[Federal Register Volume 87, Number 235 (Thursday, December 8, 2022)]
[Rules and Regulations]
[Pages 75334-75386]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-24677]
[[Page 75333]]
Vol. 87
Thursday,
No. 235
December 8, 2022
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; Final Rule
Federal Register / Vol. 87, No. 235 / Thursday, December 8, 2022 /
Rules and Regulations
[[Page 75334]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 49
[EPA-R08-OAR-2015-0709; FRL-5872.1-01-R8]
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: Final rule.
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SUMMARY: The Environmental Protection Agency (EPA) is promulgating a
Federal Implementation Plan (FIP) under the Clean Air Act (CAA) and the
EPA's implementing regulations that consists of emissions control
requirements for existing, new, and modified oil and natural gas
sources 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. This U&O FIP establishes volatile organic compound
(VOC) emissions control requirements for oil and natural gas production
and processing on Indian country lands within the U&O Reservation.
These requirements are consistent with those in place in areas within
the Basin where the EPA has approved Utah to implement the CAA, and
will help ensure that new development of oil and natural gas sources in
the Basin will not interfere with attainment of the ozone National
Ambient Air Quality Standard (NAAQS). VOC emissions control
requirements for existing oil and natural gas sources have already been
established in areas within the Basin where the EPA has approved Utah
to implement the CAA, but did not exist for most sources on Indian
country lands within the U&O Reservation. Additionally, this U&O FIP
helps demonstrate that new development on Indian country lands within
the U&O Reservation will not necessarily cause or contribute to an
ozone NAAQS violation.
DATES: This final rule is effective on February 6, 2023.
ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-R08-OAR-2015-0709. All documents in the docket are
listed on the www.regulations.gov website. In some instances, we
reference documents from the dockets for other rulemakings. For this
final rule, we have included by reference Docket ID No. EPA-HQ-OAR-
2010-0505, Docket ID No. EPA-R08-OAR-2012-0479, Docket ID No. EPA-HQ-
OAR-2003-0076, and Docket ID No. EPA-HQ-OAR-2014-0606 into Docket ID
No. 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 through http://www.regulations.gov, or please contact the person identified in the FOR
FURTHER INFORMATION CONTACT section for additional availability
information.
FOR FURTHER INFORMATION CONTACT: Ms. Claudia Smith, U.S. EPA, Region 8,
Air and Radiation Division, Mail Code 8ARD-IO, 1595 Wynkoop Street,
Denver, Colorado 80202-1129, telephone number: (303) 312-6520, email
address: [email protected].
SUPPLEMENTARY INFORMATION:
Definitions
Act or CAA: Clean Air Act, unless the context indicates
otherwise.
AVO: Audio, Visual and Olfactory.
BTU: British Thermal Unit.
CBI: Confidential Business Information.
CEDRI: Compliance Emissions Data Reporting Interface.
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.
NAAQS: National Ambient Air Quality Standards.
NAICS: North American Industry Classification System.
NESHAP: National Emission Standards for Hazardous Air
Pollutants.
NOx: nitrogen oxides.
NO2: nitrogen dioxide.
NSPS: New Source Performance Standards.
NSR: New Source Review.
PM: particulate matter.
PSD: Prevention of Significant Deterioration.
PTE: potential to emit.
RIA: Regulatory Impact Analysis.
SCADA: Supervisory Control and Data Acquisition.
SIP: State Implementation Plan.
SO2: sulfur dioxide.
TAR: Tribal Authority Rule.
TAS: treatment in a similar manner as a state.
TIP: Tribal Implementation Plan.
tpy: ton(s) per year
UDEQ: Utah Department of Environmental Quality.
U&O Reservation or the Reservation: The Uintah & Ouray Indian
Reservation.
VOC: volatile organic compound(s).
VRU: vapor recovery unit.
Organization of this document. The information presented in this
preamble is organized as follows:
I. Executive Summary
A. Purpose of, and Agency Authority for, the Regulatory Action
B. Summary of the Major Provisions of This Final Rule
C. Costs and Benefits
II. General Information
A. Does this action apply to me?
B. Where can I get a copy of this document and related
information?
