation are minor sources and are uncontrolled. The 2014
NEI indicates that, compared to other industry sector sources, existing
oil and natural gas sources are cumulatively the largest contributor of
VOC and NOX to measured exceedances of the ozone NAAQS in
the Uinta Basin. Existing oil and natural gas sources on the portions
of the Basin regulated by the UDEQ are subject to emission reduction
requirements, while existing sources on the U&O Reservation are either
subject to less stringent regulation or no regulation at all.
Specifically, the inventory shows that 79 percent of all existing
oil and natural gas facilities in the Uinta Basin are located on Indian
country lands within the U&O Reservation, producing oil and natural gas
(and processing natural gas) from 76 percent of all producing wells in
the Basin. According to the inventory, over 71,000 tons of VOC and
almost 9,500 tons of NOX emissions were emitted in 2014 from
existing oil and natural gas sources on the U&O Reservation. That is
approximately 81 percent of the total oil and natural gas-related VOC
emissions in the Uinta Basin and approximately 70 percent of the total
oil and natural gas-related NOX emissions in the Uinta
Basin. These data confirm that the bulk of the ozone-related emissions
in the Uinta Basin are released from sources on the Indian country
lands within the U&O Reservation.
Many of the oil and natural gas sources on the U&O Reservation are
uncontrolled. According to the 2014 Uinta Basin Emissions Inventory, on
the Indian country lands within the U&O Reservation, 85 percent of the
total
[[Page 3500]]
number of existing storage tanks, 97 percent of the total number of
existing glycol dehydrators and 99 percent of existing pneumatic pumps
are uncontrolled emitters of VOC. By contrast, on state-regulated land
within the Basin, 67 percent of the total number of existing storage
tanks and 14 percent of the total number of existing glycol dehydrators
are uncontrolled (uncontrolled pneumatic pump numbers are relatively
equivalent to Indian country at 98 percent). The UDEQ has adopted
revisions to existing oil and natural gas source requirements and
existing minor source permitting requirements, and has adopted new
requirements, including a Permit by Rule that replaces the requirement
for minor oil and natural gas sources to obtain a site-specific
permit.\52\ Now that the revised and new requirements are effective, we
expect the percentage of uncontrolled existing storage tanks and glycol
dehydrators in the UDEQ's jurisdiction will decrease from what was
reported in the 2014 inventory. The UDEQ's rule revisions and new rules
are discussed in more detail in Section IV.D (Developing the Proposed
Control Requirements). In addition, the 2014 inventory shows that
emissions from oil and natural gas wastewater disposal facilities on
the Indian country lands within the U&O Reservation comprise
approximately 33 percent of the total VOC emissions from oil and
natural gas activity on the U&O Reservation. As explained in Section
IV. D. (Developing the Proposed Control Requirements), these facilities
may not be controlled under the CAA, because they do not meet the
applicability criteria of preconstruction permitting programs or
federal emissions standards regulating them.
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\52\ Utah State Bulletin, Official Notices of Utah State
Government, Filed January 03, 2018, 12:00 a.m. through January 16,
2018, 11:59 p.m., 11:59 p.m., Number 2018-3, February 01, 2018,
Nancy L. Lancaster, Managing Editor, pages 46-68, available at
https://rules.utah.gov/publicat/bull_pdf/2018/b20180201.pdf,
accessed August 16, 2019.
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Based on this collection of emissions information (and other
information about meteorological conditions and local geography), the
EPA has concluded that winter ozone levels in the Uinta Basin are most
significantly influenced by VOC emissions from the presence of numerous
minor, unpermitted and largely uncontrolled oil and natural gas
production operations on the U&O Reservation.
F. What is a FIP?
Under section 302(y) of the CAA, the term ``Federal implementation
plan'' means ``a plan (or portion thereof) promulgated by the
Administrator to fill all or a portion of a gap or otherwise correct
all or a portion of an inadequacy in a State implementation plan, and
which includes enforceable emission limitations or other control
measures, means or techniques (including economic incentives, such as
marketable permits or auctions of emissions allowances), and provides
for attainment of the relevant national ambient air quality standard.''
As discussed previously in section III.B., CAA sections 301(a) and
301(d)(4) and 40 CFR 49.11(a) authorize the EPA to promulgate such FIPs
as are necessary or appropriate to protect air quality if a Tribe does
not submit or receive EPA approval of a TIP.
The Federal Indian Country Minor NSR rule is an example of a FIP,
as discussed in section III.C. Another example of the EPA's use of its
FIP authority is to protect air quality in areas of Indian country with
no EPA-approved program, while at the same time seeking to provide a
consistent regulatory environment where appropriate, is the ``FIP for
Oil and Natural Gas Well Production Facilities; Fort Berthold Indian
Reservation (FBIR; Mandan, Hidatsa, and Arikara Nation), North
Dakota.'' \53\ In that rule, we took an important initial step to
control volatile organic compound (VOC) emissions from existing, new
and modified oil and natural gas operations on the FBIR. We drafted
requirements that were consistent to the greatest extent practicable
with the most relevant aspects of neighboring state and local rules
concerning the air pollutant emitting activities on the FBIR. We did
not intend at the time, nor did we expect, the regulation to impose
significantly different regulatory burdens upon industry or the
residents of the FBIR than those imposed by the rules of state and
local air agencies in the surrounding areas.
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\53\ See 78 FR 17836 (March 22, 2013).
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This proposed U&O FIP specific to the U&O Reservation would reduce
VOC emissions related to the formation of ozone, and it is needed to
protect air quality on the U&O Reservation because exceedances of both
the 2008 and the 2015 ozone NAAQS have occurred at air quality monitors
on and around the Reservation. Portions of the Uinta Basin, including
portions of the U&O Reservation, were designated by the EPA in 2018 as
nonattainment for the 2015 ozone NAAQS. Further, there are no currently
approved TIPs that apply to existing oil and natural gas sources on the
U&O Reservation. Finally, the majority of these sources are not
currently subject to federally required emissions controls, which is
discussed further in Section IV.A.
G. Oil and Natural Gas Sector in the Uinta Basin
The oil and natural gas sector in the Uinta Basin includes the
extraction and production of oil and natural gas, as well as the
processing, transmission, and distribution of natural gas.
Specifically, for oil, the sector in the Uinta Basin includes all
operations from the well to the transfer to an oil transmission
pipeline or other means of transportation to a petroleum refinery. The
petroleum refinery is not considered part of the oil and natural gas
sector. Thus, with respect to crude oil, the oil and natural gas sector
ends where crude oil enters an oil transmission pipeline or other means
of transportation to a petroleum refinery. For natural gas, the sector
includes all operations from the well to the final end user.
The oil and natural gas sector in the Uinta Basin can generally be
separated into four segments: (1) Oil and natural gas production; (2)
natural gas processing; (3) natural gas transmission and storage; and
(4) natural gas distribution. This proposed U&O FIP for oil and natural
gas sources on the U&O Reservation focuses on existing, new, and
modified sources in the first and second segments, oil and natural gas
production and natural gas processing, because the existing minor
sources in those segments cumulatively contribute the largest portion
of VOC emissions from the oil and natural gas sector on the U&O
Reservation. There are more than 6,700 individual oil and natural gas
sources on the U&O Reservation operated by 28 distinct entities, the
majority of which are well sites in the oil and natural gas production
segment.\54\ As discussed earlier, the 2014 NEI shows that emissions
from the production segment of the oil and natural gas sector were
estimated to be the largest anthropogenic contributor of both VOC and
NOX emissions in the Uinta Basin. Comparatively, the
categories that include oil and natural gas storage and transfer and
bulk gasoline terminals (segments 3 and 4), are reported in the 2014
NEI as contributing less than one percent each of the total VOC and
NOX emissions in
[[Page 3501]]
the Uinta Basin.\55\ Of the approximately 10,400 individual active oil
and natural gas wells in the Uinta Basin, over 7,900 wells, or about 76
percent, are on Indian country lands within the U&O Reservation.
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\54\ 2014 Uinta Basin Emissions Inventory. The inventory and
supporting analysis of the data can be viewed in the docket for this
NPRM (Docket ID No. EPA-R08-OAR-2015-0709), including a spreadsheet
titled ``2014 UB EI summary data U&O FIP NPRM.xlsx.''
\55\ Based on the NEI Source Type to Sector Crosswalk in the
2014 NEI at https://gispub.epa.gov/neireport/2014/, accessed August
16, 2019.
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The oil and natural gas production segment in the Uinta Basin
includes wells and all related processes used in the extraction,
production, recovery, lifting, stabilization, and separation or
treatment of oil and/or natural gas (including condensate). Production
components in the Uinta Basin may include wells and related casing
head, tubing head, and ``Christmas tree'' piping, as well as pumps,
compressors, heater treaters, separators, storage vessels, pneumatic
devices, pneumatic pumps, and natural gas dehydrators. Production
operations in the Uinta Basin also include the well drilling,
completion, and workover processes, and include all the portable non-
self-propelled apparatuses associated with those operations. Production
sites in the Uinta Basin include not only the sites where the wells
themselves are located, but also centralized gas and liquid gathering
sources where oil, condensate, produced water, and natural gas from
several wells may be separated, stored, and treated. Production
components in the Uinta Basin also include the smaller diameter, low-
to-medium-pressure gathering pipelines and related components that
collect and transport the oil, natural gas, and other materials and
wastes from the wells or well pads.
The natural gas production segment in the Uinta Basin ends where
the natural gas enters a natural gas processing plant. Where there is
no processing plant, the natural gas production segment ends at the
point where the natural gas enters the transmission segment for long-
line transport. The crude oil production segment in the Uinta Basin
ends at the storage and load-out terminal, which is the point of
custody transfer to an oil pipeline or for transport of the crude oil
to a petroleum refinery via trucks or railcars.
Each producing crude oil and natural gas field has its own unique
properties. The composition of the crude oil and the natural gas as
well as the reservoir characteristics are likely to be different across
all reservoirs. The RIA for this rule provides a more detailed overview
of the products and components of the oil and natural gas industry that
are relevant to the activities in the Uinta Basin.\56\
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\56\ The RIA can be viewed in the docket for this rulemaking
(Docket ID No. EPA-R08-OAR-2015-0709).
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IV. Development of the Proposed Rule
This proposed U&O FIP contains a common set of VOC emissions
controls at new, modified and existing oil and natural gas sources on
the U&O Reservation. We consulted existing federal CAA oil and natural
gas sector standards to develop the VOC emissions control requirements
of this proposed U&O FIP. To make VOC emissions control requirements
across the Basin consistent, this proposed U&O FIP would go beyond the
federal standards, in some cases, to regulate equipment and activities
that are not regulated by those standards, but are regulated by the
UDEQ, such as small, remote glycol dehydrators; low throughput storage
tanks; tanker truck loading and unloading; and certain voluntarily
operated control devices. Applicability of the proposed requirements,
including for equipment and activities that are regulated by the
federal standards, is also consistent with the applicability for
equivalent equipment and activities regulated by the UDEQ.
The streamlined construction authorization mechanism in the
National O&NG FIP applies on the Indian country portions of the U&O
Reservation that are part of the Uinta Basin Ozone Nonattainment Area,
as a result of our recent action amending the National O&NG FIP, as
previously mentioned. Such true minor sources are required to register
and comply with the eight federal standards in the National O&NG FIP,
as applicable, to meet the preconstruction permitting requirements of
the Federal Indian Country Minor NSR Program. Compliance with the eight
federal standards in the National O&NG FIP, as applicable, would not
relieve the owners/operators from the other applicable VOC control
requirements of this proposed U&O FIP, except that this proposed U&O
FIP would exempt certain equipment and activities from it that are in
compliance with the applicable federal standards for those equipment
and activities that constitute the requirements of the National O&NG
FIP.
A detailed discussion of this proposed U&O FIP requirements is
found in Section V. Summary of FIP Provisions.
A. Rationale for the Proposed Rule
As discussed earlier, available information indicates that: (1)
Winter ozone levels in the Uinta Basin are above the 2008 and 2015
ozone NAAQS, posing a threat to human health, which has led to the
designation of portions of the Uinta Basin, including portions of the
U&O Reservation, as marginal nonattainment for the 2015 ozone NAAQS;
(2) ozone production in the area is driven by a combination of unique
meteorological conditions, the geography of the Basin, and significant
local emissions of ozone precursors, primarily VOC emissions from
existing oil and natural gas activity in the Basin, the majority of
which occurs on the U&O Reservation; and (3) reductions in ozone levels
in the Basin is most sensitive to reductions in VOC emissions, and
relatively insensitive to reductions in NOX emissions.
Further, the majority of those oil and natural gas sources are
operating without any federally required emissions controls.\57\
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\57\ See Sections III.D. and III.E. for more detailed discussion
of air quality problems and emissions information, respectively.
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To address these facts, in this proposed action we are determining
that it is necessary and appropriate to promulgate this proposed U&O
FIP to protect air quality on the U&O Reservation, under the authority
provided at 40 CFR 49.11 and CAA sections 301(a) and 301(d)(4). This
action includes: (1) Proposed federally enforceable VOC emissions
control requirements for new, modified and existing oil and natural gas
sources and (2) a proposed requirement to apply the requirements of the
National O&NG FIP to new and modified true minor oil and natural gas
sources seeking to locate or expand on the Indian country portions of
the U&O Reservation that are part of the Uinta Basin Ozone
Nonattainment Area, including its streamlined construction
authorization mechanism. If the second part of today's action is
finalized as proposed, the EPA in a separate rulemaking plans to
propose withdrawing its recent rulemaking \58\ amending the National
O&NG FIP to extend its construction authorization mechanism for new and
modified true minor oil and natural gas sources to the Indian country
lands within the U&O Reservation that are included in the Uinta Basin
Ozone Nonattainment Area because it will no longer be necessary.
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\58\ See 84 FR 21240 (May 14, 2019).
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Together, the oil and natural gas source controls of this proposed
U&O FIP, the construction authorization mechanism of this proposed U&O
FIP and the amended National O&NG FIP will:
1. Improve air quality by reducing VOC emissions, thereby reducing
ozone,
[[Page 3502]]
HAP, and PM2.5 levels and protecting public health;
2. Ensure a consistent regulatory environment across the basin,
thereby providing certainty to industry and avoiding the imposition of
economic burdens on the Ute Indian Tribe or residents of the
Reservation; and
3. Support permanent, continued development of the Basin's oil and
natural gas resources through a streamlined construction authorization
mechanism.
This proposed U&O FIP's VOC emission control requirements will
apply to existing, new, and modified oil and natural gas production and
natural gas processing sources on the U&O Reservation, whether major or
minor.\59\
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\59\ The control requirements could apply to major oil and
natural gas sources because they may include uncontrolled emissions
units identical to those at minor sources. And while the major
sources have presumably been, or would be, at least partly subject
to controls through existing EPA standards and permitting
requirements, they could still include individual emissions units
for which control requirements are not applicable. Therefore, we
have determined that it is appropriate to apply the proposed VOC
control requirements of this rule to major oil and natural gas
sources as well as minor oil and natural gas sources.
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We have previously informed the public of our intent to undertake
this action, as noted earlier, in the preamble to the National O&NG
FIP: ``For the Uintah and Ouray Reservation, we have sufficient
concerns about the air quality impacts from existing sources that we
plan to propose a separate reservation-specific FIP.'' \60\ The EPA
remains concerned that there is a need for air quality protection on
the U&O Reservation. Implementation of the proposed rule is intended to
improve air quality, on the U&O Reservation specifically and the Uinta
Basin generally, and thereby to protect public health and help return
the area to attainment.
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\60\ See 81 FR 35944, 35963 (June 3, 2016).
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B. Uinta Basin Air Quality Solutions: Stakeholder Feedback
Consistent with the federal government's trust responsibility and
to improve our understanding of the potential environmental
implications of oil and natural gas production operations, the EPA has
consulted (and will continue to consult) with the Ute Indian Tribe on
this proposed U&O FIP. We appreciate the importance of oil and natural
gas activity for the economic vitality of the U&O Reservation, as
expressed to us by the Tribe during our government-to-government
consultations.
We have held numerous consultations with the Ute Indian Tribe and
participated in numerous tribally-convened stakeholder and other
meetings, in 2015, 2016, 2017, 2018 and 2019. We have also reached out
to stakeholders in 2015 and will continue to do so as follows: (1) Oil
and natural gas operators and representatives; (2) environmental
groups; (3) Federal Land Managers; and (4) local county officials.
These consultations and meetings addressed, at least in part, the issue
that has prompted this rulemaking, i.e., the need expressed by the Ute
Indian Tribe and others for continued streamlined authorizations to
construct to continue to be available on the U&O Reservation as part of
the Uinta Basin Ozone Nonattainment Area. For a complete list of these
consultations and meetings, including dates, locations and attendees,
please consult the docket to this rulemaking.\61\
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\61\ ``Meetings and Consultations Held with the Ute Indian Tribe
Concerning at Least Partly the Uintah and Ouray Indian Reservation
Federal Implementation Plan and the National Oil and Natural Gas
Federal Implementation Plan for Indian Country,'' March 1, 2019,
Docket No. EPA-R08-OAR-2015-0709, available at https://www.regulations.gov.
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The purpose of the government-to-government consultations were to
receive tribal comments and concerns. The purposes of the EPA, Tribe,
and UDEQ meetings were to discuss our intent to address ozone issues in
the Uinta Basin and to solicit input on potential solutions to the
region's air quality problem, while ensuring continued resource
development. We strive to provide greater regulatory certainty and
consistency across the Uinta Basin in the regulation of these
operations through enhanced data collection and analysis, improved
information sharing and partnerships, and focused compliance assistance
and enforcement. The EPA is committed to working closely with the Tribe
and the state of Utah during this process.
C. Ensuring Streamlined Construction Authorizations on the U&O
Reservation
The EPA is committed to achieving our primary objective of
improving air quality on the U&O Reservation in a manner that also
ensures that streamlined construction authorizations on the U&O
Reservation may proceed effectively and efficiently. Accordingly, we
have separately amended the National O&NG FIP to extend its
construction authorization mechanism to apply to new or modified true
minor oil and natural gas sources on the Indian country portions of the
U&O Reservation that are part of the Uinta Basin Ozone Nonattainment
Area, because the National O&NG FIP ceased to apply upon the effective
date of the nonattainment designation (August 3, 2018). The National
O&NG FIP, as originally promulgated, covered attainment, unclassifiable
and attainment/unclassifiable areas. New and modified true minor oil
and natural gas sources constructing in such areas are eligible for
coverage under the National O&NG FIP. Since the National O&NG FIP did
not apply in nonattainment areas, the streamlined construction
authorization mechanism for new and modified true minor oil and natural
gas sources was not available after August 3, 1018 for sources locating
on Indian country portions of the U&O Reservation that are part of the
Uinta Basin Ozone Nonattainment Area. Our recent action amending the
National O&NG FIP addressed the issue by permanently re-instating the
streamlined construction authorizations. However, we are also in this
action proposing to apply the National O&NG FIP (without alteration) to
new and modified true minor sources in the oil and natural gas
production and natural gas processing segments of the oil and natural
gas sector that propose to locate or expand on Indian country lands
within the U&O Reservation that are part of the Uinta Basin Ozone
Nonattainment area. While it may seem unnecessary to propose a
streamlined construction authorization mechanism in this action when
one is already in place permanently, we are doing so to ensure that the
requirements (or at least reference to them) for oil and natural gas
sources on the Indian country portions of the U&O Reservation that are
part of the Uinta Basin Ozone Nonattainment Area are in one place in
the CFR. We intend to follow up this rule when final with a proposal to
withdraw the amendments to the National O&NG FIP. In Section V.E.
below, we explain specifically what parts of the CFR will be affected
by today's proposed rule and the subsequent proposed rule withdrawal.
Upon the effective date of the nonattainment designation (August 3,
2018), the EPA was required to issue site-specific permits to true
minor oil and natural gas sources. The Ute Indian Tribe and various
industry representatives expressed concern that the EPA might not be
able to keep pace with the demand for site-specific oil and natural
gas-related permits on the U&O Reservation given all that is involved
with approving and issuing a site-specific permit. There was concern
that a lag in permit issuance could place sources in Indian country at
a competitive disadvantage compared to
[[Page 3503]]
similar sources located in UDEQ-regulated areas, where minor sources
have expedited permitting options available. Extending the National
O&NG FIP's permitting approach to the portions of the U&O Reservation
designated nonattainment, among other benefits, avoided any such
inequity.
There is, however, an important consideration to extending the
National O&NG FIP to the U&O Reservation portion of the Uinta Basin
Ozone Nonattainment Area. Specifically, this proposed U&O FIP would
reduce ozone-forming emissions from existing, new, and modified oil and
natural gas sources, in order to ensure that new and modified true
minor source growth can occur in the area while protecting air quality.
To accomplish those reductions, we are proposing the control
requirements described later in Section V.
D. Developing the Proposed Control Requirements
Our objectives in developing proposed requirements to control VOC
emissions from existing, new, and modified oil and natural gas sources
on the U&O Reservation are to address the Basin's degraded air quality,
to provide regulatory consistency across the Uinta Basin, and to allow
for continued growth of oil and natural gas resources on the U&O
Reservation. To ensure that the regulatory requirements would be the
same as or comparable on balance across the Uinta Basin, we focused on
using UDEQ regulations and preconstruction permitting requirements
being implemented by the UDEQ for new, modified and existing oil and
natural gas sources within the Uinta Basin to identify appropriate
requirements for controlling VOC emissions from the prominent oil and
natural gas emissions sources in the Basin. We consulted existing
federal preconstruction permitting and oil and natural gas sector
regulations for common emissions sources and determined that to meet
our objectives for this rulemaking, it is necessary to propose
requirements that are additional to what is required of new and
modified sources in existing federal requirements. Extending the
National O&NG FIP to the U&O Reservation will ensure an efficient and
protective construction authorization mechanism for new and modified
true minor sources. The combination of extending the National O&NG FIP
to the U&O reservation and promulgating the control requirements in
this proposed U&O FIP will reduce ozone-forming emissions from new, and
modified and existing oil and natural gas sources. To accomplish those
reductions, we are proposing the control requirements described in
Section V.
1. Determination of VOC-Producing Equipment/Activities To Regulate
To develop these requirements, we analyzed data submitted by the
owners/operators of existing sources under the 2014 Uinta Basin
Emissions Inventory. We used this information to determine the
equipment and operations that generate the largest portion of VOC
emissions from these sources. The inventory shows that 81 percent of
VOC emissions from existing oil and natural gas sources in the Uinta
Basin occur on Indian country lands within the U&O Reservation. The
highest VOC emissions from existing oil and natural gas sources in the
Uinta Basin come from (top 6 in order of highest to lowest): \62\ (1)
Wastewater ponds; (2) fugitive emissions; (3) pneumatic pumps; (4)
crude oil and condensate storage tanks; (5) pneumatic controllers; and
(6) glycol dehydrators. As noted earlier in Section III.D., we conclude
that winter ozone formation in the Basin is more sensitive to changes
in VOC emissions than changes in NOX emissions. Therefore,
we expect that reducing VOC emissions from these emissions sources will
result in lower ozone levels in the Uinta Basin.
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\62\ These six sources represent 93 percent of oil and natural
VOC emissions on the U&O Reservation.
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2. Evaluation of Federal Oil and Natural Gas and Permitting-Related
Requirements
We do not expect that many of the existing oil and natural gas
sources on the U&O Reservation, most of which are minor sources, are
currently subject to federal VOC emissions control requirements under
the CAA, including the New Source Performance Standards (NSPS) for the
Oil and Natural Gas Sector at 40 CFR part 60, subpart OOOO (NSPS OOOO),
and subpart OOOOa (NSPS OOOOa),\63\ the National Emissions Standards
for Hazardous Air Pollutants (NESHAP) for Oil and Production Facilities
at 40 CFR part 63, subpart HH (NESHAP HH),\64\ the Prevention of
Significant Deterioration (PSD) Permit Program at 40 CFR part 52, and
the Federal Indian Country Minor NSR Permit Program at 40 CFR part
49,\65\ because they do not meet the respective applicability criteria.
As we assembled a set of requirements for this proposed U&O FIP, we
considered CAA regulatory requirements in place for oil and natural gas
sources nationwide, in the Uinta Basin on the Indian country lands
within the U&O Reservation and on lands regulated by the UDEQ.
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\63\ NSPS OOOO was originally published in the Federal Register
on August 16, 2012 at 77 FR 49490, with revisions on September 23,
2013, July 17, 2014, December 31, 2014, and July 31, 2015.
Additional revisions, including the addition of subpart OOOOa, were
signed final by the Administrator on April 28, 2016. Information on
these rulemakings is available at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry, accessed August 19,
2019.
\64\ National Emission Standards for Hazardous Air Pollutants:
Oil and Natural Gas Production and Natural Gas Transmission and
Storage, originally published in the Federal Register on June 17,
1999 at 64 FR 32609, and revised on June 29, 2001 (66 FR 34548),
January 3, 2007 (72 FR 26), and August 16, 2012 (77 FR 49490).
Information on these rulemakings is available at: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry
and https://www.epa.gov/stationary-sources-air-pollution/clean-air-act-standards-and-guidelines-oil-and-natural-gas-industry, accessed
August 16, 2019.
\65\ Review of New Sources and Modifications in Indian Country,
published in the Federal Register on July 1, 2011 (76 FR 38748),
available at http://www.gpo.gov/fdsys/pkg/FR-2011-07-01/pdf/2011-14981.pdf, accessed August 19, 2019 (Federal Indian Country Minor
NSR Program). Program includes the ``Federal Implementation Plan for
True Minor Sources in Indian Country in the Oil and Natural Gas
Production and Natural Gas Processing Segments of the Oil and
Natural Gas Sector; Amendments to the Federal Minor New Source
Review Program in Indian Country to Address Requirements for True
Minor Sources in the Oil and Natural Gas Sector,'' Final Rule, U.S.
Environmental Protection Agency, Signed April 28, 2016 and available
at https://www.epa.gov/tribal-air/oil-and-natural-gas-sources-federal-implementation-plan-rule-indian-country, accessed August 16,
2019 (Indian Country Oil and Natural Gas True Minor Source FIP).
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VOC emissions at existing major oil and natural gas sources on the
U&O Reservation (far fewer in number than minor sources) should be
controlled through federal emissions control requirements under the
CAA, including the EPA's major source preconstruction permitting
program in Indian country; the synthetic minor permit provisions of the
Federal Indian Country Minor NSR rule; the NSPS OOOO or OOOOa; and
other EPA emissions standards in place for the oil and natural gas
sector.
We do acknowledge, however, that there may be individual emissions
units or processes at such major sources that are uncontrolled because
they are not subject to any emissions control requirements in a major
source permit and/or are not otherwise subject to a federal emissions
standard. For example, such units or processes may not be subject to
the EPA regulation because they do not meet the applicability criteria
in any NSPS or NESHAP.\66\ Another example concerns oil and natural gas
wastewater disposal facilities that rely on evaporation from ponds. The
2014 Uinta Basin Emissions Inventory shows that these types of
[[Page 3504]]
wastewater disposal facilities are the largest source of VOC emissions
at existing oil and natural gas operations on Indian country lands
within the U&O Reservation, emitting approximately 33 percent of the
VOC emissions for these areas.\67\ The majority of the VOC emissions
from these types of wastewater disposal facilities occur upstream of
the evaporation ponds, where wastewater is received and handled before
being discharged to the evaporation ponds--namely from vaults and skim
ponds, and to a lesser extent, from onsite storage tanks. The inventory
also indicates that certain individual wastewater disposal facilities
on Indian country lands within the U&O Reservation are estimated to
emit VOC emissions at major source levels (i.e., greater than 100 tpy).
While emissions from storage tanks at certain wastewater disposal
facilities may be considered point sources, the evaporation emissions
from vaults, skim ponds and evaporation ponds could be considered
fugitive and the oil and natural gas sector is not one of the industry
source categories listed in major source preconstruction permitting
programs that are required to include fugitive emissions when
determining whether or not the source is major.\68\ Fugitive emissions
may, however, be considered when determining whether or not a source is
major for HAP, which requires compliance with the Title V Operating
Permit Program requirements and may require compliance with NESHAP
requirements. The NESHAP for Offsite Waste and Recovery Operations at
40 CFR part 63, subpart DD, imposes control requirements on certain
wastewater disposal facilities, but these existing facilities on the
Indian country lands within the U&O Reservation may not meet any of the
very specific applicability criteria in subpart DD.\69\
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\66\ EPA has several NESHAP and NSPS in place that regulate
equipment and processes at oil and natural gas sources.
\67\ 2014 Uinta Basin Emissions Inventory. The inventory and
supporting analysis can be viewed in the docket for this NPRM
(Docket ID No. EPA-R08-OAR-2015-0709), Microsoft Excel spreadsheet
titled ``2014 UB EI summary data_U&O FIP NPRM.''
\68\ See 40 CFR 52.21(b)(1)(iii).
\69\ See the NESHAP for Offsite Waste and Recovery Operations at
40 CFR part 63, subpart DD. The NESHAP applies to sources that meet
ALL of the following criteria: (1) Meet the definition of a
``centralized waste treatment'' facility (CWT); (2) are a major HAP
source; (3) discharge effluent subject to CWA section 402 or 307(b)
permitting; AND (4) treatment of wastewater is the predominant
activity at the CWT.
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In contrast to existing major sources, most existing minor oil and
natural gas sources on the U&O Reservation are uncontrolled, although
some may be subject to NSPS OOOO or OOOOa. For example, the 2014 Uinta
Basin Emissions Inventory indicates that only 15 percent of the oil and
natural gas sources present in 2014 on Indian country lands within the
U&O Reservation were reported to be operating VOC emissions control
devices on their storage tanks, a significant source of oil and natural
gas VOC emissions. NSPS OOOO and OOOOa only apply to sources
constructed after the relative applicability dates and that meet the
other applicability criteria. Storage tanks at sources associated with
oil and natural gas production wells that began production after the
effective dates of NSPS OOOO or OOOOa may have low enough VOC emissions
that owners/operators are not required to control VOC emissions from
storage vessels.
In addition, some VOC emissions that are also HAP from certain
emissions units at existing minor sources, such as glycol dehydrators
and storage tanks with the potential for flash emissions, may be
regulated under the NESHAP for Oil and Natural Gas Production
Facilities at 40 CFR part 63, subpart HH (NESHAP HH).\70\ However, the
NESHAP does not require emission controls for lower-emitting glycol
dehydrators or storage tanks with throughputs below a certain level on
rural and remote Indian country lands within the U&O Reservation
because the units would not meet subpart HH's urban-based glycol
dehydrator applicability criteria or tank throughput applicability
threshold. The 2014 inventory, which indicates that 99 percent of the
glycol dehydrators operated at oil and natural gas sources on the
Indian country lands within the U&O Reservation are reported as
uncontrolled,\71\ supports the conclusion that most glycol dehydrators
on the U&O Reservation may not be subject to NESHAP HH. Therefore,
using the applicability criteria of relevant EPA regulations and
analyzing available emissions and other data, allows the EPA to
conclude that the majority of existing oil and natural gas minor
sources on the U&O Reservation have not been controlled under the CAA's
programs.
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\70\ National Emission Standards for Hazardous Air Pollutants:
Oil and Natural Gas Production and Natural Gas Transmission and
Storage, originally published at See 64 FR 32609 (June 17, 1999),
and revised at See 66 FR 34548 (June 29, 2001), See 72 FR 26
(January 3, 2007), and See 77 FR 49490 (August 16, 2012).
Information on these rulemakings is available at: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry
and https://www.epa.gov/stationary-sources-air-pollution/clean-air-act-standards-and-guidelines-oil-and-natural-gas-industry, accessed
August 16, 2019.
\71\ 2014 Uinta Basin Emissions Inventory. The inventory and
supporting analysis can be viewed in the docket for this rule
(Docket ID No. EPA-R08-OAR-2015-0709), Microsoft Excel spreadsheet
titled ``2014 UB EI summary data_U&O FIP NPRM''.
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Further, the federal preconstruction minor source permitting
requirements in the Federal Indian Country Minor NSR rule did not start
to impose requirements on new and modified true minor oil and natural
gas sources until after October 3, 2016. Through application of the
Federal Indian Country Minor NSR rule, new and modified true minor oil
and natural gas sources constructed before October 3, 2016, were
required only to register as existing sources, with no additional
emissions limits or operational requirements. As of December 2014,\72\
operators of 5,169 existing minor oil and natural gas sources on the
U&O Reservation had registered under the rule as existing sources.\73\
This number is 77 percent of the 6,739 total existing oil and natural
gas sources on the Indian country lands within the U&O Reservation),
according to the 2014 Uinta Basin Emissions Inventory. The 6,739 oil
and natural gas sources are in turn 79% of the total number of reported
oil and natural gas sources in the Uinta Basin.\74\ Therefore, the
majority of the existing minor sources are not controlled under
existing CAA requirements.
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\72\ The Minor Source Registration Data used was a snapshot in
time for the purposes of consistent analyses, though we note that we
have continued to receive new registrations for existing, new, and
modified true minor sources since that date, the overwhelming
majority of which have been for oil and natural gas sources.
\73\ New and modified true minor oil and natural gas sources
constructed on or after October 3, 2016, must meet the requirements
of the Federal Indian Country Minor NSR rule (unless the source
obtains a site-specific permit) by registering under the Indian
Country True Minor Oil and Natural Gas Source FIP, which contains
requirements to comply with a set of NSPS and NESHAP requirements,
as applicable, for various oil and natural gas activities.
\74\ 2014 Uinta Basin Emissions Inventory. The inventory and
supporting analysis can be viewed in the docket for this NPRM
(Docket ID No. EPA-R08-OAR-2015-0709), Microsoft Excel spreadsheet
titled ``2014 UB EI summary data_U&O FIP NPRM''.
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3. Evaluation of State Oil and Natural Gas and Permitting-Related
Requirements
The federal CAA regulation of existing oil and natural gas
operations on the Indian country lands within the U&O Reservation
contrasts with UDEQ's regulation of existing oil and natural gas
operations on non-Indian-country lands in the Uinta Basin. As discussed
in Section III.E., higher percentages of existing tanks and glycol
dehydrators are controlled in UDEQ-regulated areas than on the U&O
Reservation. In areas within the Uinta Basin that are under the UDEQ's
CAA jurisdiction, owners/operators of new and modified minor oil
[[Page 3505]]
and natural gas operations are subject to the preconstruction
permitting requirements in Utah's federally enforceable rules for
permitting of new and modified sources (Utah Permit Requirements).\75\
These requirements are triggered whenever uncontrolled actual emissions
are greater than or equal to the minor source preconstruction
permitting thresholds of five tpy per pollutant regulated under the
Federal Indian Country Minor NSR rule (NSR-regulated pollutant). Utah
has had a minor new source review program (preconstruction permits) in
place since November 1969. The five tpy VOC threshold was implemented
in 1997 to clarify which minor sources should be permitted. Before
1997, there was no size threshold, and any minor source was required to
obtain a permit. The permits are called Approval Orders, which identify
site-specific requirements, or General Approval Orders (GAO), which
identify a standard set of requirements for similar sources. There is a
GAO available for new and modified crude oil and natural gas well sites
and tank batteries. These two types of orders require installation,
operation, and maintenance of the best available control technologies
for minor sources. What constitutes best available control technologies
for oil and natural gas sources changes over time as new technologies
and practices are introduced and become readily available and
economically feasible. Based on the requirements in issued site-
specific approval orders, the UDEQ most recently considered minor
source Best Available Control Technology (BACT) for controlling VOC
emissions from oil and natural gas operations to include: (1) Capture
of emissions from crude oil, condensate and produced water storage
tanks (working, standing, breathing, and flashing losses), glycol
dehydrator still vents, and pneumatic pumps, if combined source-wide
VOC emissions from that equipment are greater than or equal to 4 tpy;
and (2) routing all of those emissions either (1) to a process unit
where the emissions are recycled or incorporated into a product (e.g.,
a sales gathering line); or (2) to an operational combustor with a
minimum VOC control efficiency of 98.0 percent and operated with no
visible emissions. For sources required to control emissions from crude
oil, condensate and produced water storage tanks, glycol dehydrator
still vents, and pneumatic pumps, the UDEQ issued approval orders also
require: (1) At least annual onsite inspections of fugitive emission
components using either EPA Method 21 \76\ or an optical gas imaging
instrument, and (2) repair of all identified leaking components.
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\75\ Utah Administrative Code Chapter R307-401 (Permits: New and
Modified Sources), available at https://rules.utah.gov/publicat/code/r307/r307-401.htm, accessed August 21, 2019; See 40 CFR part
52, subpart TT.
\76\ The docket for this NPRM (Docket ID No. EPA-R08-OAR-2015-
0709) contains several examples of UDEQ site-specific minor source
NSR permits (aka approval orders) for Crude Oil and Natural Gas Well
Sites and/or Tank Batteries (DAQE-AN151010001-15, DAQE-AN149250001-
14, and DAQE-AN143640003-15), as well as an approval for coverage
under the GAO for a Crude Oil and Natural Gas Well Site and/or Tank
Battery (DAQE-MN149250001-14). LDAR inspection frequency ranges from
annual to quarterly.
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As mentioned earlier, the UDEQ has adopted and made effective
revisions to the existing Utah Permit Requirements that include a
permit by rule. The permit by rule replaces the requirement for certain
minor oil and natural gas sources \77\ to obtain an approval order.
Those minor oil and natural gas sources are required to register with
the UDEQ and to comply with a suite of existing revised and additional
new oil and natural gas requirements source requirements (Utah Oil and
Gas Rules) \78\ in lieu of obtaining a site-specific approval order or
approval under the GAO. The Utah Oil and Gas Rules are consistent with
the minor source BACT that was previously required under the site-
specific Approval Orders and GAO, with some exceptions. The adopted new
requirements include: (1) At well sites and centralized tank batteries
with site-wide throughput greater than or equal to 8,000 barrels (bbl)
of crude oil or 2,000 bbl of condensate on a 12-month rolling basis
from the collection of storage vessels, a requirement to either route
all VOC emissions to a process unit to be recycled, incorporated into a
product and/or recovered, or to a VOC control device (including
associated monitoring and recordkeeping); \79\ (2) at well sites and
centralized tank batteries where storage vessel controls are required,
a requirement to capture and control VOC emissions during truck loading
and unloading operations; (3) at well sites and centralized tank
batteries with combined VOC emissions from dehydrators and the
collection of storage vessels greater than or equal to 4 tpy, a
requirement to either route all VOC emissions from dehydrators to a
process unit to be recycled, incorporated into a product, and/or
recovered, or to a VOC control device (including associated monitoring
and recordkeeping); (4) at each well site or centralized tank battery
that is required to control storage vessel and/or dehydrator VOC
emissions, a requirement to implement a leak detection and repair
(LDAR) program that includes semiannual onsite monitoring of each
fugitive emissions component (with exceptions for difficult or unsafe
to monitor components) using optical gas imaging (OGI) or EPA Method 21
at 40 CFR part 60, Appendix A; (5) at oil well sites, a requirement to
manage associated gas from a completed oil well by either routing it to
a process unit for combustion, routing it to a sales pipeline, or
routing it to a VOC control device, except for emergency release
situations; \80\ and (6) for natural gas-fired engines at new or
modified well sites or centralized tank batteries after January 1,
2016, requirement compliance upon installation or modification with the
Standards of Performance for Stationary Spark Ignition Internal
Combustion Engines at 40 CFR part 60, subpart JJJJ. All storage vessels
and dehydrators located at a well site are exempt from the control
requirements, if combined VOC emissions are demonstrated to be less
than four tpy of uncontrolled emissions on a rolling 12-month basis.
Additionally, sources that are subject to issued site-specific approval
orders or approval for coverage under the GAO are exempt from the
permit by rule and new Utah Oil and Gas Rules. The UDEQ also adopted a
new requirement that oil and natural gas sources with emissions of NSR-
regulated pollutants greater than or equal to 1 tpy are to submit an
[[Page 3506]]
emissions inventory every 3rd year, beginning with calendar year 2017.
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\77\ The permit by rule applies to well sites, as defined in 40
CFR 60.5430a, including centralized tank batteries, and exempts
sources that have already been issued approval orders. New and
modified minor compressor stations are still required to obtain an
approval order.
\78\ Utah Administrative Code Chapter R307-500 Series (Oil and
Gas), available at https://rules.utah.gov/publicat/code/r307/r307.htm, accessed August 21, 2019. These rules are state-only rules
and the UDEQ has not submitted them to the EPA for approval in the
Utah SIP.
\79\ The EPA submitted comments on the UDEQ's proposed action on
November 14, 2017, in which we questioned the use of 8,000 barrels
of crude oil per year as a surrogate for four tpy of VOC. The UDEQ
responded to those comments in the package it submitted to the Air
Quality Board for recommended adoption of the proposal. The UDEQ
revised the proposal to add the applicability threshold of 2,000 bbl
of condensate. The comments and UDEQ's responses are available in
the docket for this proposed rule (Docket ID No. EPA-R08-OAR-2015-
0709).
\80\ This is a requirement the EPA recently became aware is
specified in individual Approval Orders for oil well sites, which
was not previously apparent in the example approval orders we
reviewed. On January 3, 2019, the Utah Air Quality Board approved an
additional rule in the Utah Administrative Code Chapter R307-500
Series (Oil and Gas) at R307-511 to manage associated gas from a
completed oil well by either routing it to a process unit for
combustion, routing it to a sales pipeline, or routing it to a VOC
control device, except for emergency release situations.
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Additionally, owners/operators of all existing, new, and modified
oil and natural gas sources are subject to certain requirements in the
Utah Oil and Gas Rules that apply regardless of emissions levels. These
regulations impose: (1) Basic operational requirements for all existing
pneumatic controllers (must be low or no bleed), existing flares (must
be equipped with an automatic ignition device), and tanker truck
loading and unloading (must use bottom filling or submerged fill pipe),
regardless of source-wide emissions; and (2) general duty provisions to
operate all process and control equipment in a manner consistent with
good air pollution control practices.
As a result of Utah's oil and natural gas regulations and
permitting programs, the UDEQ has mechanisms available through which it
requires owners/operators of existing, new, and modified oil and
natural gas sources in its jurisdiction to implement legally and
practicably enforceable control requirements that reduce VOC emissions
beyond what is required by applicable federal standards and permit
programs, protecting air quality and providing regulatory certainty to
owners/operators of oil and natural gas operations. As discussed
earlier in this section, no equivalent federal regulatory counterpart
to these requirements is currently available that applies to the
existing minor oil and natural gas sources on the U&O Reservation.
As discussed earlier, oil and natural gas wastewater disposal
facilities that reply on evaporation constitute approximately 33
percent of the VOC emissions in the Uinta Basin. The UDEQ is permitting
new and modified wastewater disposal facilities that rely on
evaporation through site-specific Approval Orders \81\ that: Require
monthly water sampling from the first discharge point of wastewater to
open air used to estimate emissions; (2) place limits on VOC and HAP
concentrations in that discharge point; and (3) require that limits on
wastewater throughput, or controls on the pretreatment, be in place
before the discharge. The permits for such wastewater disposal
facilities have been requested by the operators and issued by the UDEQ
to establish the sources as synthetic minor HAP sources to avoid major
HAP source status, which would require the sources to obtain an
operating permit under Title V of the CAA. Other oil and natural gas-
producing states regulate wastewater disposal facilities that rely on
evaporation through minor NSR permits as well. All of the wastewater
disposal facilities the EPA has identified that are within Indian
country on the U&O Reservation existed before the requirement to obtain
a preconstruction permit under the Federal Indian Country Minor NSR
Rule was effective. The federal NSR regulations at 40 CFR 52.21 (major
sources) and 40 CFR 49.153 specify that sources in the oil and natural
gas sector are not required to account for fugitive emissions when
determining applicability to permitting requirements.\82\ Such
wastewater disposal facilities rarely have non-fugitive emissions
units, which means they are typically considered true minor sources
with respect to NSR. However, fugitive HAP emissions must be considered
when determining whether a source is a major HAP source under the
NESHAP at 40 CFR part 60, and, therefore, subject to the permitting
requirements of the Title V Operating Permit Program at 40 CFR part
71.\83\ We are looking into whether the existing wastewater disposal
sources on the U&O Reservation may be subject to operating permit
requirements and whether the operators may be interested in obtaining
permits to establish synthetic minor sources with respect to Title V.
Such a path would currently be the only authority for the EPA to
control emissions from these sources on the U&O Reservation.
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\81\ The UDEQ issues these site-specific permits to establish
synthetic minor sources of HAP emissions using the authority in Rule
R307-401. Permit: New and Modified Sources. R307-401-8 (1) The
director will issue an approval order if the following conditions
have been met: (a) The degree of pollution control for emissions, to
include fugitive emissions and fugitive dust, is at least best
available control technology.
\82\ See definition of major stationary source at 40 CFR
52.21(b)(1)(i)(c)(iii), definition of true minor source at 40 CFR
49.152, and Applicability at 49.153(a)(1)(i)(B).
\83\ See 40 CFR 63.2 definition of fugitive emissions.
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The EPA is not proposing to require emissions reductions at such
wastewater disposal facilities on Indian country in this action. We are
interested in information from operators of existing wastewater
disposal facilities on the U&O Reservation that rely on evaporation to
better understand and characterize emissions from such sources, and the
particular processes being used, in order to determine the CAA
permitting requirements that may apply.\84\ However, we currently lack
sufficient information on the efficacy and cost-effectiveness of the
various wastewater management and control technologies to determine
cost-effective emission control requirements that could be applied
broadly on the U&O Reservation. We are seeking comment on whether to
regulate wastewater disposal facility emissions in a possible future
amendment to a U&O FIP. We are also soliciting input regarding feasible
and cost-effective options for reducing emissions from the handling of
wastewater generated in the course of oil and gas production, including
information on technologies for treatment and reuse in oil and natural
gas production operations or other applications.
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\84\ Information we are interested in obtaining, so as to
improve our understanding of these existing facilities on the U&O
Reservation, includes quarterly sampling and analysis of oilfield
wastewater processed through facilities over a one-year period at
specific locations in the process at each facility and following
specific sampling protocols and analysis methods.
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Regarding the UDEQ's recently adopted requirements for management
of associated gas from oil well sites in their permit-by-rule, the rule
was approved after we drafted and evaluated the emissions reductions
and costs of this proposed U&O FIP proposed provisions; therefore, we
are not proposing equivalent requirements for associated gas at this
time. We intend to evaluate and consider incorporating equivalent
associated gas requirements in a final U&O FIP.
4. Developing a Consistent Set of VOC Emissions Requirements
As discussed earlier, to avoid disproportionately burdening sources
seeking to develop oil and natural gas resources on the U&O
Reservation, in this proposed U&O FIP we seek to establish VOC
emissions control requirements consistent with those applicable to
sources off the U&O Reservation. We determined that UDEQ requirements
for oil and natural gas sources in the Uinta Basin are the most
relevant requirements with which to seek consistency for new, modified
and existing oil and natural gas equipment and activities. We also
reviewed other state oil and natural gas-related regulations for areas
in the region that are like the Uinta Basin in terms of industrial
operations, characteristic meteorology, and air quality concerns.
Specifically, we reviewed state-only rules and guidance from the
Wyoming Department of Environmental Quality (WDEQ) \85\ that apply
statewide to oil and natural gas sources, and those that
[[Page 3507]]
apply in the Upper Green River Basin ozone nonattainment area and the
requirements of the Colorado Department of Public Health and
Environment (CDPHE) \86\ that apply statewide to oil and natural gas
sources, and those that apply in the Denver Metro and North Front Range
ozone nonattainment area. The Upper Green River Basin ozone
nonattainment area and the Denver Metro and North Front Range ozone
nonattainment area are two areas that have experienced ozone issues
like those in the Uinta Basin where oil and natural gas activities have
contributed to ozone nonattainment and have been addressed through
state and local rules that apply to the same emission units covered by
this proposed rule.
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\85\ ``Oil and Gas Production Facilities, Chapter 6, Section 2
Permitting Guidance,'' WDEQ (available at http://deq.wyoming.gov/aqd/new-source-review/resources/guidance-documents, accessed August
19, 2019); Wyoming Nonattainment Area Regulations, Chapter 8,
section 6; 020-020-008 Wyo. Code R. Sec. 6 (2016).
\86\ Statewide Controls for Oil and Gas Operations and Natural
Gas-Fired Reciprocating Internal Combustion Engines, 5 Code Colo.
Regs. Sec. 1001-9 (2016).
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In reviewing these other state regulations, we considered whether
the technologies are being commonly used and required at oil and
natural gas sources in other states, so as to ensure that this proposed
U&O FIP requirements are legally and practicably enforceable, as well
as reasonably achievable. Based on this review, we developed
requirements in this proposed U&O FIP reflecting the most relevant
aspects of Utah-implemented rules and permit requirements applicable to
new, modified and existing oil and natural gas sources in the Uinta
Basin. However, the proposed rule's requirements are also like
Colorado's and Wyoming's requirements for crude oil, condensate, and
produced water storage tanks; glycol dehydrators; pneumatic pumps;
closed-vent systems; enclosed combustors and utility flares; pneumatic
controllers; tank truck loading and unloading; and fugitive emissions
detection and repair.
In summary, a primary objective of this proposed U&O FIP is to
protect air quality on the U&O Reservation. We are seeking to do so in
a manner that achieves the same or consistent proposed requirements
with the UDEQ's requirements for new, modified and existing sources,
including for certain equipment or activities that the EPA does not
regulate under its standards but which the UDEQ does regulate at
existing sources. These are equipment and activities that we have
identified as significant sources of VOC emissions on the U&O
Reservation. For those equipment or activities, we are proposing
requirements for existing sources that are the same as or consistent
with the UDEQ's established requirements for existing sources. In
addition, as needed, we have consulted the EPA's standards for new and
modified oil and natural gas sources, where we are proposing to
regulate the same equipment at existing sources that is regulated
nationally at new and modified sources. Overall, this approach, for
many requirements in this proposed U&O FIP, meets our goal of
regulatory consistency across the Uinta Basin. In addition, we must
follow the minimum criteria in 40 CFR part 51, the CAA, and the TAR for
approval of rules in either a SIP or a TIP,\87\ which include adequate
monitoring, recordkeeping and reporting requirements to ensure the
requirements are federally enforceable as a practical matter. The RIA
for this proposal contains a detailed comparison of the proposed rule
requirements to the relevant state requirements reviewed.
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\87\ EPA has used the planning requirements applicable to states
as a guide in developing this proposed U&O FIP.
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Included in the docket for this rulemaking are copies of the UDEQ
rules and other state and federal rules that we considered in this
process, as well as an RIA containing a discussion comparing the
requirements of those rules to the requirements in this proposed U&O
FIP.
5. Consideration of Non-CAA Oil and Natural Gas Requirements
During development of this proposed U&O FIP requirements, we were
mindful that some oil and natural gas sources that will be subject to
the requirements of this proposed U&O FIP, if finalized as proposed,
may also be subject to requirements of the Department of Interior's
Bureau of Land Management (BLM) recent rule covering production of oil
and natural gas on federal and Indian lands.\88\ The final rule,
hereinafter referred to as the ``2018 BLM Venting and Flaring Rule,''
revised a 2016 rule,\89\ hereinafter referred to as the ``2016 BLM
Venting and Flaring Rule,'' in a manner that reduced compliance
burdens, reinstated interpretations of existing statutory authorities,
and re-established longstanding requirements that had been replaced by
the 2016 BLM Venting and Flaring Rule. We have reviewed the 2018 BLM
Venting and Flaring Rule \90\ and considered potentially overlapping
requirements in development of this proposed U&O FIP. The final 2018
BLM Venting and Flaring Rule contains a general requirement that
operators flare, rather than vent, gas that is not captured, requires
persons conducting manual well purging to remain onsite in order to end
the venting event as soon as practical, and clarifies what does and
does not constitute an emergency for the purposes of royalty
assessment. The 2018 BLM Venting and Flaring Rule removed in their
entirety the following requirements from the 2016 BLM Venting and
Flaring Rule: Waste minimization plans; well drilling and completion
requirements; pneumatic controller and diaphragm pump requirements;
storage vessel requirements; and LDAR requirements. The 2018 BLM
Venting and Flaring Rule modified and/or replaced the following
requirements from the 2016 BLM Venting and Flaring Rule: Gas-capture
requirement--the BLM now defers to State or Tribal regulations in
determining when the flaring of associated gas from oil wells will be
royalty-free; downhole well maintenance and liquids unloading
requirements; and measuring and reporting volumes of gas vented and
flared.
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\88\ See 83 FR 49184 (September 28, 2018). Department of the
Interior, BLM, Final Rule, ``Waste Prevention, Production Subject to
Royalties, and Resource Conservation; Rescission or Revision of
Certain Requirements,'' (hereinafter ``2018 BLM Venting and Flaring
Rule'').
\89\ See 81 FR 83008 (November 18, 2016). Department of the
Interior, BLM, Final Rule, ``Waste Prevention, Production Subject to
Royalties, and Resource Conservation'' (hereinafter, ``2016 BLM
Venting and Flaring Rule'').
\90\ The RIA contains additional details on our review of BLM's
rules and is available in the docket for this rule (Docket ID No.
EPA-R08-OAR-2015-0709).