C. Judicial Review
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 Industry in Uinta Basin
IV. Summary of the Final U&O FIP
A. Overview
B. Introduction
C. Provisions for Delegation of Administration to the Ute Indian
Tribe
D. General Provisions
E. Emissions Inventory Requirements
F. VOC Emissions Control Requirements
G. Monitoring and Testing Requirements
H. Recordkeeping Requirements
I. Notification and Reporting Requirements
V. Significant Changes Since Proposal
A. Final Rule Effective Date and Compliance Deadline
B. Triennial Emissions Inventory
C. Streamlined Construction Authorization
D. Applicability
E. Monitoring and Testing
F. Recordkeeping and Reporting
VI. Summary of Significant Comments and Responses
A. Major Comments Concerning Effective Date and Compliance
Deadline
B. Major Comments Concerning Regulatory Authority for Minor
Source Streamlined Construction Authorization
C. Major Comments Concerning Rule Applicability
D. Major Comments Concerning Monitoring and Testing Requirements
E. Major Comments Concerning Recordkeeping and Reporting
F. Major Comments Concerning Cost-Benefit Analysis
G. Other Comments of Significant Interest
VII. Impacts of This Final FIP
A. Air Emissions Impacts
B. Energy Impacts
C. Compliance Costs
D. Economic and Employment Impacts
E. Benefits
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
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E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act (NTTAA)
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act (CRA)
I. Executive Summary
A. Purpose of, and Agency Authority for, the Regulatory Action
We are finalizing this action using our 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 Indian country lands within the U&O Reservation and in nearby
communities. The purpose of this U&O FIP is threefold.
First, and primarily, this U&O FIP will improve air quality on the
U&O Reservation by addressing emissions from oil and natural gas
production and natural gas processing activities on Indian country
lands that contribute to the winter ozone problem in the physiographic
region known as the Uinta Basin,\1\ within which the U&O Reservation is
located, and where ambient ozone levels have exceeded both the 2008 and
the 2015 ozone NAAQS.\2\ In 2018, the EPA designated portions of the
Uinta Basin, including large portions of the Indian country lands
within the U&O Reservation, as a Marginal nonattainment area for the
2015 ozone NAAQS.\3\
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\1\ For 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
Mar. 11, 2022.
\2\ 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 Mar. 11, 2022.
\3\ On April 30, 2018, the EPA designated all of the Uinta Basin
below a contiguous external perimeter of 6,250 ft. in elevation as a
Marginal nonattainment area under the 2015 ozone NAAQS (83 FR
25776). This includes areas of the Basin where the EPA has approved
the UDEQ to implement the CAA and Indian country lands within the
U&O Reservation (where the EPA is promulgating this FIP). For more
information, see https://www.epa.gov/ozone-designations/additional-designations-2015-ozone-standards, accessed Mar. 11, 2022.
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Air quality ozone monitoring data from the Uinta Basin in the years
2018, 2019 and 2020 indicates that the three-year average of the fourth
maximum ambient air concentration measurements is 76 ppb, which
violates the 2015 ozone NAAQS of 70 ppb. On April 13, 2022, the EPA
proposed to grant a 1-year attainment date extension for the Uinta
Basin Ozone Nonattainment area.\4\ The proposal explains that
preliminary 2021 ozone monitoring data indicate that the area may not
attain the 2015 ozone NAAQS by the proposed extended attainment date of
August 3, 2022, but that the area could meet the air quality criteria
for a second 1-year extension. The Uinta Basin area's preliminary 2019-
2021 design value was 78 ppb and the preliminary 2021 fourth highest
daily maximum 8-hour concentration value was 72 ppb. To qualify for a
second 1-year extension, an area's fourth highest daily maximum 8-hour
value, averaged over both the original attainment year and the first
extension year, must be 70 ppb or less. If the preliminary 2021 ozone
data are certified, then the fourth highest daily maximum 8-hour value,
averaged over 2020 and 2021, would be 69 ppb.\5\
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\4\ See 87 FR 21842 (Apr. 13, 2022), available at https://www.govinfo.gov/content/pkg/FR-2022-04-13/pdf/2022-07513.pdf,
accessed Apr. 29, 2022.