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Since the 2018 BLM Venting and Flaring Rule removed requirements on
existing activities and equipment, such as storage tanks, pneumatic
pumps, pneumatic controllers, and LDAR, we do not expect the proposed
FIP will overlap with the BLM rule. However, we note that if a final
U&O FIP is promulgated that includes requirements for managing
associated gas, as intended, we would expect that final FIP would
overlap with the 2018 BLM Venting and Flaring Rule. Specifically, we
would expect that oil and natural gas sources on the U&O Reservation
would face some overlapping requirements if the sources are also
subject to federal or Indian onshore oil and natural gas leases, or to
leases and business agreements entered into by the Tribe. There would
be no overlap for oil and natural gas sources on the U&O Reservation
that are not subject to federal or Indian onshore oil and gas leases or
tribal leases and business agreements--EPA's proposed FIP would apply
and BLM's rule would not. Because some facilities that will be subject
to a final U&O FIP may also be
[[Page 3508]]
subject to this BLM rule, we will consider the requirements of the BLM
rule in developing the final FIP. While our goal will be to avoid
conflicts between the EPA requirements and BLM requirements, it is
important to recognize that the EPA and the BLM are each operating
under different statutory authorities and mandates in developing their
rules. We expect sources subject to and in compliance with the control
requirements in this proposed U&O FIP, that are also subject to the BLM
Venting and Flaring Rule, will be able to demonstrate compliance with
BLM's rule by demonstrating compliance with this proposed U&O FIP, as
both were developed by consulting other applicable federal
requirements.
E. Effect on Determining Site-Specific Permitting Requirements
As explained in Section IV.C., this rule is being proposed in
combination with a separate action amending the National O&NG FIP to
extend its construction authorization mechanism to apply on Indian
country lands within the U&O Reservation that are included in the Uinta
Basin Ozone Nonattainment Area until such time that this proposed U&O
FIP is finalized. The National O&NG FIP provides an alternative
compliance option for the requirement in the Federal Indian Country
Minor NSR rule for new and modified true minor oil and natural gas
sources to obtain a site-specific nonattainment permit before
construction. Sources covered by the streamlined construction
authorizations in the amended National O&NG FIP would not be subject
to, or exempt from, other federal CAA permitting requirements, such as
the Title V Operating Permit Program at 40 CFR part 71 or this proposed
U&O FIP. Sources complying with the amended O&NG FIP will be able to
take into account any VOC emission reductions from any required
controls under this proposed U&O FIP when calculating their PTE for
determining applicability of the particular permitting requirements to
new, modified and existing sources. Some sources' PTE for VOC, or any
other regulated NSR and/or Title V pollutant, may exceed the
applicability thresholds for PSD, Federal Indian Country Minor NSR
rule, or Title V permitting requirements even after complying with this
proposed rule (when finalized). In such cases, the owners or operators
of these sources will be required to apply for and obtain appropriate
permits before construction.
F. Evaluation of Emissions Impacts of the Proposed Rule
The EPA has reviewed and quantified the estimated emissions impacts
from the emissions control measures proposed in this proposed U&O FIP
using the 2014 Uinta Basin Emission Inventory. We expect that the VOC
reductions achieved by this proposed U&O FIP will be beneficial for
reducing ambient ozone and HAP levels and the severity of any
exceedances of the 8-hour ozone NAAQS that may occur at any time of the
year. We are proposing a requirement for owners/operators to submit
emissions inventories on a triennial basis and will monitor changes in
the inventory along with monitoring ozone concentrations. Supporting
air quality information is discussed in the RIA for this rule.\91\
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\91\ The RIA includes a more detailed explanation of the air
quality impacts of the proposed rule. It can be found in the docket
for this rule (Docket ID No. EPA-R08-OAR-2015-0709).
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In our existing source emissions data review, we have determined
that a proposed requirement to at least a 95.0 percent VOC control
efficiency continuously for emissions from existing storage tanks,
glycol dehydrators and pneumatic pumps, and a proposed fugitive
emissions monitoring program at existing oil and natural gas sources,
will result in a reduction of VOC emissions of approximately 20,000
tpy. This number represents a 28 percent reduction of oil and natural
gas-related VOC emissions on the U&O Reservation (relative to the total
oil and natural gas-related VOC emissions for the Uinta Basin of more
than 71,000 tpy per the 2014 Uinta Basin Emissions Inventory). In
addition, this proposed U&O FIP represents an overall 26 percent
reduction in total oil and natural gas sector VOC emissions relative to
the inventory for the entire Uinta Basin. Relative to the 2014 NEI, the
proposed VOC reductions represent a 15 percent reduction in total VOC
emissions for all source sectors for the Basin, but a 25 percent
reduction during winter (excluding biogenic sources--see Section III.E)
for the Basin.
The EPA estimates that the proposed rule will result in a reduction
of approximately 2,200 tpy of HAP and 59,000 tpy of methane as ``co-
benefits,'' \92\ as the emission reduction requirements to reduce VOC
emissions also reduce HAP and methane concentrations in the gases
routed to them at proportional rates, and in some cases conserve that
gas stream for market rather than burn it in a control device.
Estimates of how much gas would be conserved are discussed later in
Section IV.G. and in the RIA.
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\92\ The RIA includes a more detailed explanation of the air
quality and climate benefits of the proposed rule. It can be found
in the docket for this rule (Docket ID No. EPA-R08-OAR-2015-0709).
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The use of combustors or flares to control VOC emissions generates
associated, unintended emissions of NOX and CO as part of
the combustion process. The EPA estimates that there would be an
associated increase of 93 tpy of NOX and 427 tpy of CO from
the use of combustion devices.\93\ When these emissions are distributed
across the sources that would be required to install a combustion
device, the emissions per source are very low. The estimated emissions
per source for both pollutants are substantially lower than the 10 tpy
threshold that triggers the requirement for minor sources to obtain a
permit under the Federal Indian Country Minor NSR rule.\94\ Therefore,
we are not concerned that the increases in NOX and CO
emissions would adversely impact the NO2 or CO NAAQS.
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\93\ The RIA includes a more detailed explanation of the air
quality impacts of the proposed rule. It can be found in the docket
for this rule (Docket ID No. EPA-R08-OAR-2015-0709).
\94\ The RIA, accessible in the docket for this rulemaking
(Docket ID No. EPA-R08-OAR-2015-0709), contains additional
discussion regarding NOX and CO emissions resulting from
combustion in relation to the NO2 and CO NAAQS.
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G. Costs and Benefits of the Proposed Rule
To estimate the total cost of the proposed rule, as well as dollar-
per-ton VOC control cost effectiveness, the EPA relied on existing cost
analyses completed to support the 2015 NSPS OOOO revisions and NSPS
OOOOa,\95\ and the 2012 Colorado Regulation 7.\96\ To estimate the
number of sources and equipment impacted by this proposed U&O FIP, the
EPA relied on the 2014 Uinta Basin Emissions Inventory. An operator's
existing fleet of sources, site-specific conditions, and existing
control equipment will affect the annual cost impact on a given
operator and is expected to be variable. Additionally, the strategies
and controls required by this proposed U&O FIP will result in the
recovery and sale of gas that would otherwise be vented to the
atmosphere. These savings are included in the cost
[[Page 3509]]
analysis and will increase the cost effectiveness of the rule. The
complete cost analysis by the EPA to support this proposed U&O FIP is
included in the RIA for this rule.\97\
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\95\ RIA of the Proposed Emission Standards for New and Modified
Sources in the Oil and Natural Gas Sector, Docket ID No. EPA-HQ-OAR-
2010-0505, accessible at http://www.regulations.gov or https://www3.epa.gov/ttnecas1/regdata/RIAs/egughgnspsproposalria0326.pdf,
accessed August 19, 2019.
\96\ Final Economic Impact Analysis per Sec. 25-7-110.5(4),
C.R.S. For Proposed revisions to Colorado Air Quality Control
Commission Regulation Number 7 (5 CCR 1001-9), January 30, 2014,
available in the docket for this rulemaking (Docket ID No. EPA-R08-
OAR-2015-0709).
\97\ The RIA, accessible in the docket for this rulemaking
includes a more detailed explanation of costs and benefits (Docket
ID No. EPA-R08-OAR-2015-0709).
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Based on the 2014 Uinta Basin Emissions Inventory, 2,524 of the
estimated 6,739 total existing sources on Indian country lands within
the U&O Reservation are likely to be impacted at least in part by the
requirements in this rulemaking for existing sources. A breakdown of
the estimated number of sources impacted by this proposed U&O FIP and
how they are affected is presented in Table 2.
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\98\ This is the count of the total number of high-bleed
pneumatic controllers in the 2014 Uinta Basin Emissions Inventory,
which is what the total annualized cost to retrofit to low-bleed
controllers is based on. We elected to not determine how the
controllers are distributed across the sources on the U&O
Reservation, because it was not necessary for calculating costs.
Table 2--Existing Sources Affected by Proposed Rule
------------------------------------------------------------------------
Proposed rule requirement: Estimated sources affected
------------------------------------------------------------------------
Add a combustor to comply with FIP... 2,064.
Retrofit existing flare with auto 460.
igniter to comply with FIP.
Conduct LDAR at well sites to comply 2,079.
with FIP.
Conduct LDAR at compressor stations 8.
to comply.
Retrofit existing high-bleed 1,503 units.\98\
pneumatic controllers to low-bleed
(1,503 units) to comply with FIP.
Comply with one or more requirements 2,524.
of the rule.
------------------------------------------------------------------------
Using the EPA and Colorado control cost estimates, the EPA
estimates the total capital cost of this proposed U&O FIP will be $280
million (incurred during the first three years of compliance, 2019-
2021) and the total annualized engineering costs of implementing all of
the controls outlined in this proposed U&O FIP is estimated to be $68
million in 2021 \99\ when using a 7 percent discount rate and $60
million when using a 3 percent discount rate.\100\ All costs and
benefits are in 2016 US dollars unless stated otherwise. Revenues from
additional recovered natural gas are estimated at $3.5 million in 2021,
assuming a wellhead natural gas price of $4.00 per thousand cubic feet,
as the EPA estimates that approximately 885 million cubic feet of
natural gas will be recovered in 2021 by implementing this proposed U&O
FIP. When estimated revenues from additional natural gas recovery are
included, the annualized engineering costs of this proposed U&O FIP are
estimated to be $64 million in 2021 when using a 7 percent discount
rate and $56 million when using a 3 percent discount rate.
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\99\ This estimate includes the costs of necessary recordkeeping
and reporting for compliance with the proposed requirements. It is
expected that maximum cost impacts to industry will occur during the
first calendar year of full compliance following the effective date
of the rule and will decrease in future years. Assuming the final
rule is promulgated and effective by the end of 2018, full
compliance under this proposed U&O FIP would be required by 2021 in
the worst-case scenario, taking into account the maximum extension
of the compliance deadline that the EPA anticipates might be granted
with sufficient justification from an operator. Therefore, the cost
year analyzed was 2021 for this proposed U&O FIP. The RIA,
accessible in the docket for this rulemaking includes a more
detailed explanation of benefits and costs (Docket ID No. EPA-R08-
OAR-2015-0709).
\100\ Estimated costs are for retrofitting existing sources
only. We did not calculate costs for new or modified sources,
because we presumed those sources would be required to implement the
proposed controls if they were required to obtain a site-specific
permit, rather than the streamlined construction authorization
mechanism of the amended National O&NG FIP that is being extended to
the portions of the Uinta Basin Ozone Nonattainment Area that
include Indian country within the U&O Reservation.
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As mentioned earlier, the total emissions reductions expected under
the proposed control requirements for existing sources are estimated to
be approximately 20,000 tpy \101\ of VOC: About 6,100 tpy from
controlling emissions from storage tanks, about 3,400 tpy from
controlling emissions from glycol dehydrators, and about 6,700 tpy from
controlling emissions from pneumatic pumps. We assume that all
emissions will be routed to a combustor that will be designed and
operated to continuously to meet at least a 95.0 percent VOC control
efficiency. For the remainder of the emission reductions, approximately
1,400 tpy of VOC emissions are achieved by implementing an LDAR program
and about 2,000 tpy of VOC emissions by retrofitting or replacing high-
bleed pneumatic controllers with low-bleed. It should be noted that the
2014 Uinta Basin Emissions Inventory has not included a methodology to
account for the phenomenon of ``super-emitters'' or fat-tail emission
distribution that is typically a result of abnormal process conditions.
Emissions resulting from this phenomenon are discussed in more detail
later in Section V.F. Implementing an LDAR program would result in
emissions reductions that include these emissions.
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\101\ The numbers do not sum to exactly 20,000 due to rounding.
All values have been individually rounded to two significant
figures.
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Using the total annualized cost of $68 million and applying a 7
percent discount rate, the cost of control is estimated to be $3,400
per ton of VOC reduced without accounting for product recovery savings.
Using $64 million at a 7 percent discount rate, the control cost is
estimated to be $3,300 per ton of VOC reduced when additional revenue
from product recovery is included. Using the total annualized cost of
$60 million at 3 percent discount rate, the cost of control is
estimated to be $3,000 per ton of VOC reduced without accounting for
product recovery savings; using $56 million at a 3 percent discount
rate, it is estimated to be $2,900 per ton of VOC reduced.
We predict that there will be ozone and PM2.5 health
benefits from VOC reductions, as well as co-benefits for climate from
methane reductions and co-benefits for human health and ozone from HAP
reductions. These ``co-benefits'' would occur because the control
techniques to meet the standards simultaneously reduce VOC, methane,
and HAP emissions at proportional rates. As mentioned earlier, this
proposed U&O FIP is anticipated to reduce 59,000 tons of methane and
2,200 tons of HAP per year starting in the first year of full
compliance (2021). The annual CO2-equivalent (CO2
Eq.) methane emission reductions are estimated to be 1.3 million metric
tons by 2021. These pollutants are associated with substantial health,
welfare, and climate effects, which these emissions reductions will
help mitigate. Climate-related benefits from methane emission
[[Page 3510]]
reductions are monetized using an interim estimate of the domestic
social cost of methane, developed under Executive Order 13783.\102\ By
2021, the annual domestic climate-related benefits of the proposed
action are estimated to be $10 million using a 3 percent discount rate
and $2.9 million using a 7 percent discount rate.\103\ The HAP reduced
as a result of reducing VOC emissions come primarily from the
reductions in glycol dehydrator emissions. Reduction of these HAP are
particularly effective for two reasons: (1) Reduced exposure will
result in air toxics-related health benefits; and (2) those HAP are
highly reactive VOC that more readily form ozone, so reductions of
those HAP are expected to proportionately have a greater influence on
reducing ozone than reductions in other VOC. The specific control
techniques for this proposed U&O FIP are anticipated to have minor
emissions disbenefits (e.g., increases in emissions of NOX
and CO related to combustion of VOC).
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\102\ See the RIA for more detailed information.
\103\ The RIA, accessible in the docket for this rulemaking
includes a more detailed explanation of the climate-related benefits
(Docket ID No. EPA-R08-OAR-2015-0709)
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The RIA\104\ for the recently revised ozone NAAQS contains a
detailed discussion of the current state of knowledge on the health
benefits associated with reducing ambient levels of ozone air
pollution. When we describe ozone health benefits, we generally group
them in two categories: (1) Reduced incidence of premature mortality
from exposure to ozone; and (2) reduced incidence of morbidity from
exposure to ozone. Reductions in premature mortality can occur either
as a result of reductions in short term exposures to ozone, which can
benefit people of all ages, or as a result of reductions in lifetime
exposures to ozone (age 30 to 99). Reduced morbidity from reduced
exposure can occur through reduced: (1) Hospital admissions for
respiratory reasons (age >65); (2) emergency department visits for
asthma (all ages); (3) asthma exacerbation (age 6-18); (4) minor
restricted-activity days (age 18-65); and (5) school absence days (age
5-17).
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\104\ ``Regulatory Impact Analysis of the Final Revisions to the
National Ambient Air Quality Standards for Ground-Level Ozone,''
U.S. Environmental Protection Agency, EPA-452/R-15-007, September
2015, https://www.regulations.gov/document?D=EPA-HQ-OAR-2013-0169-0057, accessed August 16, 2019.
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We have not quantified the monetary benefits of the VOC emissions
reductions in the proposed rule and are including only a qualitative
discussion of the benefits of the expected reductions in ozone and
PM2.5 levels, for the reasons in the following discussion.
In other ozone-related rulemakings, when adequate data have been
available, the EPA has quantified several health effects and monetized
benefits of VOC reductions associated with exposure to ozone and
PM2.5. Including only a qualitative discussion of benefits
does not imply that these benefits do not exist, but merely that the
agency does not have enough data to quantitatively support such a
discussion. However, we expect that significant reductions in VOC
emissions will result in corresponding reductions in ozone formation
and the health and welfare effects associated with exposure to ozone.
As explained previously, research studies have shown that ozone
levels in the Uinta Basin are most significantly influenced by VOC
emissions from the accumulation of existing minor oil and natural gas
production operations. However, although we expect significant VOC
emissions reductions, which will result in improvements in air quality
and will reduce the health and welfare effects that are associated with
exposure to ozone, fine particulate matter (PM2.5), and HAP,
we have determined that the VOC-related health benefits cannot be
quantified (and thus, monetized) for the elevated winter ozone observed
in the Uinta Basin, because current modeling tools using the NEI are
not sufficient to properly characterize ozone and PM2.5
formation for these winter ozone episodes due to uncertainties in
quantifying the local emissions from oil and gas operations. Existing
air quality modeling and measurement studies specific to the Uinta
Basin indicate that air quality models that use the 2011 NEI
underestimate the monitored elevated winter VOC and ozone
concentrations. Air quality model sensitivity simulations for the Uinta
Basin have shown that models can reproduce monitored ozone levels when
oil and gas emissions are increased to match monitored VOC levels;
thus, it is believed that models using the 2011 NEI fail to simulate
observed VOC and ozone levels because of ongoing uncertainties in
quantifying the local emissions from oil and natural gas
operations.\105\ But regardless of the quantitative uncertainties, we
expect that reductions in ambient VOC emissions will result in
reductions in winter ozone.\106\ Any reductions in ambient ozone levels
in the Uinta Basin are expected to lead to reductions in related
adverse public health and welfare effects associated with exposure to
ozone and is expected to meaningfully aid in compliance with the ozone
NAAQS for the Uinta Basin.\107\
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\105\ Matichuk, R., Tonnesen, G., Luecken, D., Gilliam, R.,
Napelenok, S.L., Baker, K.R., Schwede, D., Murphy, B., Helmig, D.,
Lyman, S.N., Roselle, S. (2017). Evaluation of the Community
Multiscale Air Quality Model for simulating winter ozone formation
in the Uinta Basin. Journal of Geophysical Research: Atmospheres,
122, available in the docket for this rulemaking (Docket ID No. EPA-
R08-OAR-2015-0709). Like the Uinta Basin Ozone Studies discussed
earlier, the EPA study found that modeled ozone was strongly
sensitive to changes in VOC emissions, and that when oil and gas VOC
emissions were increased sufficiently such that the model matched
the measured VOC concentrations, the model also reproduced the
observed peak ozone concentrations. For oil and natural gas sources
in the Uinta Basin we are confident that the 2011 NEI underestimates
VOC and HAP emissions. We are also confident that the 2014 NEI,
though it was not used in the EPA study, underestimates VOC and HAP
emissions. For this and other reasons that are discussed in more
detail in the RIA, we are unable to conduct photochemical modeling
to quantify the impacts of this rule's proposed VOC emissions
reductions on winter ozone air quality in the Uinta Basin.
\106\ The RIA includes a more detailed discussion of the
expected air quality benefits and impacts (Docket ID No. EPA-R08-
OAR-2015-0709).
\107\ The EPA discussed this position in detail when
promulgating the NSPS OOOO revisions and NSPS OOOOa, as well as when
promulgating the final revised ozone NAAQS, concluding that the
available VOC benefit-per-ton estimates are not appropriate to
calculate monetized benefits of those rules, even as a bounding
exercise. The dockets for both proposed rulemakings are available at
http://www.regulations.gov, Docket ID No. EPA-HQ-OAR-2010-0505-4776
and Docket ID No. EPA-HQ-OAR-2008-0699-4458.
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To improve our ability to quantify these benefits in the future,
work is in progress to enhance emissions inventories in the Basin using
improved activity data, additional sources such as wastewater
evaporation ponds, and updated estimates of speciation from storage
tank emissions. Most recently, inventories were developed from operator
supplied activity and emissions information for 2014 and 2017.
Additionally, the EPA will continue to work with the Utah DAQ, the Ute
Tribe, and industry to collect comprehensive oil and natural gas
emissions inventories for the Uinta Basin. Future EPA work will focus
on improving the emissions factors and speciation profiles used in the
development of emissions inventories--efforts that will help improve
air quality model performance.
Considering all the quantified costs and benefits of this rule,
including the revenues from recovered natural gas that would otherwise
be vented, the quantified equivalent annualized costs (the difference
between the monetized benefits and compliance costs) are estimated to
be negative $39 million in 2021 using a 3 percent interest rate and
[[Page 3511]]
negative $46 million in 2021 using a 7 percent interest rate.\108\ In
light of the many unquantified but real and meaningful benefits noted
above, the actual equivalent annualized costs are expected to be much
less. We cannot estimate these costs with any confidence.
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\108\ The RIA in the docket for this rulemaking discusses this
calculation in detail.
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We are soliciting comment on all assumptions used to calculate
costs and effectiveness of proposed control requirements, and benefits
of the emissions reductions, all of which are detailed in the RIA and
other supporting documentation available in the docket for this
proposed U&O FIP.
V. Summary of FIP Provisions
This proposed rule would apply to owners or operators of oil and
natural gas sources that either produce oil and natural gas or process
natural gas and that are located on Indian country lands within the U&O
Reservation that meet the applicability criteria specified for each set
of requirements.
This proposed U&O FIP includes the following provisions:
49.4169 Introduction
49.4170 Delegation of authority of administration to the tribe
49.4171 General provisions
49.4172 Emissions Inventory
49.4173 Nonattainment Requirements for New or Modified True Minor Oil
and Natural Gas Sources
49.4174 VOC emission control requirements for storage tanks
49.4175 VOC emission control requirements for dehydrators
49.4176 VOC emission control requirements for pneumatic pumps
49.4177 VOC emission control requirements for covers and closed-vent
systems
49.4178 VOC emission control devices
49.4179 VOC emission control requirements for fugitive emissions
49.4180 VOC emission control requirements for Tank Truck Loading
49.4181 VOC emission control requirements for pneumatic controllers
49.4182 Other combustion devices
49.4183 Monitoring requirements
49.4184 Recordkeeping requirements
49.4185 Notification and reporting requirements
We do not expect a substantial number of oil and natural gas
sources subject to this proposed U&O FIP's requirements to also be
subject to NSPS OOOO or OOOOa, or NESHAP HH. However, to alleviate some
of the regulatory burden of this proposed U&O FIP, we are proposing
that any equipment or activities affected by any requirement in this
proposed U&O FIP that are subject to the substantive emissions control
requirements in the EPA standards, as appropriate, will not be subject
to this proposed U&O FIP's substantive emissions control requirements
for such equipment and activities. As an example, given the proposed
exemptions, as a practical matter, a new or modified oil and natural
gas source on the U&O Reservation that has storage tanks, glycol
dehydrators, pneumatic pumps and fugitive emissions components and the
storage tanks, pneumatic pumps and fugitive emissions components are
subject to the emissions control requirements of NSPS OOOOa, then that
source would be subject to the substantive emissions control
requirements for glycol dehydrators in the FIP, but not to the FIP's
substantive emissions control requirements for storage tanks, pneumatic
pumps or fugitive emissions components.
A. Introduction
We are proposing in Sec. 49.4169 (Introduction) to specify: (1)
The purpose of this proposed U&O FIP; (2) the general applicability to
the provisions of this proposed U&O FIP; and (3) the compliance
schedule for this proposed U&O FIP.
We are proposing text that: (1) Establishes provisions for
delegation of authority to allow the Ute Indian Tribe to assist the EPA
with administration of this proposed U&O FIP in Sec. 49.4170; (2)
establishes general provisions and definitions applicable to oil and
natural gas sources in Sec. 49.4171; (3) establishes a requirement for
oil and natural gas sources to submit emissions inventories on a
triennial basis, beginning with an inventory for calendar year 2017 in
Sec. 49.4172; (4) establishes in Sec. 49.4173 enforceable
requirements to control emissions of VOC and other pollutants from new
and modified true minor oil and natural gas sources in the oil and
natural gas production and natural gas processing segments of the oil
and natural gas sector that commence construction on or after the
effective date of this proposed U&O FIP, unless the source obtains a
site-specific construction permit, or is otherwise required to obtain a
site-specific permit by the Reviewing Authority, in accordance with 40
CFR 49.151 through 49.161; and (5) establishes in Sec. Sec. 49.4174
through 49.4185, enforceable requirements to control and reduce VOC
emissions from oil and natural gas well production and storage
operations, natural gas processing, and gathering and boosting
operations at oil and natural gas sources that are located on Indian
country lands within the U&O Reservation.
We may issue a final action based on this proposal as soon as the
date of publication of a final U&O FIP. We believe that there may be
``good cause,'' within the meaning of 5 U.S.C. 553(d)(3), to make the
final rule effective as soon as it is published, if that is needed to
ensure that this rule begins to provide emission reductions before the
next winter ozone season. As discussed above in section II.D., winter
ozone in the Uinta Basin is a serious public health problem, which this
proposed rule is intended to help address.
In addition, the reductions provided by this rule are an integral
part of the Agency's strategy to address the air quality problem on the
U&O Reservation while maintaining a permitting mechanism that allows
appropriate continued oil and natural gas production. The primary other
component of that strategy is a separate action to amend the National
O&NG FIP to extend its geographic coverage to the Indian country
portions of the U&O Reservation that are part of the Uinta Basin Ozone
Nonattainment Area. Over the long term, we are relying on the VOC
emissions reductions in this action to support this extension of the
scope of the National O&NG FIP. Accordingly, if making this rule
effective on publication is necessary to begin effecting VOC emission
reductions before the next winter ozone season, then doing so will help
ensure that the amendment to the National O&NG FIP is compatible with
air quality improvement on the U&O Reservation.
Accordingly, the EPA proposes to find that there is good cause to
make the final action based on this proposal effective on the date of
publication of the final rule. We invite comment on this proposed
approach.
We are proposing that compliance with the rule for oil and natural
gas sources that commence construction on or after the effective date
of the final rule would be required upon startup. Compliance for
sources that are existing as of the effective date of the final rule
would be required no later than 18 months after the effective date of
the final rule. We concluded that it is important to allow owners/
operators of existing sources a reasonable period of time to conduct
any necessary retrofit-related activities, such as (1) acquiring
control devices, (2) conducting manufacturer-recommended testing to be
compliant with the proposed
[[Page 3512]]
requirements, and (3) securing the necessary trained personnel to
install compliant devices and associated piping and instrumentation. We
expect that there will be about 2,100 existing oil and natural gas
sources that may require equipment retrofit and installation of VOC
emission control equipment (combustor controls) under the proposed
rule. Additionally, we estimate that a total of approximately 1,500
high-bleed pneumatic controllers will need to be retrofitted to low- or
no-bleed. We have determined that providing 18 months from the
effective date of the final rule to install retrofits at existing
sources is a reasonable amount of time for efficient, cost-effective
project planning that accounts for a level, sustained equipment and
labor resource demand that can be supported by the vendor
community.\109\
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\109\ We recognize that 18 months is a tighter compliance
timeframe than is required in NESHAP regulations, which is typically
3 years. The purpose of this proposed U&O FIP, though, is to address
air quality in a timely fashion. Moreover, the proposal allows
sources to request extensions of the compliance date beyond the 18
months as needed.