\5\ Additional details on the proposed extension of the
attainment date are discussed in Section III.D. of this preamble.
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The winter-time ozone formation in the Uinta Basin 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 oil and natural gas facilities. As explained in section III.D.
(Air Quality and Attainment Status), most available information
indicates that winter ozone formation in the Basin is driven by local
emissions and is sensitive to changes in VOC emissions. There is
greater uncertainty as to the sensitivity to changes in NOX
emissions. As explained in section III.E. (Emissions Information),
available information indicates that 97 percent of anthropogenic VOC
emissions in the Basin are from existing oil and natural gas activity,
and that about 89 percent of those emissions are from existing sources
on the Indian country lands within the U&O Reservation and in the
nonattainment area. Before this rulemaking, VOC emissions control
requirements for existing oil and natural gas sources existed in areas
of the Basin where the EPA has approved the UDEQ to implement the CAA
but did not exist in Indian country lands within the U&O Reservation.
As explained in this final rulemaking and in the supporting information
in the record, VOC control requirements are necessary to protect air
quality on Indian country lands within the U&O Reservation.
The CAA does not require an attainment plan for Marginal ozone
nonattainment areas.\6\ Accordingly, this U&O FIP is not intended to
bring the Uinta Basin back into attainment with the ozone standard.
However, we do anticipate that this U&O FIP will make a meaningful
improvement in air quality through the reduction of VOC, an ozone
precursor, while also allowing continued construction authorization of
new development in the Basin and the positive economic impact that this
development brings to the Tribe.
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\6\ On March 9, 2018 (83 FR 10376), the EPA published the
Classifications Rule, which established how the statutory
classifications apply for the 2015 ozone NAAQS, including the air
quality thresholds for each classification category. Based on this
rule, each area with a 3-year design value of 71 ppb to 81 ppb,
based on monitoring data from 2014-2016, was to be classified as a
Marginal nonattainment area. The requirements for Marginal ozone
nonattainment areas are specified in CAA Title I, Part D, subpart 2
(see 42 U.S.C. 7511a(a)) and 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 final action is driven by the EPA's authority and
responsibility to protect air quality in Indian country under sections
301(a) and 301(d)(4) of the CAA and 40 CFR 49.11. Regarding
preconstruction review of proposed new or modified sources \7\ of air
pollution in nonattainment areas in Indian country, the reviewing
authority must demonstrate that the minor source or modification would
not cause or contribute to a NAAQS violation in the nonattainment area
(see 40 CFR 49.155(a)(7)(ii)) \8\ and that preconstruction review of
new major stationary sources and major
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modifications to existing major stationary sources located in an area
designated as nonattainment for any NAAQS 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 of this U&O FIP
will result in VOC emission reductions from existing sources,\9\
thereby improving air quality, and will 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.
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\7\ 40 CFR 49.152 defines ``minor modification at a major
source,'' ``minor source,'' ``modification,'' ``synthetic minor
source,'' and ``true minor source,'' all of which are subject to the
permitting requirements of the Federal Minor New Source Review
Program in Indian Country, at 40 CFR 49.151-49.165.
\8\ 40 CFR 49.155 applies to your permit if you are subject to
this program under 40 CFR 49.153(a) for construction of a new minor
source, synthetic minor source or a modification at an existing
source.
\9\ Existing sources are sources that commence construction
before the effective date of this FIP, per 40 CFR 49.4169(c).