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This assessment is supported by what we have learned about the time
needed for sources in Utah-regulated areas to comply with Utah's
requirements for oil and natural gas sources. In particular, we have
been informed by UDEQ compliance staff that the majority of existing
oil and natural gas sources that have been required to install VOC
emission control retrofits in State of Utah jurisdictions have
completed the required retrofits within 9 months of the effective dates
of their minor source approval orders, ahead of the 18-month deadline
in UDEQ approval orders for operators to notify the UDEQ of the status
of retrofit construction.\110\ However, there are many more existing
oil and natural gas sources on the U&O Reservation that would be
required to install retrofits to control emissions from storage tanks,
glycol dehydrators, and pneumatic pumps under this proposed U&O FIP
than are estimated to be subject to equivalent requirements in UDEQ
jurisdiction. The UDEQ estimates that approximately 1,600 existing
sources have been required to control emissions from storage tanks,
glycol dehydrator, and/or pneumatic pumps on non-Indian country lands
in the Uinta Basin, while we estimate there are approximately 2,100
sources on Indian country lands within the U&O Reservation that would
be subject to such requirements in this proposed U&O FIP. Therefore, it
is likely owners/operators may need longer than 9 months to complete
the necessary retrofits to the greater number of Indian country
sources. The 18-month compliance schedule in this proposed U&O FIP will
allow time for operators to conduct the necessary retrofits, while at
the same time starting to achieve VOC emissions reductions as soon as
practicable, so that the reductions will have a timely, beneficial
impact on air quality and human health and progress toward attaining
the ozone NAAQS.
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\110\ Email correspondence with UDEQ staff regarding their
source inventory and experiences regulating existing oil and natural
gas sources in State of Utah jurisdiction is included in the docket
for this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709). UDEQ
compliance staff target each new approval order for inspection
within 18 months of the date it is issued. They document the status
of construction at the time of inspection and note whether the
permitted source has provided a notification of construction status,
which is required within 18 months of the date the approval order is
issued. UDEQ compliance staff have inspected hundreds of such
existing oil and natural gas sources without observing any
compliance issues with the 18-month notification requirement. While
UDEQ compliance staff do not compile this information into any
readily available summary format, details about the status of
construction are included in the inspection report for each source.
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We are also proposing to allow an owner or operator to submit a
written request to the EPA for an extension of the compliance deadline
for existing sources, which must include a detailed explanation of the
reason for the request. Any approval or denial of an extension request,
including the length of any approved extension, will be based upon the
merits of each case. Factors that the EPA will consider in deciding
whether to grant an extension request under the proposed provision
include the economic and technical feasibility of meeting this proposed
U&O FIP's control requirements in the timeframe prescribed in it. We
are seeking comment on the proposed compliance schedules, or
alternative compliance schedules that may be more appropriate,
including information that supports the proposed time period or a
different time period, such as data on average times to acquire,
install, and test or obtain manufacturer certification of compliant
control devices.
B. Provisions for Delegation of Administration to the Tribe
We are proposing in Sec. 49.4170 (Delegation of Authority of
Administration to the Tribe) to establish the steps by which the Ute
Indian Tribe may request delegation to assist us with the
administration of this rule and the process by which the Regional
Administrator of EPA Region 8 may delegate to the Ute Indian Tribe the
authority to assist with such administration. As described in the
regulatory provisions, any such delegation will be accomplished through
a delegation of authority agreement between the Regional Administrator
and the Tribe. This section would provide for administrative delegation
of this federal rule and does not affect the eligibility criteria under
CAA section 301(d) and 40 CFR 49.6 for TAS should the Ute Indian Tribe
decide to seek such treatment for the purpose of administering their
own EPA-approved TIP under tribal law. Administrative delegation is a
separate process from TAS under the TAR. Under the TAR, Indian tribes
seek the EPA's approval of their eligibility to implement CAA programs
under their own laws. The Ute Indian Tribe will not need to seek TAS
under the TAR for purposes of requesting to assist us with
administration of this rule through a delegation of authority
agreement. If delegation does occur, the rule would continue to operate
under federal authority on Indian country lands within the U&O
Reservation, and the Ute Indian Tribe would assist us with
administration of the rule to the extent specified in the agreement.
C. General Provisions
We are proposing in Sec. 49.4171 (General Provisions): (1) A
requirement to design, operate, and maintain all equipment used for
hydrocarbon liquid and gas collection, storage, processing, and
handling operations covered under this rule, in a manner consistent
with good air pollution control practices and that minimizes leakage of
VOC emissions to the atmosphere; (2) definitions; (3) assurances that,
in order to ensure compliance, we will maintain our authority to
require testing, monitoring, recordkeeping, and reporting in addition
to that already required by an applicable requirement in a permit to
construct or permit to operate; and (4) assurance that nothing in the
rule will preclude the use, including the exclusive use, of any
credible evidence or information, relevant to whether a source would
have been in compliance with applicable requirements if the appropriate
performance or compliance test had been performed.
D. Emissions Inventory Requirements
We are proposing in Sec. 49.4172 a requirement for owners/
operators of oil and natural gas sources with the potential to emit one
or more NSR-regulated pollutants at levels greater than one tpy to
submit an annual emissions inventory once every three years, that
covers emissions from the previous calendar year, beginning with
calendar year 2017. This requirement will suffice for the purpose of
continued
[[Page 3513]]
updates to the comprehensive Uinta Basin oil and natural gas emissions
inventory effort by the UDEQ, Ute Indian Tribe and the EPA. Owners/
operators will be required to submit actual emissions for each
emissions unit at each oil and natural gas source covered by the
requirement in a standard format specified by the Regional Office and
available on our website by the effective date of the final rule. The
format will be consistent with the format used by the UDEQ to collect
information from sources outside of Indian country lands within the U&O
Reservation.
E. Compliance With the National Indian Country Oil and Natural Gas
Federal Implementation Plan for New and Modified True Minor Oil and
Natural Gas Sources in the Uinta Basin Ozone Nonattainment Area
From a regulatory standpoint, the effect of this action is to shift
the requirement for compliance with the National O&NG FIP from one part
of the CFR to another. Currently, new and modified true minor oil and
natural gas sources proposing to locate or expand on Indian country
lands within the U&O Reservation that are part of the Uinta Basin Ozone
Nonattainment Area must comply with the National O&NG FIP, as a result
of the recent action we took amending that FIP. The provisions of the
National O&NG FIP that the recent action requires compliance with
concern 40 CFR 49.101 through 49.105. This proposed action merely
shifts these requirements located at 40 CFR part 49, subpart C, to 40
CFR part 49, subpart K, as part of this proposed U&O FIP, for the
reasons stated previously. Additionally, these sources are also subject
to applicable requirements in the Federal Indian Country Minor NSR Rule
also found in subpart C at 40 CFR 49.151 through 49.161, including the
2-part registration requirement.
In Sec. 49.4173 (Compliance with the National Indian Country Oil
and Natural Gas Federal Implementation Plan for New and Modified True
Minor Oil and Natural Gas Sources in the Uinta Basin Ozone
Nonattainment Area), we are proposing that new and modified true minor
oil and natural gas sources proposing to locate or expand on Indian
country lands within the U&O Reservation that are part of the Uinta
Basin Ozone Nonattainment Area continue to permanently comply with the
National O&NG FIP (excluding Sec. 49.101(d), which indicates that the
National O&NG FIP does not apply in nonattainment areas), unless the
owner or operator of a source opts out of the National O&NG FIP's
permitting approach or is otherwise required by the EPA to obtain a
site-specific minor source permit according to the Federal Indian
Country Minor NSR Program at 40 CFR part 49. For the purposes of this
proposed rule, a new or modified true minor oil and natural gas source
is one constructed or modified on or after the effective date of this
proposed U&O FIP. This continued permanent application of the National
O&NG FIP to the Indian country lands within the U&O Reservation that
are included in the Uinta Basin Ozone Nonattainment Area covers only
new and modified true minor oil and natural gas sources in the oil and
natural gas production and natural gas processing segments of the oil
and natural gas sector.
Applying the requirements of the National O&NG FIP to the Uinta
Basin Ozone Nonattainment Area fulfills the EPA's obligation under the
Federal Indian Country Minor NSR rule to issue minor source NSR pre-
construction permits when combined with the existing source emissions
reductions that would be required by this proposed U&O FIP. The EPA is
seeking comment only on the proposal to continue to permanently apply
the National O&NG FIP to sources on Indian country lands within the U&O
Reservation that are part of the Uinta Basin Ozone Nonattainment Area;
we are not re-proposing for comment the requirements of the National
O&NG FIP.
The National O&NG FIP provides an efficient and effective,
alternative approach that fulfills the minor NSR permitting
requirement, while also ensuring air quality protection through
requirements that are unambiguous and legally and practicably
enforceable. The National O&NG FIP approach is also transparent to the
public; it is clear to the public what requirements apply. The National
O&NG FIP reduces burden for sources and the Reviewing Authority and
minimizes potential delays in new construction due to compliance with
the minor NSR permitting obligation.
Upon application of the National O&NG FIP to the Indian country
lands within the U&O Reservation that are part of the Uinta Basin Ozone
Nonattainment Area, new and modified true minor sources will have to
address three sets of requirements.
First, under the National O&NG FIP that applies to new and modified
true minor sources on the Indian country portions of the U&O
Reservation that are part of the Uinta Basin Ozone Nonattainment Area,
compliance with eight federal standards is required for the following
equipment in the oil and natural gas production and natural gas
processing segments of the oil and natural gas sector: Compression
ignition and spark ignition engines; process heaters; combustion
turbines; fuel storage tanks; glycol dehydrators; completion of
hydraulically fractured oil and natural gas wells; reciprocating and
centrifugal compressors (except those at well sites); pneumatic
controllers; pneumatic pumps; storage vessels; and fugitive emissions
from well sites, compressor stations, and natural gas processing
plants.
Sources must comply with all of the provisions of the eight federal
standards (unless a provision is specifically excluded), as applicable
to oil and natural gas sources under each standard: (1) 40 CFR part 63,
subpart DDDDD, National Emission Standards for Hazardous Air Pollutants
for Major Sources: Industrial, Commercial, and Institutional Boilers
and Process Heaters; (2) 40 CFR part 63, subpart ZZZZ, National
Emissions Standards for Hazardous Air Pollutants for Stationary
Reciprocating Internal Combustion Engines; (3) 40 CFR part 60, subpart
IIII, Standards of Performance for Stationary Compression Ignition
Internal Combustion Engines; (4) 40 CFR part 60, subpart JJJJ,
Standards of Performance for Stationary Spark Ignition Internal
Combustion Engines; (5) 40 CFR part 60, subpart Kb, Standards of
Performance for Volatile Organic Liquid Storage Vessels (Including
Petroleum Liquid Storage Vessels) for Which Construction,
Reconstruction, or Modification Commenced After July 23, 1984; (6) 40
CFR part 60, subpart OOOOa, Standards of Performance for Crude Oil and
Natural Gas Facilities for which Construction, Modification, or
Reconstruction Commenced after September 18, 2015; (7) 40 CFR part 63,
subpart HH, National Emission Standards for Hazardous Air Pollutants
from Oil and Natural Gas Production Facilities; and (8) 40 CFR part 60,
subpart KKKK, Standards of Performance for New Stationary Combustion
Turbines.
Under the National O&NG FIP, true minor sources must comply with
these standards, as they currently exist or as amended in the future,
except for those provisions specifically excluded under the National
O&NG FIP (and unless the source opts out of the FIP and obtains a site-
specific permit or is otherwise required to obtain a site-specific
permit by the Reviewing Authority). New and modified sources subject to
the National O&NG FIP would be subject to any future changes to the
eight underlying EPA standards only if they undergo a future minor
modification as a true minor source and would otherwise be subject to
those future changes. To help
[[Page 3514]]
understand the requirements of the National O&NG FIP, you may wish to
review the provisions for each of the eight federal rules (i.e., five
NSPS and three NESHAP) identified in the National O&NG FIP. (The
National O&NG FIP does not change the applicability of the specified
standards, nor does it relieve sources subject to the standards from
complying with them, independently of that FIP.)
It is important to note that compliance with these eight standards
in the National O&NG FIP would not relieve the owners/operators of oil
and natural gas sources from the obligation to comply with the proposed
requirements of Sec. Sec. 49.4169 through 49.4171 and 49.4174 through
49.4185, as applicable. Those proposed U&O Reservation-specific
requirements would apply to sources regardless of whether they are
existing, new or modified. Because the proposed U&O Reservation-
specific requirements would exempt affected emissions units or
activities that are subject to and controlled according to equivalent
NSPS requirements, we expect that duplicative requirements will be
avoided. Further we expect that the emissions reductions achieved from
existing sources complying with those proposed U&O Reservation-specific
requirements will provide justification for the proposed approval of
new or modified true minor oil and natural gas sources on the U&O
Reservation through the National O&NG FIP.
Second, under the Indian Country Minor NSR rule (Sec. 49.160(c)),
new and modified sources subject to the National O&NG FIP must satisfy
the requirement for two-part registration by using the two registration
forms provided by the EPA \111\ rather than a permit application (as
mentioned earlier in Section IV.C). The registration forms contain the
information required in Sec. 49.160(c)(2). True minor sources
complying with the National O&NG FIP must submit the Part 1
Registration Form, with the information required by Sec. 49.160(c)(2),
at least 30 days before beginning construction. The Part 2 Registration
Form must be submitted within 60 days after the ``startup of
production'' as defined in Sec. 49.152(d). The source must determine
the potential for emissions within 30 days after startup of production.
The combination of the Part 1 and Part 2 Registration Forms submittal
satisfies the requirements in Sec. 49.160(c)(2). The forms are
submitted instead of the application form otherwise required in Sec.
49.160(c)(1)(iii). After being reviewed by the permitting authority,
completed registration forms will be available online on the
appropriate EPA Regional Office website.
---------------------------------------------------------------------------
\111\ The registration forms are available at: https://www.epa.gov/tribal-air/tribal-minor-new-source-review (accessed
August 16, 2019) or from the EPA Regional Offices.
---------------------------------------------------------------------------
Finally, under the National O&NG FIP, before beginning construction
new and modified sources must document that potential impacts on
threatened and endangered species and historic properties (collectively
referred to as ``protected resources'') have been assessed. 40 CFR
49.104. The section provides two options for documenting this
assessment: (1) Submittal of documentation to the EPA Regional Office
(and to the relevant tribe for the area where the source is located or
locating) that a site-specific assessment conducted by another federal
agency has been completed for the specific oil and natural gas
activity, and that the owner/operator meets all air quality-related
requirements as specified within all documents/approvals obtained
through that assessment (these requirements are typically implemented
and enforced as conditions of an approved Surface Use Plan of
Operations and/or Application for Permit to Drill); \112\ or (2)
submittal of documentation to the EPA Regional Office (and to the
relevant tribe for the area where the source is located or locating)
demonstrating that the source has completed the screening processes
specified by the EPA for consideration of threatened and endangered
species and historic properties and received a written determination
from the EPA stating that it has satisfactorily completed these
processes.\113\
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\112\ This assessment will typically be conducted through the
National Environmental Policy Act process and result in either a
Record of Decision or a Finding of No Significant Impact document.
\113\ This process of source documentation submittal and the
EPA's confirmation that it has satisfactorily completed the
procedures must occur before the source submits its Part 1
Registration Form pursuant to Sec. 49.160(c)(1)(iv). These
processes are contained in ``Procedures to Address Threatened and
Endangered Species and Historic Properties for the Federal
Implementation Plan for Managing Air Emissions from True Minor
Sources in Indian Country in the Oil and Natural Gas Production and
Natural Gas Processing Segments of the Oil and Natural Gas Sector,''
available at https://www.epa.gov/tribal-air/tribal-minor-new-source-review.
---------------------------------------------------------------------------
We are taking comment on this approach of shifting compliance with
the National O&NG FIP for new and modified true minor oil and natural
gas sources on the U&O Reservation portions of the Uinta Basin Ozone
Nonattainment Area from 40 CFR part 49, subpart C to 40 CFR part 49,
subpart K as part of this proposed U&O FIP, in addition to the proposed
VOC emissions reduction requirements in the proposed U&O FIP.
F. VOC Emissions Control Requirements
The discussion in this subsection details the proposed VOC
emissions control requirements and how they compare to existing state
and federal requirements for the equipment and activities listed in
Table 3. The most notable difference between the proposed VOC emissions
control requirements for this FIP and the Utah Oil and Gas Rules and
Utah Permit Requirements is that the 4 tpy combined VOC emissions
threshold requiring controls in the Utah permit by rule does not
include pneumatic pump emissions. The reason for this difference is
that we have identified that emissions from pneumatic pumps are a large
source of VOC emissions on the U&O Reservation, but a negligible source
of VOC emissions in the Utah jurisdiction in the Basin, because the
majority of natural gas production occurs on the Reservation. This
difference is explained in more detail later in this section.
[[Page 3515]]
Table 3--Proposed VOC Emissions Control Requirements for New, Modified and Existing Oil and Natural Gas Sources Versus UDEQ and Federal \114\ Control
Requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
Proposed VOC emissions controls Utah oil and gas
------------------------------------------------------------------------- rules and Utah
Control efficiency permit NSPS OOOO NSPS OOOOa NESHAP HH
Proposed requirements (section) TPY threshold (percent) requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
Storage Tank VOC Emission Source-wide See VOC emission Issued Utah Permit Control individual Control individual Control individual
Control Requirements (49.4174). uncontrolled VOC control devices Requirements tanks with PTE tanks with PTE tanks with
emissions from later in this (BACT for site- >=6 tpy per tank >=6 tpy per tank potential for
storage tanks, table (49.4178). specific & constructed after constructed after flash emissions
dehydrators and general approval August 23, 2011 September 18, and actual annual
pneumatic pumps orders)--Same as (alternatively no 2015 average
>=4 tpy. proposed FIP. control required (alternatively no hydrocarbon
Or for storage Utah Oil and Gas if uncontrolled control required liquid throughput
tanks-only Rules--Control VOC emissions if uncontrolled >=79,500 liters/
sources, storage tanks if maintained <4 VOC emissions day.
throughput of source throughput tpy). maintained <4
8,000 barrels >=8,000 bbl crude tpy).
(bbl) of crude oil or 2,000 bbl
oil or 2,000 bbl condensate, on
condensate on rolling 12-month
rolling 12-month basis--unless <=4
basis--unless <=4 tpy source-wide
tpy source-wide VOC from storage
VOC from storage tanks (does not
tanks. include pneumatic
pump emissions).
Dehydrators VOC Emission Control See VOC emission Issued Utah Permit Not covered....... Not covered....... Units at non-urban
Requirements (49.4175). control devices Requirements area sources with
later in this (BACT for site- actual annual
table (49.4178). specific & average flowrate
general approval of natural gas
orders)--Same as <85,000 standard
proposed FIP. m\3\/day not
Utah Oil and Gas covered--this is
Rules--Control majority of units
dehydrators if on U&O
combined Reservation.
emissions from
dehydrators and
storage tanks >=4
tpy VOC (does not
include pneumatic
pump emissions).
Pneumatic Pumps VOC Emission See VOC emission Issued Utah Permit Not covered....... For well sites, Not covered.
Control Requirements (49.4176). control devices Requirements hook up to
later in this (BACT for site- control device if
table (49.4178). specific & already on site
general approval and constructed
orders)--Same as after September
proposed FIP--. 18, 2015.
Utah Oil and Gas For natural gas
Rules does not processing
require control plants, zero
of pneumatic pump natural gas
emissions. emissions.
Covers and Closed-Vent System Source-wide 100%.............. 100% in issued 100 percent of 100 percent of 100 percent If
VOC Emission Control uncontrolled VOC Utah Permit storage tank storage tank required to
Requirements (49.4177). emissions from Requirements and emissions, if emissions, if control glycol
storage tanks, Rules (BACT for constructed after constructed after dehydrators and/
dehydrators and site-specific & August 23, 2011. September 18, or storage vessel
pneumatic pumps general approval 2015. HAP emissions.
>=4 tpy. orders).
Or for storage Utah Oil and Gas
tanks-only Rules--Like
sources, proposed FIP
throughput of (except Utah Oil
8,000 bbl of and Gas Rules do
crude oil or not include
2,000 bbl pneumatic pump
condensate on emissions).
rolling 12-month
basis--unless <=4
tpy source-wide
VOC from storage
tanks.
VOC Emission Control Devices Source-wide 95.0 percent 98.0 percent 95.0 percent 95.0 percent If required to
(49.4178). uncontrolled VOC continuously. continuous VOC continuous VOC continuous VOC control glycol
emissions from control control control dehydrator or
storage tanks, efficiency for efficiency, for efficiency, for storage vessel
dehydrators and Issued Utah use on tanks with use on tanks with HAP emissions,
pneumatic pumps Permit PTE >=6 tpy per PTE >=6 tpy per must reduce HAP
>=4 tpy. Requirements tank if tank, if by 95.0 percent,
Or for storage (BACT for site- constructed after constructed after or maintain <20
tanks-only specific & August 23, 2011. September 18, ppmv or 1 tpy
sources, general approval 2015. benzene.
throughput of orders).
8,000 bbl of Same as proposed
crude oil or FIP for Utah Oil
2,000 bbl and Gas Rules.
condensate on
rolling 12-month
basis--unless <=4
tpy source-wide
VOC from storage
tanks.
Fugitive Emissions VOC Emission Sources required NA--Semi-annual Utah Oil and Gas Only for natural At least quarterly Ensure closed-vent
Control Requirements (49.4179). to control surveys. Rules--Same as gas processing surveys for system operates
storage vessel, Proposed FIP for plants--At least natural gas with no
dehydrator and/or well sites. annual surveys. processing detectable
pneumatic pump Issued Utah Permit plants, quarterly emissions if
emissions (per Requirements surveys for required to
49.4174 through (sources exempt compressor control glycol
49.4178). from Utah Oil and stations and semi- dehydrator or
Gas Rules) annual surveys storage vessel
require LDAR, for well sites, HAP emissions.
ranging from if constructed or
annual to modified after
quarterly for oil September 18,
and natural gas 2015.
sources,
including
compressor
stations.
[[Page 3516]]
Tank Truck Loading VOC Emission None--applies to NA--Bottom filling Utah Oil and Gas Not covered....... Not covered....... Not covered.
Control Requirements (49.4180). all existing or submerged fill Rules--more
sources. pipe. stringent, as
capture and
control of VOC
emissions
required at
sources required
to control
storage vessel
and glycol
dehydrator
emissions.
Pneumatic Controllers VOC NA--meet the Utah Oil and Gas Zero-bleed for Zero-bleed for Not covered.
Emission Control Requirements standards of NSPS Rules--Same as processing plants processing plants
(49.4181). OOOO. Proposed FIP--. and low-bleed (<6 and low-bleed (<6
scfh) elsewhere, scfh) elsewhere,
if constructed if constructed
after October 15, after September
2013. 18, 2015.
Other combustion devices NA--must have Utah Oil and Gas Not covered....... Not covered....... Not covered.
(49.4182). automatic Rules--Same as
ignition device. proposed FIP.
--------------------------------------------------------------------------------------------------------------------------------------------------------
1. Storage Tanks, Glycol Dehydrators, and Pneumatic Pumps
---------------------------------------------------------------------------
\114\ The National O&NG FIP incorporates the requirements of the
eight standards, as they apply to a source. To make emissions
control requirements across the Basin consistent, this proposed U&O
FIP goes beyond the eight federal standards to regulate certain
equipment and activities that are not regulated by established EPA
standards (or are regulated differently) but are regulated in UDEQ
standards. The EPA is in the process of reviewing certain provisions
of NSPS OOOOa. The requirements summarized in this table are the
requirements effective at the time of publication of this NPRM.
---------------------------------------------------------------------------
For new, modified and existing sources, we are proposing in
Sec. Sec. 49.4174 (Storage Tank VOC Emission Control Requirements),
49.4175 (Dehydrators VOC Emission Control Requirements), and 49.4176
(Pneumatic Pumps VOC Emission Control Requirements) to require that
owners and operators of affected storage tanks, glycol dehydrators and
natural gas-driven pneumatic pumps either: (1) Reduce VOC emissions
from working, standing, breathing, and flashing losses from crude oil,
condensate, and produced water storage tanks, glycol dehydrator process
vents (glycol dehydrator regenerator or still vent and the vent from
the dehydrator flash tank, if present), and pneumatic pumps, by at
least 95.0 percent on a continuous basis; or (2) maintain the source-
wide uncontrolled actual VOC emissions from all storage tanks, glycol
dehydrators, and pneumatic pumps at a rate of less than 4 tpy, or at a
source that contains only storage tanks and does not contain glycol
dehydrators or pneumatic pumps, maintain the source-wide throughput at
less than 8,000 barrels (bbl) of crude oil or 2,000 bbl of condensate
in any consecutive 12-month period. We are proposing that applicability
for the VOC emissions control requirements be determined specifically
according to the following criteria. For oil and natural gas sources
that began operation before the effective date of the final rule, we
are proposing that applicability be determined using uncontrolled
actual emissions or actual throughput based on 12 consecutive months of
data. For oil and natural gas sources that begin operation or
modification after the effective date of the final rule, we are
proposing that applicability for glycol dehydrators and pneumatic pumps
be determined using potential to emit and we are proposing that
emissions from all storage tanks be controlled upon startup for a
minimum of 12 consecutive months. This requirement for new and modified
storage tanks is being proposed because of the uncertainty of well
production levels before operation begins. After a minimum of 12
consecutive months of operation, controls may be removed if source-wide
uncontrolled actual VOC emissions from all storage tanks, glycol
dehydrators, and pneumatic pumps are demonstrated to be less than 4
tpy, or, at a source containing only storage tanks, source-wide
throughput is demonstrated to be less than 8,000 bbl of crude or 2,000
bbl of condensate.
We are proposing that owners or operators must demonstrate that the
source-wide uncontrolled actual VOC emissions from crude oil,
condensate, and produced water storage tanks, glycol dehydrator process
vents, and pneumatic pumps have been maintained below 4 tpy using
records of monthly determinations of uncontrolled actual VOC emission
rates for the 12 consecutive months immediately preceding the
demonstration. The uncontrolled actual VOC emissions rate must be
calculated using a generally accepted model or calculation methodology.
The proposal would require that the owner or operator re-evaluate
the source-wide uncontrolled actual VOC emissions or the source-wide
throughput of crude oil or condensate on a monthly basis. If the
results of the monthly determination show that the uncontrolled actual
VOC emission rate is greater than or equal to 4 tpy or the throughput
of crude oil or condensate is greater than 8,000 bbl or 2,000 bbl,
respectively, the owner or operator will have 30 days to switch to the
first option specified and control VOC emissions by at least 95 percent
continuously. We are proposing an exemption to the VOC emissions
control requirements for each emergency storage tank, provided the tank
meets the following requirements: (1) The tank is not used as an active
storage tank; (2) the owner or operator empties the tank no later than
15 days after receiving fluids; and (3) the tank is equipped with a
liquid level gauge or equivalent device.
The proposed VOC emissions control applicability and requirements
are the same as or comparable on balance with the requirements in the
Utah Permitting Requirements and/or Utah Oil and Gas Rules. The
proposed methods for determining applicability to the control
requirements are the same as those determined to be cost-effective in
site-specific minor source BACT analyses in the Utah Permit
Requirements. In site-specific approval orders that have been issued,
the UDEQ requires VOC emissions controls for source-wide emissions from
storage tanks, glycol dehydrators, and pneumatic pumps at oil and
natural gas sources \115\ when the
[[Page 3517]]
source-wide uncontrolled actual emissions from that equipment are
greater than or equal to 4 tpy. We have also determined that
controlling emissions above the 4 tpy VOC level is cost-effective and
will achieve meaningful emissions reductions on the U&O
Reservation.\116\ The proposed methods for determining applicability to
the control requirements are comparable on balance with the UDEQ's
recently adopted Utah Oil and Gas Rules, with the exception that those
rules do not consider emissions from or control of pneumatic
pumps.\117\ The reason for this difference is discussed later when
describing requirements for pneumatic pumps. The Utah Oil and Gas Rules
require all storage vessels located at a well site that are in
operation as of January 1, 2018, with a site-wide throughput of 8,000
bbl or greater of crude oil or 2,000 bbl or greater of condensate per
year on a rolling 12-month basis to control emissions unless an
exemption applies that combined VOC emissions from storage vessels are
demonstrated to be less than 4 tpy of uncontrolled emissions (defined
as actual emissions or the potential to emit without considering
controls) on a rolling 12-month basis. Emissions to meet the exemption
must be calculated using direct site-specific sampling data and any
software program or calculation methodology in use by industry that is
based on AP-42 Chapter 7. The Utah Oil and Gas Rules require all new
and modified storage vessels (that begin operation on or after January
1, 2018) to control emissions upon startup of operation for a minimum
of one year. A separate provision allows controls to be removed after a
minimum of one year of operation if source-wide throughput is less than
8,000 bbl crude oil or 2,000 bbl condensate on a rolling 12-month basis
or uncontrolled VOC emissions are demonstrated to be less than 4 tons
per year. For sources that operate only storage tanks and not glycol
dehydrators or pneumatic pumps, the 8,000 bbl of crude oil/2,000 bbl of
condensate throughput applicability threshold for control of storage
tank emissions is the same as the control applicability threshold for
storage vessels in the UDEQ's recently adopted Utah Oil and Gas Rules.
The proposed requirement to control emissions from all new and modified
storage tanks for at least 12 consecutive months, the proposed
exemption for emergency storage tanks, and the provision allowing
removal of controls from storage tanks, glycol dehydrators and
pneumatic pumps are also the same as the requirements in the recently
adopted Utah Oil and Gas Rules, with the exception of pneumatic pump
emissions and control mentioned earlier that will be discussed in more
detail later.
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\115\ The docket for this rule contains several examples of UDEQ
site-specific minor source NSR permits (approval orders) for Crude
Oil and Natural Gas Well Sites and/or Tank Batteries (DAQE-
AN151010001-15, DAQE-AN149250001-14, and DAQE-AN143640003-15). UDEQ
site-specific approval order requirements are based on BACT analyses
for oil and natural gas sources concluding that combustion of VOC
emissions from crude oil and condensate storage tanks, glycol
dehydrators, and pneumatic pumps is economically and technically
feasible when the source-wide uncontrolled VOC emissions from those
emissions sources is equal to or greater than 4 tpy. The analyses
rely in part on the EPA's analysis in the April 12, 2013 NSPS OOOO
reconsideration, and the finding that emissions from those three
emissions sources at a single source can feasibly be routed to the
same combustor. Though the 4 tpy threshold is not specifically
stated in the approval orders, if a source applying for a site-
specific approval order has source-wide storage tank, glycol
dehydrator, and pneumatic pump VOC emissions equal to or greater
than 4 tpy, the order contains requirements to control those
emissions.
\116\ The RIA in the docket for this proposed U&O FIP contains
more detailed information on our analyses.
\117\ In response to an EPA comment on UDEQ's proposal
questioning why issued approval orders and the GAO cover pneumatic
pumps, but the new Utah Oil and Gas Rules do not, the UDEQ stated
that the 2014 Uinta Basin Emissions Inventory indicated that
pneumatic pump emissions constitute an insignificant portion of the
total VOC emissions at Utah-regulated sources in the Basin. The
comments and UDEQ's responses are available in the docket for this
proposed rule (Docket ID No. EPA-R08-OAR-2015-0709).
---------------------------------------------------------------------------
We are proposing to specify the option that the owner or operator
capture and route all subject emissions through a closed-vent system to
an enclosed combustor or utility flare that is designed and operated to
reduce the mass content of VOC in the emissions vented to it, by at
least 95.0 percent. Requirements for closed-vent systems are proposed
under conditions specified in Sec. 49.4176 (VOC emission control
requirements for covers and closed-vent systems) and requirements for
operation and monitoring of control devices are proposed under
conditions specified in Sec. Sec. 49.4177 (VOC Emission Control
Devices) and 49.4182 (Monitoring Requirements), all of which are
discussed in detail later in the summaries of Covers, Closed-Vent
Systems, and VOC Emission Control Devices and Monitoring Requirements.
We are proposing the alternative option that the owner or operator
design their operations to recover 100 percent of the emissions and
recycle them for use in a process unit or incorporate them into a
product. These proposed control options are the same as the Utah Permit
Requirements and the Utah Oil and Gas Rules.
This proposed U&O FIP approach for controlling pneumatic pumps by
routing emissions to the same control device that controls emissions
from storage tanks and glycol dehydrators is the same as the UDEQ's
approach for controlling pneumatic pumps in site-specific approval
orders issued under Utah Permit Requirements. As described earlier,
regulating pneumatic pumps in this proposed U&O FIP is not comparable
to the UDEQ's recently adopted new Utah Oil and Gas Rules because those
rules do not include requirements for pneumatic pumps.\118\ However, we
are confident that this approach will help achieve ozone air quality
improvements through this proposed U&O FIP, as the 2014 Uinta Basin
Emissions Inventory shows that VOC emissions from pneumatic pumps
constitute 15 percent of the total oil and natural gas-related VOC
emissions on the U&O Reservation.\119\ We are taking comment on whether
and how to control emissions from pneumatic pumps at oil and natural
gas sources.
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\118\ We note that the recently adopted new Utah Oil and Gas
Rules do not contain requirements for pneumatic pumps. We are
proposing requirements for pneumatic pumps requirements, as we have
identified emissions from existing pneumatic pumps as being a
significant source of VOC emissions on the Indian country lands
within the U&O Reservation.
\119\ By contrast, the 2014 Uinta Basin Emissions Inventory
shows that there are a very low number of pneumatic pumps installed
and operating on lands in the Uinta Basin that are regulated by the
UDEQ and the UDEQ has stated that this fact is the reason the Utah
Oil and Gas Rules do not have control requirements for pneumatic
pumps (see the response to comments on the UDEQ's proposed rules in
the docket for this rulemaking).
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We do not expect that a substantial number of oil and natural gas
sources that would meet the applicability criteria of this proposed U&O
FIP will also be subject to NSPS OOOO or OOOOa, or to NESHAP HH.
However, to address any potential regulatory overlap, we are proposing
that any affected crude oil, condensate and produced water storage
tanks, glycol dehydrators and pneumatic pumps that are subject to the
emissions control requirements in the EPA standards, would not be
subject to this proposed U&O FIP requirements for such equipment and
activities, including monitoring, recordkeeping and reporting
requirements associated with such equipment and activities.
We are seeking comment on these proposed requirements, including
information supporting alternative VOC emission reduction and control
efficiency requirements and specific operating condition requirements
that would provide equivalent protection of air quality in the Uinta
Basin and regulatory consistency across the Uinta Basin. We noted
previously that in January 2019, the Utah Air Quality Board approved an
additional rule in the Utah Administrative Code Chapter R307-500 Series
(Oil and Gas) at R307-
[[Page 3518]]
511 to manage associated gas from a completed oil well by either
routing it to a process unit for combustion, routing it to a sales
pipeline, or routing it to a VOC control device, except for emergency
release situations. This rule was approved after we drafted and
evaluated the emissions reductions and costs of the provisions in this
proposed U&O FIP. We intend to evaluate and incorporate equivalent
requirements for associated gas from oil wells in a final U&O FIP.
2. Covers, Closed-Vent Systems
For affected new, modified, and existing sources that are required
to control emissions from storage tanks, glycol dehydrators and
pneumatic pumps, we are proposing in Sec. 49.4177 (VOC emission
control requirements for covers and closed-vent systems) to require the
use of covers on all crude oil, condensate, and produced water storage
tanks and the use of closed-vent systems with all equipment that
captures and routes VOC emissions to the respective vapor recovery or
VOC emission control devices. Because closed-vent systems would be
common to control requirements for storage tanks, glycol dehydrators
and pneumatic pumps, we are proposing these requirements in a separate
section to avoid redundancy. Proposed Sec. 49.4178 also specifies
construction and operational requirements for the covers and closed-
vent systems. The construction and operational requirements for the
covers and closed-vent systems are intended to provide legal and
practical enforceability to ensure that all captured VOC emissions are
routed to the respective vapor recovery or VOC emission control
devices. In addition, for affected new, modified, and existing sources
that are required to control emissions from storage tanks, glycol
dehydrators and pneumatic pumps, Sec. 49.4178 (VOC emission control
devices) we are proposing specific legally and practicably enforceable
construction and operational requirements for enclosed combustors and
utility flares.
We are proposing in Sec. 49.4177 (VOC emission control
requirements for covers and closed-vent systems) to require that each
owner or operator equip the openings on each subject crude oil,
condensate, and produced water storage tank with a cover that ensures
that working, standing, breathing, and flashing losses are efficiently
routed through a closed-vent system to a vapor recovery system, an
enclosed combustor, or a utility flare. We are proposing that each
cover and all openings on the cover (e.g., access hatches, sampling
ports, and gauge wells) must form a continuous barrier over the entire
surface area of the crude oil, condensate, or produced water in the
storage tank. Each cover opening must be secured in a closed, sealed
position (i.e., covered by a gasketed lid or cap) whenever material is
in the tank on which the cover is installed, except when it is
necessary to use an opening to: (1) Add material to, or remove material
from the unit (this includes openings necessary to equalize or balance
the internal pressure of the unit following changes in the level of the
material in the unit); (2) inspect or sample the material in the unit;
or (3) inspect, maintain, repair, or replace equipment inside the unit.
We are proposing to require that each owner or operator subject to
this requirement to control VOC emissions from working, standing,
breathing, and flashing losses from crude oil, condensate, and produced
water storage tanks, glycol dehydrator still vents, and pneumatic pumps
must use closed-vent systems to collect and route the emissions to the
respective vapor recovery or VOC emission control devices. We are
proposing that all vent lines, connections, fittings, valves, relief
valves, and any other appurtenance employed to contain and collect
emissions and transport them to the vapor recovery or VOC control
equipment, must be maintained and operated properly during any time the
control equipment is operating and must be designed to operate with no
detectable emissions. If a closed-vent system contains one or more
bypass devices that could be used to divert all or a portion of the
emissions from entering the vapor recovery or VOC control devices, we
are proposing that the owner or operator must meet one of the following
options for each bypass device: (1) At the inlet to the bypass device,
properly install, calibrate, maintain, and operate a flow indicator
capable of taking periodic readings and sounding an alarm when the
bypass device is open such that the emissions are being, or could be,
diverted away from the control device and into the atmosphere; or (2)
secure the bypass device valve in the non-diverting position using a
car-seal or a lock-and-key type configuration.
The proposed cover and closed-vent system requirements are
comparable on balance with UDEQ requirements for storage vessels in
both the issued site-specific approval orders and the Utah Oil and Gas
Rules. The site-specific approval orders require storage tank thief
hatches to be closed and latched except during tank unloading or other
maintenance activities. They also require that thief hatches be
inspected once every three months to ensure thief hatches are closed,
latched, and the associated gaskets, if any, are in good working
condition. Similarly, the Utah Oil and Gas Rules for storage vessels
require thief hatches to be kept closed and latched except during
unloading or maintenance. This proposed U&O FIP requirements for covers
and closed-vent systems, including the associated monitoring
requirements proposed in Sec. 49.4183 and discussed later, were
developed by consulting the covers and closed-vent system requirements
of EPA standards, such as OOOO and NESHAP HH. For ease of
implementation, these requirements provide more detail than the UDEQ
requirements in both the issued site-specific approval orders and the
Utah Oil and Gas Rules but are comparable on balance with the UDEQ
requirements for storage vessels and closed-vent systems.
3. VOC Emission Control Devices
For new, modified and existing sources that are required to control
emissions from storage tanks, glycol dehydrators and pneumatic pumps,
we are proposing to require in Sec. 49.4178 (VOC emission control
devices) that each owner or operator follow the manufacturer's written
operating instructions, procedures and maintenance schedules to ensure
the use of good air pollution control practices for minimizing
emissions from each enclosed combustor and utility flare. Each utility
flare must be designed and operated according to the requirements of 40
CFR 60.18(b). Each enclosed combustor must be designed and operated to
reduce the mass content of the VOC in the natural gas routed to it by
at least 95 percent continuously. The proposed control efficiency
required for each VOC emissions control device is the same as the
recently adopted Utah Oil and Gas Rules.
We recognize that the site-specific approval orders issued to
existing sources under the Utah Permit Requirements require control
devices to meet 98 percent VOC control efficiency. But we have
concluded that the differences between this proposed U&O FIP and the
Utah Oil and Gas Rules and the Utah Permit Requirements are minimal,
and all were designed to achieve a consistent result. The UDEQ requires
permittees of minor oil and natural gas sources to show compliance with
98.0 percent VOC control device control efficiency by routing all
exhaust gas/vapors (from the storage tanks, glycol dehydrators or
pneumatic pumps) to the operating combustor,
[[Page 3519]]
operating the device according to the manufacturer's written
instructions when gases/vapors are routed to it, operating the device
with no visible emissions, and by performing tests to visually
determine smoke emissions according to EPA Method 22 at 40 CFR part 60,
appendix A. The recently adopted new Utah Oil and Gas Rules require at
least 95.0 percent VOC control efficiency and do not specify methods to
ensure no visible emissions but refer to NSPS OOOOa for demonstrating
compliance with the control efficiency requirements. We note that
combustion devices can be designed to meet 98.0 percent control
efficiencies, and can control emissions by 98.0 percent or more, on
average, in practice when properly operated.\120\ Combustion devices
designed to meet 98.0 percent control efficiency may not, however, be
able continuously to meet this efficiency in practice, due to factors
such as the variability of field conditions and downtime.
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\120\ The EPA has currently reviewed performance tests submitted
for 19 different makes/models of combustor control devices and
confirmed they meet the performance requirements in NSPS subpart
OOOO and NESHAP subparts HH and HHH. All reported control
efficiencies were above 99.9 percent at tested conditions. EPA notes
that the control efficiency achieved in the field is likely to be
lower than the control efficiency achieved at a bench test site
under controlled conditions, but these units should have no problem
meeting 95.0 percent control continuously. See Combustion Device
Performance Testing Summary Table in the docket for this rule.
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During development of NSPS OOOO and OOOOa, 95.0 percent control
efficiency was determined to be the best system of emission reduction
(BSER) and able to be continuously achieved by affected facilities
(e.g., storage vessels, centrifugal compressors) nationwide, although
the EPA is aware that combustors and utility flares may be capable of
achieving instantaneous control efficiencies greater than 95.0
percent.\121\ In determining BSER, the EPA must be confident that the
control efficiency can be achieved continuously by every affected
facility nationwide to which it applies. We are confident that
combustors and utility flares can meet at least 95.0 percent VOC
control efficiency on a continuous basis. While the EPA is aware that
combustion devices commonly used to control VOC-containing gas streams
are capable of demonstrating greater than 98.0 percent continuous VOC
control efficiency in a controlled performance testing environment,
under ideal conditions, based on widespread and readily available
manufacturer test data,\122\ we are not confident that the devices can
meet 98.0 percent continuous VOC control efficiency in the field.
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\121\ See ``Oil and Natural Gas Sector New Source Performance
Standards and National Emissions Standards for Hazardous Air
Pollutants reviews, Parts 60 and 63, Response to Public Comments on
Proposed Rule, See 76 FR 52738 (August 23, 2011), available at
http://www.regulations.gov (Docket ID EPA-HQ-OAR-2010-0505 (Section
2.5.4, pages 127-128; Section 3.4.1, pages 294-295; and Section
3.5.1, pages 302-303)).
\122\ See Combustion Device Performance Testing Summary Table in
the docket for this rule.
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We are proposing to require that all utility flares and enclosed
combustors installed per this rule are models that: (1) Have been
tested by the manufacturer in accordance with specific requirements in
NSPS OOOO; (2) are devices that are designed and operated in accordance
with applicable requirements in 40 CFR 60.18(b), or (3) are devices for
which the owner or operator has conducted performance testing according
to the specific requirements in NSPS OOOO. The Utah Oil and Gas Rules
require that compliance for VOC control devices be demonstrated by
meeting the performance test methods and procedures specified in NSPS
OOOO. The Utah Oil and Gas Rules do not distinguish between utility
flares and enclosed combustors. We determined it was important to
propose specific requirements for the different types of control
devices that may be present at oil and natural gas sources on the U&O
Reservation, because EPA standards, such as NSPS OOOO and OOOOa and
NESHAP HH make such distinctions for legal and practical
enforceability. Therefore, although the proposed requirements for VOC
control devices to demonstrate compliance with the proposed control
efficiency requirements are more detailed for ease implementation, they
are comparable on balance with the Utah Oil and Gas Rules that
reference such requirements in NSPS OOOO.
We have determined that certain work practice and operational
requirements are also necessary for the practical enforceability of the
proposed VOC emission reduction requirements for utility flares or
enclosed combustors. We are proposing that utility flares and enclosed
combustors must be operated within specific parameters to ensure the
effective control of VOC emissions. (This necessity was discussed in
detail in the preamble and Technical Support Documents to the proposed
and final NSPS OOOO).\123\ Specifically, we are proposing that each
owner or operator must ensure that each enclosed combustor or utility
flare is: (1) Operated at all times that emissions are routed to it;
(2) equipped and operated with a liquid knock-out system to collect any
condensable vapors (to prevent liquids from going through the control
device); (3) equipped and operated with a flash-back flame arrestor;
(4) equipped and operated with a continuous burning pilot flame, or an
electronically controlled automatic ignition device; (5) equipped with
a monitoring system for continuous recording of the parameters that
indicate proper operation of each continuous burning pilot flame or
electronically controlled automatic ignition device, such as a chart
recorder, data logger or similar device, or connected to a Supervisory
Control and Data Acquisition (SCADA) system, to monitor and document
proper operation of the enclosed combustor or utility flare; (6)
maintained in a leak-free condition; and (7) operated with no visible
smoke emissions. These proposed work practice and operational
requirements are the same as the Utah Oil and Gas Rules with respect to
operation of the control devices with no visible emissions. Other
proposed work practice and operational requirements are different or
more prescriptive than the Utah Oil and Gas Rules in several areas, to
provide legal and practical enforceability. For example, the Utah Oil
and Gas Rules require all VOC emissions control devices to simply be
equipped and operated with an operational auto igniter. This proposed
U&O FIP requires each enclosed combustor or utility flare to be
equipped and operated with either: (1) A continuous burning pilot
flame; or (2) an electronically controlled automatic ignition device.
All enclosed combustors or utility flares must be equipped with a
monitoring system for continuous measurement and recording of the
parameters that indicate proper operation of each continuous burning
pilot flame or electronically controlled automatic ignition device,
such as a chart recorder, data logger or similar device, or connected
to a SCADA system to monitor and document proper operation of the
device. The work practice and operational requirements for VOC control
devices in this proposed U&O FIP were developed by considering the UDEQ
requirements for VOC control devices in combination with consulting the
work practice and operational requirements for control devices in EPA
standards, including NSPS OOOO and OOOOa and NESHAP HH. Specifically
regarding the proposed requirement to equip enclosed combustors and
utility flares with either
[[Page 3520]]
a continuous burning pilot flame or an electronically controlled
automatic ignition device, provided there is a monitoring system to
indicate proper operation of the device, the EPA has maintained our
position as recently as 2016 that without a continuous ignition
sources, there may be periods of uncontrolled emissions and continuous
ignition sources are designed to combust the flammable portion of the
gas stream, even if the gas stream has a low BTU content.\124\
Therefore, we have maintained that automatic ignition devices may not
be reliable in the field to ensure that there is an ignition source at
all times gas is flowing to a control device, and EPA standards, such
as NSPS OOOO and OOOOa have commonly required that enclosed combustors
be equipped with continuous burning pilot flames and continuous
parameter monitoring systems to ensure the presence of a flame at all
times a gas stream is routed to the control device. Additionally, since
Sec. 60.18(b)(2) of the General Provisions for 40 CFR part 60 is
required for design and operation if an operator uses a utility flare
under this proposed U&O FIP, a continuous pilot flame is required in
that provision, and we believe an equivalent requirement should be
applicable to the enclosed combustion control devices typically used
for controlling emissions from storage vessels and other equipment at
oil and natural gas sources. We recognize that the UDEQ requires auto
igniters on all combustion devices. In the interest of establishing
regulations on the U&O Reservation that are comparable on balance with
the UDEQ requirements, we are proposing a hybrid approach that provides
owners and operators required to control of VOC emissions from storage
tanks, glycol dehydrators and pneumatic pumps the option to use devices
that comply with EPA standards (continuous burning pilot), or to use
electronically controlled automatic ignition devices if the control
device is also equipped with a system that can indicate to the owner
and operator that the automatic ignition device is not operating
properly while gas is being routed to the control device. We expect
that these proposed requirements for control devices would achieve a
comparable result as the requirements for VOC control devices in the
Utah Oil and Gas Rules, ensuring the control device is operated
properly to achieve the required control efficiency, while providing
consistency with EPA policy regarding flares and combustors.
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\123\ These documents can be found in the docket for the NSPS
OOOO rulemaking, Docket ID EPA-HQ-OAR-2010-0505, available at http://www.regulations.gov.
\124\ EPA's Response to Public Comments on the EPA's Oil and
Natural Gas Sector: Emission Standards for New, Reconstructed, and
Modified Sources. 40 CFR part 60, subpart OOOOa. May 2016. Chapter
11--Compliance. Comment Excerpt Number: 17. Pages 188-191. Available
at https://www.regulations.gov (Docket ID EPA-HQ-OAR-2010-0505-
7632), Accessed August 16, 2019.
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Section 49.4178 proposes to allow owners or operators of oil and
natural gas sources, upon receiving written approval, to use control
devices other than an enclosed combustor or utility flare, provided
they achieve at least 95.0 percent VOC control efficiency continuously.
This provision will allow for owners or operators to take advantage of
technological advances in VOC emission control for the oil and natural
gas industry and will provide us with valuable information on any new
control technologies.
We are seeking comment on the covers, closed-vent systems, and VOC
emission control devices provisions in this proposed U&O FIP, including
information supporting more or less stringent requirements that would
provide legal and practical enforceability of the proposed requirement
to reduce VOC emissions from storage tanks, glycol dehydrators, and
pneumatic pumps by 95.0 percent continuously.
4. Fugitive Emissions Control
For new, modified and existing sources, we are proposing LDAR
requirements in Sec. 49.4179 (Fugitive Emissions VOC Emission Control
Requirements) that each owner or operator of an oil and natural gas
source that is required to control VOC emissions from storage tanks,
glycol dehydrators, and pneumatic pumps per Sec. Sec. 49.4174 through
49.4178 conduct periodic inspections of the source to detect leaks from
fugitive emission components and repair them. We are proposing to
define fugitive emissions components in Sec. 49.4171 to include, among
other things: Valves, connectors, open-ended lines, pressure relief
devices, flanges, covers, closed-vent systems, and thief hatches or
other openings on controlled tanks. Each affected owner or operator
will be required to develop and implement a Reservation-wide fugitive
emissions monitoring plan for all of its oil and natural gas sources on
the U&O Reservation that must include the following requirements: (1)
Conduct an initial monitoring of fugitive emissions components at each
affected source within 18 months of the effective date of the rule; (2)
conduct subsequent monitoring once every 6 months after the initial
monitoring for fugitive emissions components at oil and natural gas
sources; (3) describe the fugitive emissions detection monitoring
method to be used, which is limited to onsite optical gas imaging
instruments, EPA Reference Method 21, with a leak defined as any
visible emissions using an optical gas imaging instrument, or an
instrument reading of 500 parts per million volume (ppmv) VOC using EPA
Reference Method 21, or another method approved by the EPA other than
optical gas imaging or EPA Reference Method 21; (4) identification of
manufacturer and model number of any leak detection equipment to be
used; (5) procedures and timeframes for identifying and repairing
components from which leaks are detected, including a requirement to
repair any identified leaks from components that are safe to repair and
that do not require source shutdown within 30 days of identifying a
leak; (6) identification of timeframes to repair leaks that are
technically infeasible to repair (i.e., are unsafe to repair \125\ or
require source shutdown), but no later than 2 years after discovering
such a leak; (7) procedures for verifying effective repair of leaking
components, no later than 30 days after repairing a leak; (8) specific
training and experience needed to perform inspections; (9) description
of procedures for calibration and maintenance of monitoring equipment
to be used; and (10) standard monitoring protocol for a typical
affected source, including a general list of component types that will
be inspected and what supporting data will be recorded (e.g., wind
speed, detection method device-specific operational parameters, date,
time, and duration of inspection). We are proposing in Sec. 49.4179 to
exempt source owners/operators from having to monitor certain
components for various reasons, such as: (1) The monitoring could not
occur without elevating the monitoring personnel which expose the
personnel to other immediate danger; or (2) the component to be
inspected is buried, insulated, or otherwise obstructed in a manner
that prevents access by a monitor probe or optical gas imaging device.
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\125\ Unsafe to repair is defined in the proposed rule as
meaning that operator personnel would be exposed to an imminent or
potential danger as a consequence of the attempt to repair the leak
during normal operation of the source.