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This U&O FIP focuses on VOC emission reductions because
improvements in winter ozone levels in the Basin are most likely to
come from VOC emissions reductions from existing oil and natural gas
sources.\10\ Further, after a careful analysis of initial emissions
data provided by industry and later updated using information obtained
from two studies in the 2017 Uinta Basin Oil and Gas Emissions
Inventory Update (referred to herein as the UBEI2017-Update),\11\ we
determined that most of the existing oil and natural gas sources on the
Indian country lands within the U&O Reservation are largely
uncontrolled for VOC and other emissions. Therefore, in developing this
rule, we concentrated on determining the most effective control
requirements to reduce VOC emissions from oil and natural gas sources
to address the winter ozone exceedances. This is not to say that
reductions in NOX would not be beneficial in winter months.
The EPA may decide to focus on NOX reductions in future
rulemakings if additional action is required to address air quality
impacts from ozone pollution in the Basin.
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\10\ See Uinta Basin Ozone Studies (field studies conducted in
the Basin from 2011 to 2014), available at https://deq.utah.gov/air-quality/uinta-basin-ozone-studies-ubos, accessed Mar. 11, 2022. 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).
\11\ 2017 Uinta Basin Oil and Natural Gas Emissions Inventory
Update (UBEI2017-Update). The inventory and supporting analysis can
be viewed in the docket for this rule, Microsoft Excel spreadsheet
titled, ``UO FIP cost and emissions analysis.xlsx'' (Docket ID No.
EPA-R08-OAR-2015-0709). The inventory covers sources in Uintah and
Duchesne Counties. The UDEQ submitted an earlier version of the 2017
inventory to the 2017 NEI and plans to submit the updated emissions
at a future date. The UDEQ, the EPA, and the Ute Indian Tribe
updated storage vessel, pneumatic controller, pneumatic pump,
fugitive, gas well liquid unloading, blowdowns and pigging and
oilfield wastewater emissions using updated emissions factors
obtained from the Uinta Basin Composition Study and the acquisition
of about 200 of oilfield wastewater (produced water) samples. The
studies that updated the emissions factors are described in two
White Papers available in the docket, ``UINTA BASIN VOC COMPOSITION
STUDY IMPACTS ON THE 2017 OIL AND GAS EMISSIONS INVENTORY November
2020--Revised March 2021--White Paper'' (``DAQ-2021-004302.pdf''),
and ``PRODUCED WATER DISPOSAL FACILITY EMISSION FACTORS & THEIR
IMPACT ON THE 2017 OIL AND GAS EMISSIONS INVENTORY November 2020--
Revised April 2021--White Paper'' (``DAQ-2020-016022.pdf'').
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Second, the control requirements being finalized are intended to be
the same as or consistent with the requirements applicable to similar
sources in areas of the Basin where the EPA has approved the UDEQ to
implement the CAA, to promote a more consistent regulatory environment
across the Basin. Where we are regulating existing equipment or
activities that are also covered by EPA standards for the oil and
natural gas source category, but do not meet the applicability criteria
of those standards, we also strove for consistency with those EPA
standards.
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 Indian country lands within the U&O Reservation,
as well as registrations of new and modified true minor oil and natural
gas sources on Indian country lands within the U&O Reservation under
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 (codified at 40
CFR part 49, subpart C, 40 CFR 49.101-49.105) \13\ (National O&NG FIP).
In addition to providing a streamlined construction authorization
mechanism to new and modified true minor oil and natural gas
sources,\14\ the National O&NG FIP requires compliance with a suite of
eight federal oil and natural gas source category emissions standards
\15\ for new and modified sources, as applicable. In 2019, the EPA
extended the National O&NG FIP's streamlined construction authorization
mechanism for true minor oil and natural gas sources in Indian country
to the portions of the U&O Reservation within the Uinta Basin ozone
nonattainment area.\16\ We are relying on the existing source VOC
emissions reductions that will be achieved under this U&O FIP to ensure
that the limited extension of the National O&NG FIP to the Indian
country portion of the Uinta Basin Ozone Nonattainment Area will not
harm the area's ability to attain the NAAQS. This is described in
greater detail in Sections V.C. and VI.B.
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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 35944 (June 3, 2016); docket No. EPA-
HQ-OAR-2014-0606, available at https://www.regulations.gov, accessed
Mar. 11, 2022.