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In drafting the proposed LDAR requirements, we reviewed the UDEQ
requirements. For new and modified oil and natural gas sources that may
have obtained coverage under the UDEQ's GAO, we have concluded that the
UDEQ's LDAR inspection frequency requirement is different than the LDAR
inspection frequency requirements for
[[Page 3521]]
oil and natural gas sources under this proposed U&O FIP. For new and
modified sources under the GAO, the UDEQ requires an inspection
frequency based on production levels and number of leaks detected,
which may require monitoring frequencies for only certain sources that
are equivalent to this proposed U&O FIP. For existing sources covered
under site-specific approval orders, we have concluded that the UDEQ's
LDAR frequency requirements (a range of annual to quarterly) to be
different than those in proposed FIP. For new, modified and existing
sources subject to the recently adopted new Utah Oil and Gas Rules, the
LDAR frequency requirements of this proposed U&O FIP are the same. The
LDAR requirements in the Utah Oil and Gas Rules were designed
procedurally to be consistent with NSPS OOOOa, though the applicability
threshold is different. The UDEQ's site-specific approval orders, the
GAO, and the recently adopted new Utah Oil and Gas Rules all require
implementation of an LDAR program at facilities that are required to
control storage vessel, dehydrator and/or pneumatic pump emissions,
which is consistent with this proposed U&O FIP. We determined that,
particularly for existing sources, in order to provide consistent
requirements across the Uinta Basin, the LDAR requirements in this
proposed U&O FIP should be consistent with the LDAR requirements for
new, modified and existing sources in the Utah Oil and Gas Rules, as
those rules apply prospectively to all oil and natural gas well sites
on non-reservation Indian country lands in the Uinta Basin that are not
already subject to site-specific approval orders. If the sources in the
Uinta Basin that are regulated by the UDEQ are also subject to the LDAR
requirements of the NSPS OOOOa, the NSPS requirements supersede the
UDEQ requirements. Similarly, if the sources in the Uinta Basin that
would be regulated by the EPA on the U&O Reservation are subject to the
LDAR requirements of the NSPS OOOOa, those sources would be exempt from
complying with the LDAR requirements in this proposed U&O FIP. The
fugitive emissions LDAR procedural requirements proposed in this
proposed U&O FIP are consistent with the Utah Oil and Gas Rules. We are
proposing applicability criteria for implementing an LDAR program, and
LDAR inspection frequency requirements, that are consistent with
requirements in the Utah Oil and Gas Rules, which meets our goal of
regulatory consistency across the Uinta Basin. We expect that the
proposed LDAR requirements will result in meaningful reductions in VOC
emissions and ground-level ozone production, significantly furthering
our main objective for this proposed U&O FIP. We are seeking comment on
the fugitive emissions control requirements in this proposed U&O FIP,
including information supporting more or less stringent inspection
requirements.
We are proposing a provision allowing for the use of alternative
methods of leak detection, other than EPA Reference Method 21 or
optical gas imaging instrument, to demonstrate compliance with the
fugitive emissions monitoring requirements, provided the method is
approved by the EPA. The Uinta Basin generally encompasses an area of
over 6,800 square miles with hundreds of miles of dirt roads connecting
over 10,000 oil and natural gas wells. According to the 2014 Uinta
Basin Emissions Inventory,\126\ the average number of wells per well
pad is 1.3. The inventory shows that fugitive emissions are the second
highest VOC emissions source on the U&O Reservation, at about 13,900
tpy. The total does not account for emissions due to abnormal process
operations, which is discussed in the following paragraphs. Recognizing
that technology used to detect, measure, and mitigate emissions is
rapidly developing, on July 18, 2016, the EPA issued a request for
information, (RFI) \127\ inviting all parties to provide information on
innovative technologies to accurately detect, measure, and mitigate
emissions from the oil and natural gas industry. The intent of this
notice was to solicit data supporting alternative approaches to limit
emissions from this sector.
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\126\ The complete, detailed dataset for the 2014 Uinta Basin
Emission Inventory, including location data of every facility, can
be viewed in the docket for this rule (Docket ID No. EPA-R08-OAR-
2015-0709), SQLite database titled OGEI_v2.2_2014FINAL.db''.
\127\ See 81 FR 46670 (July 18, 2016).
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Studies have been conducted specific to the Uinta Basin that
investigated the viability of leak detection from an aerial platform.
One study \128\ employed a helicopter-based infrared camera, at an
elevation of approximately 50 meters above ground level, to survey more
than 8,000 oil and natural gas well pads in seven U.S. basins to assess
the prevalence and distribution of hydrocarbon sources whose fugitive
emissions were high enough to be labeled high-emitters. At each site
with detected emissions, the survey team reported the site's location
and the number and equipment type of each observed emission source.
Survey results indicated the prevalence of high-emitting sites was four
percent of all the sites surveyed across the seven basins examined. In
the Uinta Basin, 1,389 well pad facilities were flown over, and high
emissions were observed at 6.6 percent of those well pads.
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\128\ ``Aerial Surveys of Elevated Hydrocarbon Emissions from
Oil and Gas Production Sites,'' Environmental Science and
Technology, 2016, 50 (9), pp 4877-4886, publication date April 5,
2016, available at http://pubs.acs.org/doi/abs/10.1021/acs.est.6b00705, accessed August 16, 2019.
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The high emitting sources, or ``super-emitters,'' are likely due to
abnormal process conditions.\129\ Examples of abnormal process
conditions, which could be persistent or episodic, include: Failures of
tank control systems, malfunctions upstream of the point of emissions
(for example, stuck separator dump valve resulting in produced gas
venting from tanks), design failures (for example, vortexing or gas
entrainment during separator liquid dumps) and equipment or process
issues (for example, over-pressured separators, malfunctioning or
improperly operated dehydrators or compressors).\130\
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\129\ Zavala-Araiza, D., Alvarez, R.A., Lyon, D.R., Allen, D.T.,
Marchese, A.J., Zimmerle, D.J., & Hamburg, S.P. (2017). Super-
emitters in natural gas infrastructure are caused by abnormal
process conditions. Nature communications, 8, 14012.
\130\ The 2014 Uinta Basin Emissions Inventory has not accounted
for the phenomenon of ``super-emitters.''
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We are seeking information on alternative methods of leak detection
(e.g., aerial) that could potentially achieve meaningful and more cost-
effective reductions in fugitive VOC emissions that contribute to ozone
formation. We are seeking input on how these advanced monitoring
technologies and platforms could be broadly applied to new, modified
and existing sources in the Uinta Basin and whether any of these
advanced monitoring technologies would be effective in the Uinta Basin
and should be approvable as an alternative leak detection compliance
method under a final U&O FIP. We are also seeking input on the criteria
that EPA should consider in approving alternative leak detection
compliance methods, including appropriate accuracy and quality
assurance standards that alternative methods would need to meet to
demonstrate equivalency to onsite optical gas imaging instruments or
onsite EPA Reference Method 21. Specific descriptions of the approach,
frequency of monitoring, detection thresholds, limiting factors in
detection, costs and availability for alternative leak detection
methods would be helpful.
[[Page 3522]]
5. VOC Emissions Control Requirements for All Sources
Sections 49.4180 (VOC emission control requirements for Tank Truck
Loading), 49.4180 (VOC emission control requirements for pneumatic
controllers) and 49.4184 (Other combustion devices) contain proposed
requirements for all new, modified and existing oil and natural gas
sources, regardless of source-wide or emission unit specific emissions.
Like the requirements in Utah's Oil and Gas Rules for oil and natural
gas sources in UDEQ's jurisdiction, this proposed U&O FIP's
requirements are as follows: (1) Tank trucks used for transporting
intermediate crude oil, condensate, or produced water must be loaded
using bottom filling or submerged fill pipes; (2) all existing
pneumatic controllers must meet the pneumatic controller standards in
NSPS OOOO at 40 CFR 60.5390(b)(2) and (c)(2) and NSPS OOOOa at 40 CFR
60.5390a(b)(2) and (c)(2); and (3) all existing enclosed combustors,
utility flares, or other open flares present at sources on a voluntary
basis that are not required to control storage tank, glycol and
dehydrator and pneumatic pump emissions (per Sec. Sec. 49.4174 through
49.4178), and are voluntarily operated, must be equipped with an
electronically controlled automatic ignition device.
Our proposed requirements for truck loading/unloading diverge in
one respect from what the UDEQ is requiring in their recently adopted
rulemaking. The UDEQ requires that VOC emissions from tank truck
loading and unloading at sources required to control storage tank
emissions be captured using a vapor capture line and routed to the
onsite combustor or a separate combustor for VOC control. We are not
proposing an equivalent requirement, as we have determined that it may
not be cost effective presently given limited estimated emissions for
truck loading/unloading on the U&O Reservation, based on the 2014 Uinta
Basin Emissions Inventory. Assuming that the annualized cost to install
a vapor capture line to an existing combustor is similar to that of
routing pneumatic pumps to a combustor (approximately $1,627 per
source) and assuming there are approximately 2,100 sources that would
be required to add a combustor, such a requirement would result in high
costs relative to the VOC emissions reductions that would be achieved.
Concerning pneumatic controllers, this proposed U&O FIP
requirements for pneumatic controllers require owners/operators of
affected pneumatic controllers to meet the standards established for
pneumatic controllers in NSPS OOOO and OOOOa. We are proposing that
owners/operators of affected controllers meet the tagging requirements
in 40 CFR 60.5390(b)(2), 60.5390(c)(2) and 60.5390a(b)(2) and (c)(2),
except that the month and year of installation, reconstruction or
modification is not required. This exception is consistent with the
Utah Oil and Gas Rules.
Lastly, for existing enclosed combustors, utility flares, or other
open flares present at sources that would not be required to comply
with the substantive VOC emissions control requirements of proposed
sections Sec. Sec. 49.4174 through 49.4178, we are proposing to
require that those voluntarily operated control devices be equipped
with an electronically controlled automatic ignition device. This
approach is the same as the requirements of the Utah Oil and Gas Rules,
which require automatic igniters on all existing combustion devices.
Contrary to the proposed requirements in Section 49.4179 (VOC Emission
Control Devices) for devices used to comply with the substantive VOC
emissions control requirements of this proposed U&O FIP, we determined
that requiring a system to monitor proper operation of devices used to
ensure the presence of a flame at all times a gas stream is routed to
the device was unreasonable for voluntarily operated devices and would
result in requirements for such sources on the U&O Reservation that are
not comparable to requirements for such sources on lands regulated by
the UDEQ.
G. Monitoring Requirements
For new, modified, and existing sources, we are proposing in Sec.
49.4183 (Monitoring Requirements) to require each owner or operator to
conduct source monitoring necessary for the practical enforceability of
all of this proposed U&O FIP's VOC emission reduction requirements,
including: (1) Monthly inspections of each closed-vent system,
including storage tank openings, thief hatches, and bypass devices, for
defects that can result in air emissions according to the procedures in
40 CFR 60.5416(c) [NSPS OOOO]; (2) monthly auditory, visual, olfactory
(AVO) inspections of each VOC emissions control device, tank thief
hatch, cover, seal, pressure relief valve, and closed-vent system to
ensure proper condition and functioning, performed while the storage
tanks are being filled, and corrective action within 5 days of
discovering the device is not operational; and (3) monitoring of each
enclosed combustor or utility flare to confirm proper operation as
follows: By checking the system for proper operation whenever an
operator is onsite and responding to any indication of pilot flame
failure and to ensure the pilot flame is relit as soon as practically
and safely possible; and (4) monitoring of visible emissions according
to the requirements in 40 CFR 60.5412(d)(i)(iii) [NSPS OOOO, which
requires EPA Method 22 visual emissions testing].
These proposed monitoring requirements are comparable on balance
with those in the Utah Permit Requirements and Utah Oil and Gas Rules,
with some exceptions made to ensure legally and practicably enforceable
control of VOC emissions.
For example, the Utah Permit Requirements and Utah Oil and Gas
Rules require installation and operation of an automatic ignition
device and operations with no visible emissions for all VOC control
devices, but there are no corresponding monitoring requirements to
demonstrate compliance with those requirements. We expect that the
proposed monitoring requirements for ensuring there is a constant
ignition source when gas is flowing to the control device and for
visible emissions testing will provide legal and practical
enforceability.
We are seeking comment on the monitoring requirements in this
proposed U&O FIP, including information supporting more or less
stringent monitoring requirements that would provide legal and
practical enforceability of the proposed VOC emission control
requirements.
H. Recordkeeping Requirements
For new, modified and existing sources, we are proposing in Sec.
49.4184 (Recordkeeping Requirements) to require that each owner or
operator of an affected oil and natural gas source keep specific
records to be made available upon request, in lieu of voluminous
reporting requirements. The records that must be kept include all
required measurements, monitoring results, emissions calculations, and
deviations or exceedances of rule requirements and corrective actions
taken, as well as any manufacturer specifications and guarantees or
engineering analyses. These recordkeeping requirements provide legal
and practical enforceability for the control and emission reduction
requirements of this rule.
We are seeking comment on the recordkeeping requirements in this
proposed U&O FIP, including
[[Page 3523]]
information supporting more or less stringent recordkeeping
requirements that would provide legal and practical enforceability of
the proposed VOC emission control requirements.
I. Notification and Reporting Requirements
For new, modified, and existing sources, we are proposing in Sec.
49.4185 (Reporting Requirements) to require that each owner or operator
of an affected oil and natural gas source prepare and submit an annual
compliance report, beginning 90 days after the end of the first
compliance reporting period, which is one year after this rule becomes
effective and covers the period for the previous calendar year. The
report must include a summary of required records and a summary of
deviations or exceedances of any requirements of the final FIP and the
corrective measures taken. Additionally, a report of results must be
submitted for any performance test we require. These reporting
requirements provide legal and practical enforceability for the control
and emission reduction requirements of this rule. We are seeking
comments on the reporting frequency in this proposed U&O FIP, including
information supporting a more or less frequent reporting schedule.
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This proposed action is an economically significant regulatory
action and was submitted to the Office of Management and Budget (OMB)
for review. Any changes made in response to the OMB recommendations
have been documented in the docket. The EPA prepared an analysis of the
potential costs and benefits associated with this proposed action. This
analysis, ``Regulatory Impact Analysis of for the Proposed Federal
Implementation Plan for Managing Emissions from Oil and Natural Gas
Sources on Indian Country Lands Within the Uintah and Ouray Indian
Reservation in Utah'' (Ref. EPA-908/Z-16-001), is available in the
docket, and is summarized in Section IV.I. Benefits and Costs of the
Proposed Rule.
B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs
This action is expected to be an Executive Order 13771 regulatory
action. Details on the estimated costs of this proposed rule can be
found in the EPA's analysis of the potential costs and benefits
associated with this action.
C. Paperwork Reduction Act (PRA)
The information collection activities in this proposed rule have
been submitted to the Office of Management and Budget (OMB) for
approval under the PRA. The Information Collection Request (ICR)
document that the EPA is preparing for this proposed U&O FIP has been
assigned EPA ICR number 2539.01. You can find a copy of the ICR in the
docket for this rule, and it is briefly summarized here.
This proposed action imposes a new information collection burden
under the PRA. The ICR covers information collection necessary to meet
the requirements in this proposed U&O FIP. In general, owners or
operators are required to maintain records of all required monitoring
and other rule compliance. This proposed U&O FIP also requires annual
reports containing information for each oil and natural gas source,
including a summary of all required records during the reporting
period, and a summary of all instances where operation was not
performed in compliance with the requirements of this proposed U&O FIP
during the reporting period. Additionally, a summary emissions
inventory is required for each source covered under this rulemaking
once every three years. These reports and records are essential in
determining compliance and are required of all sources subject to this
proposed U&O FIP. The information collected will be used by the EPA or
the Ute Indian Tribe to determine the compliance status of sources
subject to the rule.
Respondents/affected entities: The potential respondents are owners
or operators of existing, new, and modified oil and natural gas sources
on Indian country lands within the U&O Reservation.
Respondent's obligation to respond: Mandatory. The EPA is charged
under sections 301(a) and 301(d)(4) of the CAA to promulgate
regulations as necessary to protect tribal air resources. Promulgating
this proposed U&O FIP would address winter ozone air quality
concentrations that exceed the NAAQS, and given the recent ozone NAAQS
nonattainment designation, when combined with the National O&NG FIP
amendments, would provide justification to allow continued streamlined
construction authorization of new or modified true minor oil and
natural gas sources, all in a manner that seeks to provide regulatory
consistency between state and federal requirements with regard to
controlling VOC emissions from existing, new, and modified oil and
natural gas operations on the U&O Reservation. There is no other
federal rule, including the recently finalized NSPS and NESHAP for the
Oil and Natural Gas Sector (NSPS OOOO, NSPS OOOOa, and NESHAP HH), that
establishes air pollution control regulations for the particular oil
and natural gas operations that exist on the U&O Reservation that are
appropriate to address the issues identified for this area. This is in
contrast to oil and natural gas operations on non-Indian-country lands
under the State of Utah's jurisdiction, which are governed by the UDEQ
regulations and Utah Division of Oil, Gas, and Mining regulations.
Consistent with the regulatory structure that exists on non-Indian
country lands, this proposed U&O FIP has requirements for VOC emissions
control and reductions, monitoring, recordkeeping, and reporting.
In addition, section 114(a) states that the Administrator may
require any owner or operator subject to any requirement of this Act
to:
Establish and maintain such records;
Make such reports;
Install, use, and maintain such monitoring equipment, and
use such audit procedures, or methods;
Sample such emissions (in accordance with such procedures
or methods, at such locations, at such intervals, during such periods,
and in such manner as the Administrator shall prescribe);
Keep records on control equipment parameters, production
variables or other indirect data when direct monitoring of emissions is
impractical;
Submit compliance certifications in accordance with
section 114(a)(3); and
Provide such other information as the Administrator may
reasonably require.
Estimated number of respondents: We estimate that 4,894 oil and
natural gas sources will be subject to one or more requirements in this
proposed U&O FIP over the next three years.
Frequency of response: Annual reports are required. Respondents
must monitor all specified criteria at each affected source and
maintain these records for five years.
Total estimated burden: 123,000 hours per year (3-year average),
for all operators subject to this proposed U&O FIP.
Total estimated cost: $21.6 million per year; includes labor cost
of $6.4 million, annualized capital cost of $6.4 million, and $8.7
million in operation and maintenance costs for all of the
[[Page 3524]]
operators that would subject to this proposed U&O FIP.
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.
Submit your comments to the EPA on the Agency's need for this
information, the accuracy of the provided burden estimates and any
suggested methods for minimizing respondent burden, using the docket
identified at the beginning of this proposed rule. You may also send
your ICR-related comments to OMB's Office of Information and Regulatory
Affairs via email to [email protected], Attention: Desk
Officer for the EPA. Since OMB is required to make a decision
concerning the ICR between 30 and 60 days after receipt, OMB must
receive comments no later than 30 days after publication of the ICR in
the Federal Register. The EPA will respond to any ICR-related comments
in the final rule.
D. 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 owners/
operators of oil and natural gas sources on the U&O Reservation. They
were identified through a review of existing minor source registrations
submitted by owners/operators on the U&O Reservation under the Federal
Indian Country Minor NSR rule. The Agency has determined that two out
of eleven total small entities, or 18%, may experience an impact of 0%
to 3% of revenues.\131\
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\131\ The RIA includes a more detailed analysis of the impact of
the proposed rule to small entities. It can be viewed in the docket
for this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
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E. Unfunded Mandates Reform Act (UMRA)
This proposed action does not contain an unfunded mandate of $100
million of more as described in UMRA, 2 U.S.C. 1531-1538, and does not
significantly or uniquely affect small governments. This action imposes
no enforceable duty on any state, local or tribal governments, and the
action contains a federal private sector mandate that may result in the
expenditures of less than $100 million for the private sector in any
one year.
1. Statutory Authority
The legal authority for this rule stems from sections 301(a) and
301(d)(4) of the CAA and 40 CFR 49.11(a). See section III.B of this
preamble for more information.
2. Costs and Benefits
As discussed in Section IV.I. Benefits and Costs of the Proposed
Rule, the estimated total annualized engineering costs of this proposed
rule in 2021, accounting for the recovered natural gas, are $64 million
in 2016 dollars using a 7 percent discount rate and $56 million in 2021
in 2016 dollars using a 3 percent discount rate.\132\ The EPA estimates
that the proposed rule will lead to annual monetized benefits of about
$10 million in 2021 using a 3 percent discount rate and $2.9 million at
a 7 percent discount rate. Including the resources from recovered
natural gas that would otherwise be vented, the quantified annualized
net benefits of the regulation (the difference between the monetized
benefits and total annualized compliance costs) are estimated to be -
$39 million in 2021 in 2016 dollars using a 3 percent interest rate and
-$46 million using a 7 percent interest rate.\133\ More in-depth
information on costs and benefits, including non-monetized or
quantified benefits, of the final regulation can be found in the
RIA.\134\ We are seeking comment on the cost assumptions used in our
RIA, including comments and information supporting higher or lower cost
estimates. Specifically, the EPA is requesting comment on the capital
costs of routing a glycol dehydrator and/or pneumatic pump to an
existing combustor.
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\132\ The recordkeeping and reporting costs calculated for the
ICR analysis, discussed earlier, are imbedded in the total
annualized engineering costs included here.
\133\ The RIA in the docket for this rulemaking discusses this
calculation in detail.
\134\ The RIA includes a more detailed discussion of the
potential costs and benefits associated with this rule. It can be
viewed in the docket for this rulemaking (Docket ID No. EPA-R08-OAR-
2015-0709).
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3. Effects on National Economy
The EPA estimated the labor impacts due to compliance with the
proposed rule for affected entities within the oil and natural gas
sector, including the installation, operation, and maintenance of
control equipment and control activities, as well as the labor
associated with new reporting and recordkeeping requirements. We did
not estimate any potential changes in labor outside of the affected
sector, and due to data and methodology limitations we did not estimate
net employment impacts for the affected sector, apart from the partial
estimate of the labor requirements related to control strategies. The
labor requirements analysis used a bottom-up engineering-based
methodology to estimate employment impacts. The engineering cost
analysis of the RIA includes estimates of the labor requirement costs
associated with implementing the regulations. Each of these labor
changes may be required as part of an initial effort to comply with the
new regulation.
4. Regulatory Alternatives
Alternate regulatory options examined in the RIA include a low-
impact option (Option 1) and a high-impact option (Option 3). The
Option 1 requirements would be like Option 2; however, they would not
include control of emissions from glycol dehydrators. Additionally,
Option 1 would require implementation of LDAR at sources with a gas-to-
oil ratio (GOR) of greater than or equal to 300, that produce on
average, greater than 15-barrel equivalents per well per day. This is
in contrast to proposed Option 2, which would require implementation of
an LDAR program at sources that are required to control storage tank,
glycol dehydrator, and pneumatic pump VOC emissions per proposed
Sec. Sec. 49.4173 through 49.4177. The EPA could have considered a
range of even less stringent regulatory options than Option 1 to
evaluate and propose, including an option that would not require
retrofit of existing storage tanks with controls or requires controls
less broadly. Retrofitting existing tanks with controls is one of the
higher costs evaluated in this proposed rulemaking. Such an option,
however, would lead to even greater disparity with the requirements for
similar sources in Utah jurisdiction in the Basin than the current
Option 1. However, we are seeking comment on whether it is appropriate
to consider a less stringent option that does not include retrofitting
existing storage tanks for controls, recognizing that if comments
support it as a viable regulatory option and if the agency proposes to
adopt that option, the EPA may be required to hold an additional public
comment period on this rulemaking. Option 3 (high impact) would require
implementation of an LDAR program at all existing oil and natural gas
sources, regardless of throughput, or tank, dehydrator, and pneumatic
pump annual VOC emissions.
This proposed U&O FIP results in estimated annualized costs of $60
million in 2021 using a 3 percent
[[Page 3525]]
interest rate, resulting in a cost of control of $3,000 per ton of the
estimated 20,000 tons of VOC reduced, and -annualized costs of $68
million using a 7 percent interest rate, resulting in a cost of control
of $3,400 per ton of the estimated 20,000 tons of VOC reduced.
The annualized costs of the first option (Option 1) would be $43
million in 2021 using a 7 percent discount rate, resulting in a cost of
control of $3,300 per ton of the estimated 13,000 tons of VOC reduced,
and $38 million in 2021 using a 3 percent discount rate, resulting in a
cost of control of $2,900 per ton of VOC reduced. Option 1 was analyzed
to reduce burden on small entities, while still achieving VOC emissions
reductions. Although this option would cost less overall than proposed
Option 2, it would achieve significantly less benefits in the form of
VOC emissions reductions (13,000 tons versus 20,000 tons for proposed
Option 2), because emissions from glycol dehydrators would not be
controlled and a smaller number of storage tanks would be controlled,
because the VOC emissions threshold triggering control would be
different than Option 2.\135\ Additionally, by not controlling glycol
dehydrator emissions in Option 1, there would also be significantly
less benefits from the associated reductions in HAP emissions that are
more reactive in forming ozone than the lighter-end VOC emissions
resulting from storage tanks, pneumatic pumps and fugitive emissions.
Implementation of Option 1 would also lead to regulatory requirements
that are inconsistent with the requirements for equivalent sources in
UDEQ jurisdiction, thus not meeting our goal of regulatory consistency
across the Uinta Basin.
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\135\ Under Option 1, the EPA would determine the four tpy
threshold triggering control with combined source-wide VOC emissions
from storage tanks and pneumatic pumps only.
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The annualized costs of Option 3 would be $79 million in 2021 using
a 7 percent discount rate, resulting in a cost of control of $3,500 per
ton of the estimated 23,000 tons of VOC reduced, and $71 million in
2021 using a 3 percent discount rate, resulting in a cost of control of
$3,100 per ton of VOC reduced. Option 3 was analyzed to achieve a
greater level of VOC emissions reductions. Although this option would
achieve about 3,000 more tons of VOC emissions reductions than proposed
Option 2, it would also result in increases in costs. Additionally,
Option 3 would lead to regulatory requirements that are inconsistent
with the requirements for equivalent sources in UDEQ jurisdiction, thus
not meeting our goal of regulatory consistency across the Uinta Basin.
For a more in-depth analysis of these options, see the RIA for this
proposed U&O FIP.
F. Executive Order 13132: Federalism
This proposed 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.
G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This proposed action has tribal implications. However, it will
neither impose substantial direct compliance costs on federally
recognized tribal governments, nor preempt tribal law. The EPA has
conducted outreach on this proposed rule consistent with the EPA Policy
on Consultation and Coordination with Indian Tribes (May 4, 2011) via
ongoing monthly meetings with tribal environmental professionals \136\
before and during the development of this proposed action, and further
as follows: (1) Via Tribal consultation with the Ute Indian Tribe
Business Committee regarding options that the EPA could consider to
address the Uinta Basin air quality concerns; (2) via stakeholder
meetings where the Tribe was included and participated in emissions
contributions discussions specific to the EPA's strategy for addressing
the Uinta Basin air quality concerns; and (3) via ongoing stakeholder
working group meetings convened by the Ute Indian Tribe Business
Committee where the EPA participated in discussions with the Tribe and
industrial operators on strategies to reduce existing ozone-related
emissions and provide a streamlined construction authorization
mechanism for new and modified minor oil and natural gas sources given
the recent nonattainment designation for the 2015 ozone NAAQS.
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\136\ These monthly meetings are general in nature, dealing with
many air-related topics, and are not specific to this proposed U&O
FIP.
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The EPA held consultations with elected officials of the Ute Indian
Tribe Business Committee on the following dates: July 22, 2015;
December 17, 2016; November 13, 2017; March 22, 2018, August 17, 2018;
November 14, 2018; and February 28, 2019. The EPA has also participated
in tribally convened stakeholder meetings on March 22, 2017 and June 1-
2, 2017.
During the consultation discussions on this proposed U&O FIP, the
Tribe expressed concerns regarding their economic needs to develop and
generate revenue from Tribal oil and natural gas resources; to consider
air quality effects on the health, safety, and welfare concerns of
their tribal membership living within the exterior boundaries of the
U&O Reservation and the Uinta Basin; and to balance regulatory
requirements for an even economic and regulatory playing field.\137\ We
addressed questions the Tribe had regarding the controls being
considered, the ability for owners or operators to take credit for the
controls for purposes such as permitting and NAAQS attainment, the
estimated costs of proposed controls, the characterization of Indian
country, and the breadth of oil and natural gas source category types
proposed to be regulated. The Ute-Tribe-convened stakeholder meetings
involved discussions on appropriate ways to expedite nonattainment
permitting for new and modified minor oil and natural gas sources on
the U&O Reservation. Ute Indian Tribe and industry participants
recognized that existing source emissions reductions would likely be
necessary in order for the EPA to demonstrate that construction
authorization for new and modified sources would not cause or
contribute to NAAQS violations in the nonattainment area.
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\137\ The records of communication for all consultations and
preliminary discussions with the Ute Indian Tribe are included in
the docket for this rulemaking (Docket ID No. EPA-R08-OAR-2015-
0709).
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Enacting a FIP for the U&O Reservation is directly responsive to
the Ute Indian Tribe's air quality concerns in that we are proposing to
implement our CAA authority to protect air quality on and surrounding
Indian country lands within the U&O Reservation in a manner that
provides regulatory consistency with respect to requirements for oil
and natural gas sources on adjacent lands regulated by the state in the
Basin. We are committed to supporting tribes' right to self-governance
and to protecting their inherent sovereignty. We will continue to
provide outreach to tribal environmental professionals and continue
consultation with tribal leadership on this proposed action.
H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is subject to Executive Order 13045 because it is an
[[Page 3526]]
economically significant regulatory action as defined by Executive
Order 12866 and the EPA has concluded that the environmental health or
safety risks addressed by this proposed action have a disproportionate
effect on children. This action's health and risk assessments are
contained in the Purpose, Air Quality Review, Benefits and Costs, and
Executive Order 12898: Federal Actions to Address Environmental Justice
in Minority Populations and Low Income Populations sections in this
preamble (sections II., IV.G., IV.I., and VI.J., respectively), with
more detailed information contained in the RIA for this
rulemaking.\138\ In fact, this proposed U&O FIP should have a positive
effect on the health of the residents of the U&O Reservation, including
children, as it is expected to result in a reduction in ambient ozone
concentrations, which disproportionately impact children, elderly, and
those with respiratory ailments.
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\138\ The RIA includes more detailed discussions of the health
and risk assessments for this rule and can be viewed in the docket
for this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
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I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not a ``significant energy action'' as defined in
Executive Order 13211,\139\ because it is not likely to have a
significant adverse effect on the supply, distribution, or use of
energy. The basis for these determinations follows.
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\139\ See 66 FR 28355 (May 22, 2001).
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This proposed action was determined to be a significant regulatory
action that was submitted to the OMB for review under Executive Order
12866. Any changes made in response to the OMB recommendations have
been documented in the docket. The EPA prepared an analysis of the
potential costs and benefits associated with this proposed action,
which is included in the RIA,\140\ and is summarized in Section IV.I.
Benefits and Costs of the Proposed Rule.
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\140\ The RIA includes a more detailed discussion of the
potential costs and benefits associated with this rule. It can be
viewed in the docket for this rulemaking (Docket ID No. EPA-R08-OAR-
2015-0709).
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We have concluded that, while this action may have some effects on
the supply, distribution, or use of energy, it is not likely to have
significant adverse energy effects. Most owners/operators of existing
oil and natural gas production sources on the U&O Reservation also
operate sources on non-Indian country lands within and outside of the
U&O Reservation, where they are already required to employ the
emissions control technologies required by this proposed U&O FIP.
Additionally, we expect that these owners/operators will also operate
new and modified sources in the Uinta Basin that are subject to similar
NSPS OOOO and OOOOa, NESHAP HH, and other oil and natural gas sector-
related control requirements within the Uinta Basin. Therefore, it is
expected that the owners/operators will continue to procure necessary
control equipment and supplies from the same suppliers they currently
use for non-Indian country existing, new or modified sources. Further,
only the higher-producing sources are expected to be subject to the
more substantive emission control requirements in this proposed U&O
FIP, and those sources are more likely to be able to accommodate the
additional costs, so it is not expected that the new requirements alone
would factor significantly into decisions to slow or halt production
and thereby cause a shortfall in supply. Rather, the prices of oil and
natural gas are likely to be a more significant factor in decisions on
reducing production from existing sources, and prices are not expected
to change appreciably over from 2020 to 2025.\141\
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\141\ The RIA includes more detailed information on oil and
natural gas prices. It can be viewed in the docket for this
rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
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Additionally, this proposed U&O FIP establishes several emissions
control standards that give regulated entities flexibility in
determining how to best comply with the regulation. Even within the
geographically and economically homogeneous affected area within the
Uinta Basin, this flexibility is an important factor in reducing
regulatory burden. For more information on the estimated energy effects
of the proposed rule, please see the RIA, which is in the docket for
this proposed rule.
J. National Technology Transfer and Advancement Act (NTTAA)
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), 15 U.S.C. 272 note, directs the EPA to use
voluntary consensus standards (VCS) in its regulatory activities unless
to do so would be inconsistent with applicable law or otherwise
impractical. VCS are technical standards, which include materials
specifications, test methods, sampling protocols, business practices
and management systems developed or adopted by voluntary consensus
standards bodies (VCSB), both domestic and international. These bodies
plan, develop, establish or coordinate voluntary consensus standards
using agreed-upon procedures.
This action involves technical standards. Therefore, the EPA
conducted a search to identify potentially applicable VCS. However, the
Agency identified no such standards.\142\ Therefore, the EPA has
decided to use EPA Methods 21 and 22 of 40 CFR part 60, appendix A-7
and part 63, appendix A.\143\
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\142\ ``Voluntary Consensus Standard Results for Federal
Implementation Plan for Managing Emissions from Oil and Natural Gas
Sources on the Uintah and Ouray Indian Reservation in Utah,''
Memorandum from Steffan Johnson, Group Leader, U.S. EPA, Measurement
Technology Group, to Deirdre Rothery, Unit Chief Air Permitting and
Monitoring Unit, U.S. EPA Region 8 Air Program, dated December 22,
2017, available in the Docket for this proposed rule (Docket ID No.
EPA-R08-OAR-2015-0709).
\143\ The EPA Reference Methods 21 and 22 can be accessed at
https://www.ecfr.gov/cgi-bin/ECFR?page=browse (Search Title 40, Part
60 and Part 63, accessed August 21, 2019.
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K. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
The EPA concludes that this action does not have disproportionately
high and adverse human health or environmental effects on minority
populations, low-income populations, and/or indigenous peoples, as
specified in Executive Order 12898.\144\
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\144\ See 59 FR 7629 (February 16, 1994).
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The documentation for this decision is contained in the RIA \145\
for this proposed rule. Our objective in developing this proposed rule
is to protect the communities in and near Indian country lands within
the U&O Reservation, where existing oil and natural gas operations have
been shown to contribute to exceedances of the ozone NAAQS. The impacts
of this proposed rule are expected to be beneficial, rather than
adverse, and its benefits are expected to accrue to communities in and
near Indian country lands within the U&O Reservation. As explained in
Section IV.F., the EPA has quantified the expected emissions impacts
from this proposed action and found that the proposed action will
result in large reductions of VOC emissions.
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\145\ The RIA includes a more detailed discussion of the
environmental justice analysis for this rule. It can be viewed in
the docket for this rulemaking (Docket ID No. EPA-R08-OAR-2015-
0709).
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This proposed action will also provide regulatory certainty to
owners/operators, by imposing, to the extent
[[Page 3527]]
appropriate, requirements that are the same as or consistent with those
applicable to such existing sources that are regulated by the UDEQ in
the Uinta Basin because they are not on Indian country lands within the
Reservation. This will ensure that air quality is protected
consistently across the Uinta Basin and our Environmental Justice (EJ)
analysis that can be found in the RIA for this rulemaking supports the
conclusion that this action will not result in disproportionate
impacts.
List of Subjects in 40 CFR Part 49
Environmental protection, Administrative practice and procedure,
Air pollution control, Indians, Indians-law, Indians-tribal government,
Intergovernmental relations, Reporting and recordkeeping requirements.
Dated: December 16, 2019.
Gregory Sopkin,
Regional Administrator, Region 8.
For reasons set forth in the preamble, part 49 of title 40 of the
Code of Federal Regulations is proposed to be amended as follows:
PART 49--INDIAN COUNTRY: AIR QUALITY PLANNING AND MANAGEMENT
0
1. The authority citation for part 49 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
0
2. Add the undesignated center heading ``Federal Implementation Plan
for Managing Emissions from Oil and Natural Gas Sources on the Indian
Country Lands Within the Uintah and Ouray Indian Reservation in Utah''
and Sec. Sec. 49.4169 through 49.4185 to subpart K to read as follows:
Subpart K--Implementation Plans for Tribes--Region VIII
* * * * *
Federal Implementation Plan for Managing Emissions From Oil and Natural
Gas Sources on the Indian Country Lands Within the Uintah and Ouray
Indian Reservation in Utah
Sec.
49.4169 Introduction.
49.4170 Delegation of authority of administration to the tribe.
49.4171 General provisions.
49.4172 Emissions inventory.
49.4173 Nonattainment requirements for new or modified true minor
oil and natural gas sources.
49.4174 VOC emissions control requirements for storage tanks.
49.4175 VOC emissions control requirements for dehydrators.
49.4176 VOC emissions control requirements for pneumatic pumps.
49.4177 VOC emissions control requirements for covers and closed-
vent system.
49.4178 VOC emissions control devices.
49.4179 VOC emissions control requirements for fugitive emissions.
49.4180 VOC emissions control requirements for tank truck loading.
49.4181 VOC emissions control requirements for pneumatic
controllers.
49.4182 Other combustion devices.
49.4183 Monitoring requirements.
49.4184 Recordkeeping requirements.
49.4185 Notification and reporting requirements.
Sec. 49.4169 Introduction.
(a) What is the purpose of Sec. Sec. 49.4169 through 49.4185?
Sections 49.4169 through 49.4185 establish legally and practicably
enforceable requirements for oil and natural gas sources to address
ozone air quality. Section 49.4170 establishes provisions for
delegation of authority to allow the Ute Indian Tribe to assist the EPA
with administration of this proposed U&O FIP. Section 49.4171 contains
general provisions and definitions applicable to oil and natural gas
sources. Section 49.4173 establishes legally and practicably
enforceable requirements to control and reduce emissions of volatile
organic compounds (VOC), nitrogen oxides, sulfur dioxide, particulate
matter (PM, PM10 and PM2.5), hydrogen sulfide,
carbon monoxide and various sulfur compounds from new and modified true
minor oil and natural gas sources in the oil and natural gas production
and natural gas processing segments of the oil and natural gas sector
that are located on portions of the U&O Reservation that are included
in the Uinta Basin ozone nonattainment area and commence construction
on or after [30 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE
FEDERAL REGISTER], unless the source obtains a site-specific
construction permit, or is otherwise required to obtain a site-specific
permit by the Reviewing Authority, in accordance with 40 CFR 49.151
through 49.161. Sections 49.4174 through 49.4185 establish legally and
practicably enforceable requirements to control and reduce VOC
emissions from oil and natural gas well production and storage
operations, natural gas processing, and gathering and boosting
operations at oil and natural gas sources (as defined in Sec.
49.4171(b)) that are located on Indian country lands within the U&O
Reservation.
(b) Am I subject to Sec. Sec. 49.4169 through 49.4185? Sections
49.4169 through 49.4185, as appropriate, apply to each owner or
operator of an oil and natural gas source located on Indian country
lands within the U&O Reservation that has equipment or activities that
meet the applicability thresholds specified in each section. Generally,
the equipment and activities at oil and natural gas sources that are
already subject to and in compliance with VOC emission control
requirements under another EPA standard or other federally enforceable
requirement, as specified in each appropriate subsection later, are
considered to be in compliance with the requirements to control VOC
emissions from that same equipment under this proposed U&O FIP.
(c) When must I comply with Sec. Sec. 49.4169 through 49.4185?
Compliance with Sec. Sec. 49.4169 through 49.4171 and 49.4174 through
49.4185, as applicable, is required no later than [DATE 18 MONTHS AFTER
DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] for oil
and natural gas sources that commence construction before [DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER]. You may submit
a written request to the EPA for an extension of the compliance date
for existing sources that describes the specific reasons for the
requested extension. Any decision to approve or deny the request,
including the length of time of an approved request, will be based on
the determined merits of case-specific circumstances. Compliance with
Sec. Sec. 49.4169 through 49.4171 and 49.4174 through 49.4185, as
applicable, is required upon startup for oil and natural gas sources
that commence construction on or after [DATE OF PUBLICATION OF THE
FINAL RULE IN THE FEDERAL REGISTER]. Compliance with Sec. 49.4173 is
required upon commencing construction of any new and modified true
minor oil and natural gas source in the oil and natural gas production
and natural gas processing segments of the oil and natural gas sector
that is located on portions of the U&O Reservation that are included in
the Uinta Basin ozone nonattainment area that commences construction on
or after [30 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE
FEDERAL REGISTER].
Sec. 49.4170 Delegation of authority of administration to the tribe.
(a) What is the purpose of this section? The purpose of this
section is to establish the process by which the Regional Administrator
may delegate to the Ute Indian Tribe the authority to assist the EPA
with administration of this proposed U&O FIP. This section provides for
administrative delegation and does not affect the eligibility criteria
[[Page 3528]]
under 40 CFR 49.6 for treatment in the same manner as a state.
(b) How does the Ute Indian Tribe request delegation? In order to
be delegated authority to assist us with administration of this
proposed U&O FIP, the authorized representative of the Ute Indian Tribe
must submit a written request to the Regional Administrator that:
(1) Identifies the specific provisions for which delegation is
requested;
(2) Includes a statement by the Ute Indian Tribe's legal counsel
(or equivalent official) that includes the following information:
(i) A statement that the Ute Indian Tribe is an Indian tribe
recognized by the Secretary of the Interior;
(ii) A descriptive statement that meets the requirements of Sec.
49.7(a)(2) and demonstrates that the Ute Indian Tribe is currently
carrying out substantial governmental duties and powers over a defined
area;
(iii) A description of the laws of the Ute Indian Tribe that
provide adequate authority to carry out the aspects of the rule for
which delegation is requested; and
(3) Demonstrates that the Ute Indian Tribe has, or will have,
adequate resources to carry out the aspects of the rule for which
delegation is requested.
(c) How is the delegation of administration accomplished? (1) A
Delegation of Authority Agreement setting forth the terms and
conditions of the delegation and specifying the provisions of this rule
that the Ute Indian Tribe will be authorized to implement on behalf of
the EPA will be entered into by the Regional Administrator and the Ute
Indian Tribe. The Agreement will become effective upon the date that
both the Regional Administrator and the authorized representative of
the Ute Indian Tribe have signed the Agreement. Once the delegation
becomes effective, the Ute Indian Tribe will be responsible, to the
extent specified in the Agreement, for assisting us with administration
of the FIP and will act as the Regional Administrator as that term is
used in these regulations. Any Delegation of Authority Agreement will
clarify the circumstances in which the term ``Regional Administrator''
found throughout the FIP is to remain the EPA Regional Administrator
and when it is intended to refer to the ``Ute Indian Tribe,'' instead.
(2) A Delegation of Authority Agreement may be modified, amended,
or revoked, in part or in whole, by the Regional Administrator after
consultation with the Ute Indian Tribe.
(d) How will any Delegation of Authority Agreement be publicized?
The Agency will publish a notice in the Federal Register informing the
public of any Delegation of Authority Agreement with the Ute Indian
Tribe to assist us with administration of all or a portion of the FIP
and identifying such delegation in the FIP. The Agency will also
publish an announcement of the Delegation of Authority Agreement in
local newspapers.
Sec. 49.4171 General provisions.
(a) At all times, including periods of startup, shutdown, and
malfunction, each owner or operator must, to the extent practicable,
design, operate, and maintain all equipment used for hydrocarbon liquid
and gas collection, storage, processing, and handling operations
covered under Sec. Sec. 49.4171 and 49.4174 through 49.4185,
regardless of emissions rate and including associated air pollution
control equipment, in a manner that is consistent with good air
pollution control practices and that minimizes leakage of VOC emissions
to the atmosphere.
(b) Definitions. As used in Sec. Sec. 49.4169 through 49.4185, all
terms not defined herein have the meaning given them in the Act, in 40
CFR part 60, 40 CFR part 63, in the Prevention of Significant
Deterioration regulations at 40 CFR 52.21, in the Federal Minor New
Source Review Program in Indian Country at 40 CFR 49.151, or in the
Federal Implementation Plan for Managing Air Emissions from True Minor
Sources in Indian Country in the Oil and Natural Gas Production and
Natural Gas Processing Segments of the Oil and Natural Gas Sector at 40
CFR 49.102. The following terms have the specific meanings given them:
Bottom filling means the filling of a tank through an inlet at or
near the bottom of the tank designed to have the opening covered by the
liquid after the pipe normally used to withdraw liquid can no longer
withdraw any liquid.
Condensate means hydrocarbon liquid separated from produced natural
gas that condenses due to changes in temperature, pressure, or both,
and that remains liquid at standard conditions.
Crude oil means hydrocarbon liquids that are separated from well-
extracted reservoir fluids during oil and natural gas production
operations, and that are stored or injected to pipelines as a saleable
product. Condensate is not considered crude oil.
Electronically controlled automatic ignition device means an
electronic device which generates sparks across an electrode and
reaches into a combustible gas stream traveling up a flare stack or
entering an enclosed combustor, at the point of the pilot tip, equipped
with a temperature monitor that signals the device to attempt to re-
light an extinguished pilot flame.
Enclosed combustor means a thermal oxidation system with an
enclosed combustion chamber that maintains a limited constant
temperature by controlling fuel and combustion air.
Flashing losses means natural gas emissions resulting from the
presence of dissolved natural gas in the crude oil, condensate, or
produced water, which are under high pressure that occurs as the
liquids are transferred to storage tanks that are at atmospheric
pressure.
Fugitive emissions component means any component that has the
potential to emit fugitive emissions of VOC at an oil and natural gas
source, such as valves, connectors, pressure relief devices, open-ended
lines, access doors, flanges, closed-vent systems, covers, thief
hatches or other openings on a controlled storage vessel, compressors,
instruments, and meters. Devices that vent as part of normal
operations, such as natural gas-driven pneumatic controllers or natural
gas-driven pumps, are not fugitive emissions components, insofar as the
natural gas discharged from the device's vent is not considered a
fugitive emission. Emissions originating from other than the vent, such
as the thief hatch on a controlled storage vessel, would be considered
fugitive emissions.
Glycol dehydration unit process vent emissions means VOC-containing
emissions from the glycol dehydration unit regenerator or still vent
and the vent from the dehydration unit flash tank (if present).
Malfunction alarm and remote notification system means a system
connected to an electronically controlled automatic ignition device
that sends an alarm through a remote notification system to an owner or
operator's central control center, if an attempt to relight the pilot
flame is unsuccessful.
Pneumatic pump means a single diaphragm pump powered by pressurized
natural gas.
Pneumatic pump emissions means the VOC-containing emissions from
pressurized natural gas-driven pneumatic pumps.
Produced natural gas means natural gas that is separated from
extracted reservoir fluids during oil and natural gas production
operations.
Regional Administrator means the Regional Administrator of EPA
Region 8 or an authorized representative of the Regional Administrator
of EPA Region
[[Page 3529]]
8, except to the extent otherwise specifically specified in a
Delegation of Authority Agreement between the Regional Administrator
and the Ute Indian Tribe.
Standing and breathing losses means VOC emissions from fixed roof
tanks as a result of evaporative losses during storage.
Storage tank means a tank or other vessel that contains an
accumulation of crude oil, condensate, intermediate hydrocarbon
liquids, or produced water, and that is constructed primarily of non-
earthen materials (such as wood, concrete, steel, fiberglass, or
plastic), which provide structural support.
Submerged fill pipe means any fill pipe with a discharge opening
which is entirely submerged when the liquid level is six inches above
the bottom of the tank and the pipe normally used to withdraw liquid
from the tank can no longer withdraw any liquid.
Supervisory Control and Data Acquisition (SCADA) system generally
refers to industrial control computer systems that monitor and control
industrial infrastructure or source-based processes.
Unsafe to repair means (in the context of fugitive emissions
monitoring) that operator personnel would be exposed to an imminent or
potential danger as a consequence of the attempt to repair the leak
during normal operation of the source.
Utility flare means a thermal oxidation system using an open
(without enclosure) flame that is designed and operated in accordance
with the requirements of 40 CFR 60.18(b). An enclosed combustor is not
considered a utility flare. A combustion device is not considered a
utility flare when installed horizontally or vertically within an open
pit and often used in oil and natural gas operations to combust
produced natural gas during initial well completion or temporarily
during emergencies when enclosed combustors or utility flares installed
at a source are not operational or injection of recovered produced
natural gas is unavailable.
Visible smoke emissions mean air pollution generated by thermal
oxidation in a flare or enclosed combustor and occurring immediately
downstream of the flame present in those units. Visible smoke occurring
within, but not downstream of, the flame, does constitute visible smoke
emissions.
Working losses means natural gas emissions from fixed roof tanks
resulting from evaporative losses during filling and emptying
operations.
Sec. 49.4172 Emissions inventory.
(a) Applicability. The emissions inventory requirements of this
section apply to each oil and natural gas source as identified in Sec.
49.4169(b), and that has actual emissions of any pollutant identified
in paragraph (c) of this section greater than or equal to one ton in
any consecutive 12-month period.
(b) Each oil and natural gas source shall submit an inventory for
every third year, beginning with the 2017 calendar year, for all
emission units at a source.
(c) The inventory shall include the total emissions for
PM10, PM2.5, oxides of sulfur, oxides of
nitrogen, carbon monoxide and volatile organic compounds for each
emissions unit at the source. Emissions for the emissions unit at the
source shall be calculated using the emissions unit's actual operating
hours, product rates and types of materials processed, stored or
combusted during the calendar year of the reporting period.
(d) The inventory shall include the type and efficiency of any air
pollution control equipment present at the reporting source.
(e) The inventory shall be submitted to the EPA Region 8 Office no
later than April 15th of the year following each inventory year, except
that the first inventory covering calendar year 2017 shall be submitted
no later than October 1, 2018.
(f) The inventory shall be submitted in an electronic format
specific to this source category that is available on the EPA Region 8
Office website at https://www.epa.gov/air-quality-implementation-plans/approved-air-quality-implementation-plans-region-8.
Sec. 49.4173 Compliance with the National Indian Country Oil and
Natural Gas Federal Implementation Plan for New and Modified True Minor
Oil and Natural Gas Sources in the Uinta Basin Ozone Nonattainment
Area.
(a) Applicability. This section applies to each owner or operator
of a new and modified true minor source in the oil and natural
production and natural gas processing segments of the oil and natural
gas source sector that is located on portions of the U&O Reservation
that are included in the Uinta Basin ozone nonattainment area and that
commences construction on or after [30 DAYS AFTER DATE OF PUBLICATION
OF THE FINAL RULE IN THE FEDERAL REGISTER]. Owners/operators of such
sources shall comply with the requirements of the Federal
Implementation Plan for Managing Air Emissions from True Minor Sources
in Indian Country in the Oil and Natural Gas Production and Natural Gas
Processing Segments of the Oil and Natural Gas Sector at 49.101 through
49.105, as applicable, except for Sec. 49.101(b)(1)(v), and,
applicable requirements of the Federal Minor New Source Review Program
in Indian Country at 40 CFR 49.151 through 49.161.
(b) Complying with the requirements of Sec. 49.4173(a) does not
relieve the owner/operator from the obligation to comply with the
requirements of Sec. Sec. 49.4169 through 49.4171 and 49.4174 through
49.4185, as applicable.
Sec. 49.4174 VOC emissions control requirements for storage tanks.
(a) Applicability. The VOC emissions control requirements of this
section apply to each crude oil, condensate, and/or produced water
storage tank located at an oil and natural gas source as identified in
Sec. 49.4169(b) that meets the criteria in one of paragraphs (1)
through (4):
(1) At an oil and natural gas source that began operations before
[30 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL
REGISTER], the source-wide uncontrolled actual VOC emissions from all
storage tanks, glycol dehydrators, and pneumatic pumps is equal to or
greater than 4 tpy, as determined according to this section;
(2) At an oil and natural gas source that began operations on or
after [30 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE
FEDERAL REGISTER], upon startup of operation, for a minimum of 12
consecutive calendar months;
(3) At an oil and natural gas source that began operations before
[30 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL
REGISTER], with one or more storage tanks and no glycol dehydrators or
pneumatic pumps, the source-wide throughput is equal to or greater than
8,000 barrels of crude oil or 2,000 barrels of condensate in any
consecutive 12-month period; or
(4) Modification to an oil and natural gas source shall require a
re-evaluation of the source-wide VOC emissions from all storage tanks,
glycol dehydrators and pneumatic pumps or the source-wide crude oil or
condensate throughput.
(b) Exemptions. (1) This section does not apply to crude oil,
condensate, and/or produced water storage tanks located at an oil and
natural gas source that are subject to the emissions control
requirements for storage vessels in 40 CFR part 60, subparts OOOO or
OOOOa, or 40 CFR part 63, subpart HH.
(2) This section does not apply to an emergency storage tank
located at an oil
[[Page 3530]]
and natural gas source, if it meets the following requirements:
(i) The emergency storage tank is not used as an active storage
tank;
(ii) The owner or operator empties the emergency storage tank no
later than 15 days after receiving fluids; and
(iii) The emergency storage tank is equipped with a liquid level
gauge or equivalent device.
(c) VOC emission control requirements. For each storage tank, you
must comply with the VOC emissions control requirements of paragraphs
(1) or (2) of this section.
(1) You must reduce VOC emissions from each storage tank by at
least 95.0 percent on a continuous basis according to paragraphs
(c)(1)(i) or (ii) of this section. You must route all flashing,
working, standing and breathing losses from the crude oil, condensate,
and/or produced water storage tanks through a closed-vent system that
meets the conditions specified in Sec. 49.4177(d) to:
(i) An operating system designed to recover 100 percent of the
emissions and recycle them for use in a process unit or incorporate
them into a product; or
(ii) An enclosed combustor or utility flare designed to reduce the
mass content of VOC in the natural gas emissions vented to the device
by at least 95.0 percent and operated as specified in Sec. Sec.
49.4177(d) and 49.4178;
(2) You must maintain the source-wide uncontrolled actual VOC
emissions from all storage tanks, glycol dehydrators, and pneumatic
pumps at an oil and natural gas source at less than 4 tpy. Before using
the uncontrolled actual VOC emission rate for compliance purposes, you
must demonstrate that the uncontrolled actual VOC emissions have
remained at less than 4 tpy, as determined monthly for 12 consecutive
months. After such demonstration, you must determine the uncontrolled
actual VOC emission rate each month. The uncontrolled actual VOC
emissions must be calculated using a generally accepted model or
calculation methodology. Monthly calculations must be based on the
average throughput of the source for the month. Monthly calculations
must be separated by at least 14 days. You must comply with paragraph
(c)(1) of this section within 30 days of the monthly emissions
determination required in this section if the determination indicates
that VOC emissions from all storage tanks, glycol dehydrators, and
pneumatic pumps at your oil and natural gas source increased to 4 tpy
or greater.
(3) Except as provided in paragraph (c)(4) of this section, if you
use a control device to reduce emissions from your storage tanks, you
must equip each storage tank with a cover that meets the requirements
of Sec. 49.4177(c).
(4) If you use a floating roof to reduce emissions, you must meet
the requirements of Sec. 60.112b(a)(1) or (2) and the relevant
monitoring, inspection, recordkeeping, and reporting requirements in 40
CFR part 60, subpart Kb.
(5) After a minimum of 12 consecutive months of operation at a
source that begins operation on or after [30 DAYS AFTER DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER], controls may be
removed under one of the following conditions:
(i) The source-wide uncontrolled actual VOC emissions from all
storage tanks, glycol dehydrators, and pneumatic pumps has been
maintained at a rate less than 4 tpy, as determined according to this
section; or
(ii) At a source with one or more storage tanks and no glycol
dehydrators or pneumatic pumps, the source-wide throughput is less than
8,000 barrels of crude oil or 2,000 barrels of condensate.
Sec. 49.4175 VOC emissions control requirements for dehydrators.
(a) Applicability. The VOC emissions control requirements of this
section apply to each glycol dehydration unit located at an oil and
natural gas source as identified in Sec. 49.4169(b) where the source-
wide uncontrolled actual VOC emissions from all storage tanks, glycol
dehydrators, and pneumatic pumps is equal to or greater than 4 tpy, as
determined according to Sec. 49.4174. Applicability for glycol
dehydrators that began operation before [30 DAYS AFTER DATE OF
PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] shall be
determined using uncontrolled actual emissions. Applicability for
glycol dehydrators that began operation on or after [30 DAYS AFTER DATE
OF PUBLICATION OF THE FINAL RULE IN THE FEDERAL REGISTER] shall be
determined using potential to emit.
(b) Exemptions. This section does not apply to glycol dehydration
units subject to with the emissions control requirements for glycol
dehydration unit process vents in 40 CFR, part 63, subpart HH.
(c) VOC emissions control requirements. For each glycol dehydration
unit, you must comply with the VOC emissions control requirements of
paragraphs (1) or (2) of this paragraph.
(1) You must reduce VOC emissions from each glycol dehydration unit
process vent by at least 95.0 percent on a continuous basis according
to paragraphs (c)(1)(i) and (ii) of this section. You must route all
glycol dehydration unit process vent emissions through a closed-vent
system that meets the conditions specified in Sec. 49.4177(d) to:
(i) An operating system designed to recover 100 percent of the
emissions and recycle them for use in a process unit or incorporate
them into a product; or
(ii) An enclosed combustor or utility flare designed to reduce the
mass content of VOC in the emissions vented to the device by at least
95.0 percent and operated as specified in Sec. Sec. 49.4177(d) and
49.4178; or
(2) You must maintain the source-wide uncontrolled actual VOC
emissions from all storage tanks, glycol dehydrators, and pneumatic
pumps at an oil and natural gas source at less than 4 tpy for 12
consecutive months in accordance with the procedures specified in Sec.
49.4174(c)(2).
Sec. 49.4176 VOC emissions control requirements for pneumatic pumps.
(a) Applicability. The requirements of this section apply to each
pneumatic pump located at an oil and natural gas source as identified
in Sec. 49.4169(b) where the potential for source-wide uncontrolled
VOC emissions from all storage tanks, glycol dehydrators, and pneumatic
pumps is equal to or greater than 4 tpy, as determined according to
Sec. 49.4174. You must reevaluate the source-wide VOC emissions from
all storage tanks, glycol dehydrators and pneumatic pumps for each
modification to an existing source.
(b) Exemptions. This section does not apply to pneumatic pumps
subject to the emissions control requirements for pneumatic pumps in 40
CFR part 60, subpart OOOOa.
(c) VOC Emission Control Requirements. For each pneumatic pump, you
must comply with the VOC emissions control requirements of paragraph
(1) or (2) of this section.
(1) You must reduce VOC emissions from each pneumatic pump by at
least 95.0 percent on a continuous basis according to paragraph
(c)(1)(i) or (ii) of this section. You must route all pneumatic pump
emissions through a closed-vent system that meets the conditions
specified in Sec. 49.4177(d) to:
(i) An operating system designed to recover 100 percent of the
emissions and recycle them for use in a process unit or incorporate
them into a product; or
(ii) An enclosed combustor or utility flare designed to reduce the
mass
[[Page 3531]]
content of VOC in the emissions vented to the device by at least 95.0
percent and operated as specified in Sec. Sec. 49.4177(d) and 49.4178;
or
(2) You must maintain the source-wide uncontrolled actual VOC
emissions from all storage tanks, glycol dehydrators, and pneumatic
pumps at an oil and natural gas source at less than 4 tpy for any 12
consecutive months in accordance with the procedures specified in Sec.
49.4174(c)(2).
Sec. 49.4177 VOC emissions control requirements for covers and
closed-vent systems.
(a) Applicability. The VOC emissions control requirements in this
section apply to each cover on a crude oil, condensate or produced
water storage tank subject to Sec. 49.4174 and each closed-vent system
used to convey VOC emissions from storage tanks, glycol dehydration
units and pneumatic pumps (to a vapor recovery system or control
device) that are subject to Sec. Sec. 49.4174 through 49.4176.
(b) Exemptions. This section does not apply to covers and closed-
vent systems subject to the requirements for covers and closed-vent
systems in 40 CFR part 60, subparts OOOO or OOOOa, or 40 CFR part 63,
subpart HH.
(c) Covers. Each owner or operator must equip all openings on each
crude oil, condensate, and/or produced water storage tank with a cover
to ensure that all flashing, working, standing and breathing emissions
are routed through a closed-vent system to a vapor recovery system, an
enclosed combustor, or a utility flare.
(1) Each cover and all openings on the cover (e.g., access hatches,
sampling ports, pressure relief valves (PRV), and gauge wells) must
form a continuous impermeable barrier over the entire surface area of
the crude oil, condensate, and/or produced water in the storage tank.
(2) Each cover opening must be secured in a closed, sealed position
(e.g., covered by a gasketed lid or cap) whenever material is in the
unit on which the cover is installed except when it is necessary to use
an opening as follows:
(i) To add fluids to, or remove fluids from the unit (this includes
openings necessary to equalize or balance the internal pressure of the
unit following changes in the level of the material in the unit);
(ii) To inspect or sample the fluids in the unit; or
(iii) To inspect, maintain, repair, or replace equipment located
inside the unit.
(3) Each thief hatch cover must be weighted and properly seated to
ensure that flashing, working, standing and breathing emissions are
routed through the closed-vent system to the vapor recovery system, the
enclosed combustor, or the utility flare under normal operating
conditions.
(4) Each PRV must be set to release at a pressure that will ensure
that flashing, working, standing and breathing emissions are routed
through the closed-vent system to the vapor recovery system, the
enclosed combustor, or the utility flare under normal operating
conditions.
(d) Closed-vent systems. Each owner or operator must meet the
following requirements for closed-vent systems:
(1) Each closed-vent system must route all captured storage tank
flashing, working, standing and breathing losses, glycol dehydration
unit process vent emissions, and pneumatic pump emissions from the oil
and natural gas source to a gathering pipeline system for sale, use in
a process unit, incorporation into a product, or other beneficial
purpose, or to a VOC emission control device, as specified in
Sec. Sec. 49.4174 through 49.4176.
(2) All vent lines, connections, fittings, valves, relief valves,
or any other appurtenance employed to contain and collect captured
storage tank flashing, working, standing and breathing losses, glycol
dehydration unit process vent emissions, and pneumatic pump emissions
to transport such emissions to a gathering pipeline system for sale,
use in a process unit, incorporation into a product, or other
beneficial purpose, or to a VOC emission control device, as specified
in Sec. Sec. 49.4174 through 49.4176, must be maintained and operated
properly at all times.
(3) Each closed-vent system must be designed to operate with no
detectable emissions, as demonstrated by the fugitive emissions
component monitoring requirements in Sec. 49.4179(c).
(4) If any closed-vent system contains one or more bypass devices
that could be used to divert all or a portion of the captured storage
tank flashing, working, standing and breathing losses, glycol
dehydration unit process vent emissions, and pneumatic pump emissions,
from entering a gathering pipeline system for sale, use in a process
unit, incorporation into a product, or other beneficial purpose, or
from being transferred to the VOC emissions control device, the owner
or operator must meet one of the requirements in paragraphs (i) or (ii)
for each bypass device. Low leg drains, high point bleeds, analyzer
vents, open-ended valves or lines, and safety devices are not subject
to the requirements applicable to bypass devices:
(i) At the inlet to such a bypass device the owner or operator must
properly install, calibrate, maintain, and operate a flow indicator
that is capable of taking continuous readings and sounding an alarm
when the bypass device is open such that emissions are being, or could
be, diverted away from a gathering pipeline system for sale, use in a
process unit, incorporation into a product, or other beneficial
purpose, or the VOC emission control device and into the atmosphere; or
(ii) The owner or operator must secure the bypass device valve
installed at the inlet to the bypass device in the non-diverting
position using a car-seal or a lock-and-key type configuration.
Sec. 49.4178 VOC emissions control devices.
(a) Applicability. The requirements in this section apply to all
utility flares and enclosed combustors used to control VOC emissions at
an oil and natural gas source as identified in Sec. 49.4169(b) in
order to meet the requirements specified in Sec. Sec. 49.4174 through
49.4177, as applicable.
(b) Exemptions. This section does not apply to VOC emission control
devices subject to the requirements for control devices used to comply
with the emissions standards in 40 CFR part 60, subparts OOOO or OOOOa;
or 40 CFR part 63, subpart HH.
(c) Enclosed combustors and utility flares. Each owner or operator
must meet the following requirements for enclosed combustors and
utility flares:
(1) For each enclosed combustor or utility flare, the owner or
operator must follow the manufacturer's written operating instructions,
procedures and maintenance schedule to ensure good air pollution
control practices for minimizing emissions;
(2) The owner or operator must ensure that each enclosed combustor
or utility flare is designed to have sufficient capacity to reduce the
mass content of VOC in the captured emissions routed to it by at least
95.0 percent for the minimum and maximum natural gas volumetric flow
rate and BTU content routed to the device;
(3) Each enclosed combustor or utility flare must be operated to
reduce the mass content of VOC in the captured emissions routed to it
by continuously meeting at least 95.0 percent VOC control efficiency;
(4) The owner or operator must ensure that each utility flare is
designed and operated in accordance with the
[[Page 3532]]
requirements of 40 CFR 60.18(b) for such flares;
(5) The owner or operator must ensure that each enclosed combustor
is:
(i) A model demonstrated by a manufacturer to meet the VOC control
efficiency requirements of Sec. Sec. 49.4174 through 49.4177 using the
EPA-approved performance test procedures specified in 40 CFR 60.5413 by
the due date of the first annual report as specified in Sec.
49.4185(b); and
(ii) Demonstrated by the owner or operator to meet the VOC control
efficiency requirements of Sec. Sec. 49.4174 through 49.4177 using the
EPA-approved performance test procedures specified in 40 CFR 60.5413 by
the due date of the first annual report as specified in Sec.
49.4183(b); and
(6) The owner or operator must ensure that each enclosed combustor
and utility flare is:
(i) Operated properly at all times that captured emissions are
routed to it;
(ii) Operated with a liquid knock-out system to collect any
condensable vapors (to prevent liquids from going through the control
device);
(iii) Equipped and operated with a flash-back flame arrestor;
(iv) Equipped and operated with one of the following:
(A) A continuous burning pilot; or
(B) An operational electronically controlled automatic ignition
device;
(v) Equipped with a monitoring system for continuous measuring and
recording of the parameters that indicate proper operation of each
continuous burning pilot flame or electronically controlled automatic
ignition device (such as a chart recorder, data logger or similar
device), or connected to a SCADA system, to monitor and document proper
operation of the enclosed combustor or utility flare;
(vi) Maintained in a leak-free condition; and
(vii) Operated with no visible smoke emissions.
Sec. 49.4179 Fugitive emissions VOC emissions control requirements.
(a) Applicability. The requirements of this section apply to all
owners or operators of the collection of fugitive emissions components,
as defined in Sec. 49.4171, at an oil and natural gas source, as
identified in Sec. 49.4169(b), that is required to control VOC
emissions according to Sec. Sec. 49.4174 through 49.4178.
(b) Exemptions. This section does not apply to owners or operators
of the collection of fugitive emission components, as defined in 40 CFR
60.5430a, at an oil and natural gas source subject to the fugitive
emissions monitoring requirements in 40 CFR part 60, subpart OOOOa.
(c) Monitoring requirements. (1) Each owner or operator must
develop and implement a fugitive emissions monitoring plan to reduce
emissions from fugitive emissions components at all of their oil and
natural gas sources on Indian country lands within the U&O Reservation.
This Reservation-wide monitoring plan must include the following
elements:
(i) A requirement to perform an initial monitoring of the
collection of fugitive emissions components at each oil and natural gas
source by [DATE 18 MONTHS AFTER DATE OF PUBLICATION OF THE FINAL RULE
IN THE FEDERAL REGISTER];
(ii) A requirement to perform subsequent monitoring of the
collection of fugitive emissions components at each oil and natural gas
source once every 6 months after the initial monitoring survey, with
consecutive monitoring surveys conducted at least five months apart.
(iii) A description of the technique used to identify leaking
fugitive emission components, which must be limited to:
(A) Onsite EPA Reference Method 21, 40 CFR part 60, appendix A,
where an analyzer reading of 500 parts per million volume (ppmv) VOC or
greater is considered a leak in need of repair;
(B) Onsite optical gas imaging instruments, as defined in 40 CFR
60.18(g)(4), where any visible emissions are considered a leak in need
of repair, unless the owner or operator evaluates the leak with an
analyzer meeting EPA Reference Method 21 at 40 CFR part 60, appendix A
and the concentration is less than 500 ppmv. The optical gas imaging
instrument must be capable of meeting the optical gas imaging equipment
requirements specified in 40 CFR part 60, subpart OOOOa; or
(C) Another method approved by the Administrator other than EPA
Reference Method 21 or optical gas imaging instruments to demonstrate
compliance with the fugitive emissions monitoring requirements.
(iv) The manufacturer and model number of any fugitive emissions
monitoring device to be used;
(v) Procedures and timeframes for identifying and repairing
components from which leaks are detected, including:
(A) A requirement to repair any leaks identified from components
that are safe to repair and do not require source shutdown as soon as
practicable, but no later than 30 calendar days after discovering the
leak;
(B) Timeframes for repairing leaking components that are unsafe to
repair or require source shutdown, to be no later than the next
required monitoring event; and
(C) Procedures for verifying leaking component repairs, no more
than 30 calendar days after repairing the leak;
(vi) Training and experience needed before performing surveys;
(vii) Procedures for calibration and maintenance of any fugitive
emissions monitoring device to be used; and
(viii) Standard monitoring protocols for each type of typical oil
and natural gas source (e.g., well site, tank battery, compressor
station), including a general list of component types that will be
inspected and what supporting data will be recorded (e.g., wind speed,
detection method device-specific operational parameters, date, time,
and duration of inspection).
(2) The owner or operator is exempt from inspecting a valve,
flange, or other connection, pump or compressor, pressure relief
device, process drain, open-ended valve, pump or compressor seal system
degassing vent, accumulator vessel vent, agitator seal, or access door
seal under any of the following circumstances:
(i) The contacting process stream only contains glycol, amine,
methanol, or produced water;
(ii) If using Method 21, the monitoring could not occur without
elevating the monitoring personnel to an immediate danger as a
consequence of completing monitoring;
(iii) Monitoring could not occur without exposing monitoring
personnel to an immediate danger as a consequence of completing
monitoring; or
(iv) The item to be inspected is buried, insulated in a manner that
prevents access to the components by a monitor probe or optical gas
imaging device, or obstructed by equipment or piping that prevents
access to the components by a monitor probe or optical gas imaging
device.
Sec. 49.4180 Tank truck loading VOC emissions control requirements.
(a) Applicability. The requirements in this section apply to each
owner or operator who loads or permits the loading of any intermediate
hydrocarbon liquid or produced water at an oil and natural gas source
as identified in Sec. 49.4169(b).
(b) Tank truck loading requirements. Tank trucks used for
transporting intermediate hydrocarbon liquid or produced water must be
loaded using bottom filling or a submerged fill pipe, as defined in
Sec. 49.4171(b).
[[Page 3533]]
Sec. 49.4181 VOC emissions control requirements for pneumatic
controllers.
(a) Applicability. The VOC emissions control requirements in this
section apply to each owner or operator of any existing pneumatic
controller located at an oil and natural gas source as identified in
Sec. 49.4169(b).
(b) Exemptions. This section does not apply to pneumatic
controllers subject to and controlled in accordance with the
requirements for pneumatic controllers in 40 CFR part 60, subparts OOOO
or OOOOa.
(c) Retrofit requirements. All existing pneumatic controllers must
meet the standards established for pneumatic controllers that are
constructed, modified, or reconstructed on or after October 15, 2013,
as specified in 40 CFR part 60, subpart OOOO Standards of Performance
for Crude Oil and Natural Gas Production, Transmission and
Distribution.
(d) Documentation requirements. The owner or operator of any
existing pneumatic controllers must meet the tagging requirements in 40
CFR 60.5390(b)(2) and (c)(2) and 40 CFR 60.5390a(b)(2) and (c)(2),
except that the month and year of installation, reconstruction or
modification is not required.
Sec. 49.4182 Other combustion devices.
(a) Applicability. The VOC emission control requirements in this
section apply to each owner or operator of any existing enclosed
combustor, utility flare, or other flare located at an oil and natural
gas source as identified in Sec. 49.4169(b) that is used to control
VOC emissions, but is not required under Sec. Sec. 49.4174 through
49.4176, and 49.4178 of this rule.
(b) Retrofit requirements. All existing enclosed combustors,
utility flares, or other open flares must be equipped with an
operational electronically controlled automatic ignition device.
Sec. 49.4183 Monitoring requirements.
(a) Applicability. The monitoring requirements in paragraphs (c)
through (e) of this section apply, as appropriate, to each oil and
natural gas source as identified in Sec. 49.4169(b) with equipment or
activities that are subject to Sec. Sec. 49.4174 through 49.4178.
(b) Exemptions. Paragraphs (c) through (e) do not apply to any
crude oil, condensate, or produced water storage tanks, glycol
dehydration units, pneumatic pumps, covers, closed-vent systems or VOC
emission control devices subject to and monitored in accordance with
the monitoring requirements for such equipment and activities in 40 CFR
part 60, subparts OOOO or OOOOa, or 40 CFR part 63, subpart HH.
(c) Each owner or operator must inspect at least once every
calendar month each closed-vent system, including storage tank
openings, thief hatches, and bypass devices, for defects that can
result in air emissions according to the procedures in 40 CFR
60.5416(c).
Any defects identified must be corrected or repaired within 15 days
of identification.
(d) Each owner or operator must perform auditory, visual, and
olfactory (AVO) inspections at least once every calendar month of each
VOC emissions control device, tank thief hatch, cover, seal, pressure
relief valve, and closed-vent system to ensure proper condition and
functioning of the equipment. The monthly inspections must be performed
while the crude oil, condensate, and produced water storage tanks are
being filled. If any of the components are not in good working
condition, they must be repaired within 15 days of identification of
the deficient condition.
(e) Each owner or operator must monitor the operation of each
enclosed combustor and utility flare to confirm proper operation and
demonstrate compliance with the requirements of Sec. 49.4178(c)(6)(iv)
and (v), as follows:
(1) Check the system for proper operation whenever an operator is
on site, at least once per calendar month; and
(2) Respond to any indication of pilot flame failure and ensure
that the pilot flame is relit as soon as practically and safely
possible after discovery.;
(3) Demonstrate compliance with the requirements of Sec.
49.4178(c)(6)(vii), that each enclosed combustor is operated with no
visible smoke emissions, by complying with the requirements in 40 CFR
60.5412(d)(i) through (iii).
(f) Where sufficient to meet the monitoring requirements in this
section, the owner or operator may use a SCADA system to monitor and
record the required data in paragraphs (c) through (d).
Sec. 49.4184 Recordkeeping requirements.
(a) Each owner or operator of an oil and natural gas source as
identified in Sec. 49.4169(b) must maintain the following records, as
applicable:
(1) For each oil and natural gas source as identified in Sec.
49.4169(b):
(i) As applicable, the monthly calculations, as specified in Sec.
49.4174(c)(2), demonstrating that the uncontrolled actual VOC emissions
from all storage tanks, glycol dehydrators, and pneumatic pumps at an
oil and natural gas source, as identified in Sec. 49.4169(b), has been
maintained at less than 4 tpy;
(ii) As applicable, records of monthly and rolling 12-month crude
oil or condensate throughput;
(iii) For each enclosed combustor or utility flare at an oil and
natural gas source required under Sec. Sec. 49.4174 through 49.4178:
(A) Manufacturer-written, site-specific designs, operating
instructions, operating procedures and maintenance schedules, including
those of any operation monitoring systems;
(B) Date of installation;
(C) Records of all required monitoring of operations in Sec.
49.4183;
(D) Records of any instances in which the pilot flame is not
present or the monitoring equipment is not functioning in the enclosed
combustor or utility flare, the date and times of the occurrence, the
corrective actions taken, and any preventative measures adopted to
prevent recurrence of the occurrence; and
(E) Records of any time periods in which visible smoke emissions
are observed emanating from the enclosed combustor or utility flare.
(iv) For each closed-vent system:
(A) The date of installation; and
(B) Records of any instances in which any closed-vent system or
control device was bypassed or down, the reason for each incident, its
duration, and the corrective actions taken, and any preventative
measures adopted to avoid such bypasses or downtimes; and
(v) Documentation of all storage tank and closed-vent system
inspections required in Sec. 49.4183(d) and (e) All inspection records
must include the following information:
(A) The date of the inspection;
(B) The findings of the inspection;
(C) Any adjustments or repairs made as a result of the inspection,
and the date of the adjustment or repair; and
(D) The inspector's name and signature;
(vi) The Uinta Basin-wide fugitive emissions monitoring plan for
the U&O Reservation; and
(vii) Documentation of each fugitive emissions inspection at all
oil and natural gas sources. All inspection records must include the
following information:
(A) The date of the inspection;
(B) The identification of any component that was determined to be
leaking;
(C) The identification of any component not exempt under Sec.
49.4179(b)(2) that is not inspected and the reason it was not
inspected;
(D) The date of the first attempt to repair the leaking component;
[[Page 3534]]
(E) The identification of any component with a delayed repair and
the reason for the delayed repair:
(1) For unavailable parts:
(i) The date of ordering a replacement component; and
(ii) The date the replacement component was received; and
(2) For a shutdown:
(i) The reason the repair is technically infeasible;
(ii) The date of the shutdown;
(iii) The date of subsequent startup after a shutdown; and
(iv) Emission estimates of the shutdown and the repair if the delay
is longer than 6 months;
(F) The date and description of any corrective action taken,
including the date the component was verified to no longer be leaking;
(G) The identification of each component exempt under Sec.
49.4179(b)(2), including the type of component and a description of the
qualifying exemption; and
(H) The inspector's name and signature.
(2) For each oil and natural gas source as identified in Sec.
49.4169(b):
(i) For each electronically controlled automatic ignition system
required under Sec. 49.4182, records demonstrating the date of
installation and manufacturer specifications; and
(ii) For each retrofitted pneumatic controller, the records
required in 40 CFR 60.5420(c)(4)(i).
(b) Each owner or operator must keep all records required by this
section onsite at the source or at the location that has day-to-day
operational control over the source and must make the records available
to the EPA upon request.
(c) Each owner or operator must retain all records required by this
section for a period of at least five years from the date the record
was created.
Sec. 49.4185 Notification and reporting requirements.
(a) Each owner or operator must submit any documents required under
this rule to: U.S. EPA Region 8, Enforcement and Compliance Assurance
Division, Air Toxics and Enforcement Branch, 8ENF-AT, 1595 Wynkoop St.,
Denver, CO 80202, or documents may be submitted electronically to
[email protected].
(b) Each owner and operator must submit an annual report containing
the information specified in paragraphs (b)(1) through (3) of this
section. The annual report must cover the period for the previous
calendar year. The initial annual report is due within fifteen months
of [DATE 30 DAYS AFTER DATE OF PUBLICATION OF THE FINAL RULE IN THE
FEDERAL REGISTER]. Subsequent annual reports are due on the same date
each year as the date the initial annual report was submitted. If you
own or operate more than one oil and natural gas source, you may submit
one report for multiple oil and natural gas sources provided the report
contains all of the information required as specified in paragraphs
(b)(1) through (3) of this section. Annual reports may coincide with
title V reports as long as all the required elements of the annual
report are included. An alternative schedule on which the annual must
be submitted will be allowed as long as the schedule does not extend
the reporting period. The annual report must include:
(1) The owner or operator name, and the name and location (decimal
degree latitude and longitude location indicating the datum used in
parentheses) of each oil and natural gas source being included in the
annual report.
(2) The beginning and ending dates of the reporting period.
(3) For each oil and natural gas source a summary of all required
records specified in Sec. 49.4183 as they relate to the source's
compliance with the requirements of Sec. Sec. 49.4174 through 49.4183.
[FR Doc. 2019-27431 Filed 1-17-20; 8:45 am]
BILLING CODE 6560-50-P