\14\ 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 40 CFR
49.167 (federal preconstruction permit program for major sources in
nonattainment areas in Indian country) or 40 CFR 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 40 CFR 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.
\15\ 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.
\16\ 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 https://www.regulations.gov, accessed Mar. 11, 2022.
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In the preamble to the final National O&NG FIP published on June 3,
2016, the EPA stated 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, not
through the National O&NG FIP. Further, we stated that such FIPs may
need to include requirements for existing, new, and modified sources
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beyond those in the National O&NG FIP.\17\ Consistent with that
approach, new and modified true minor oil and natural gas sources on
Indian country lands within the U&O Reservation that would use the
National O&NG FIP for construction authorization may have to comply
with additional requirements for certain equipment or activities not
covered by the eight federal standards.\18\
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\17\ See 81 FR 35964, 35968.
\18\ As described in detail later, this action exempts certain
equipment and activities that are subject to the emissions control
requirements of a subset of the eight federal standards in the
National O&NG FIP from having to comply with the emissions control
requirements in this action for the same equipment and activities.
Other types of equipment, such as small and remote glycol
dehydrators and storage vessels with potential emissions <= 6 tpy
VOC, are not regulated by those federal standards but are regulated
in this action.
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In summary, this U&O FIP is intended to: (1) improve air quality on
Indian country lands within the U&O Reservation; (2) promote a more
consistent regulatory environment across the Basin; and (3) ensure that
emissions reductions will be achieved that will ensure that new
development, under both source-specific minor source permitting and the
National O&NG FIP's streamlined construction authorization mechanism
for new or modified true minor oil and natural gas sources, will not
interfere with attainment of the NAAQS.
B. Summary of the Major Provisions of This Final Rule
The following is a summary of each key requirement in the final
action. As explained earlier, the final FIP was developed to maximize
air quality improvement, in a manner that promotes a more consistent
regulatory environment across all areas in the Uinta Basin, such that
covered sources within Indian country on the U&O Reservation will be
regulated in a manner similar to how they would be regulated if located
in areas in the Basin where EPA has approved the UDEQ to implement the
CAA. We attempted to achieve this goal by providing as much consistency
as possible in the FIP with current federal standards for the oil and
natural gas industry, including NSPS 40 CFR part 60, subparts OOOO and
OOOOa (NSPS OOOO and OOOOa); NESHAP 40 CFR part 63, subpart HH (NESHAP
HH); and the Control Techniques Guidelines for reducing smog-forming
VOC emissions from existing oil and natural gas equipment and processes
in certain states and areas with smog problems (Oil and Gas CTG).\19\
The provisions in the final U&O FIP are informed by EPA's evaluation of
these several applicable federal authorities as well as an evaluation
of current UDEQ requirements that apply in the Uinta Basin outside of
the Indian country lands within the U&O Reservation (areas of the Basin
where the EPA has approved the UDEQ to implement the CAA). Where the
EPA identified differences in these authorities, we considered the
facts specific to the U&O Reservation in conjunction with the goals of
the FIP to decide what to include in the final FIP. Our analysis was
somewhat complicated by a recent joint resolution under the
Congressional Review Act (CRA),\20\ which disapproved policy revisions
made in 2020 to NSPS OOOO and OOOOa \21\ and thereby reinstated
standards from the 2012 NSPS OOOO and 2016 NSPS OOOOa.\22\ The
resolution did not, however, disapprove technical revisions made in a
separate rulemaking in 2020 to NSPS OOOOa,\23\ which remain in place
today. These two events resulted in regulatory inconsistencies between
the NSPS OOOOa methane and VOC standards.\24\ Further, the Oil and Gas
CTG in some respects includes recommendations that do not match exactly
with the requirements in the 2016 NSPS OOOOa methane standards.\25\ In
addition, the EPA recently proposed a rule to regulate methane and VOC
emissions from existing, new, and modified sources in the oil and
natural gas industry that would revise existing standards under NSPS
OOOOa, establish new VOC and methane standards for emissions sources
not previously covered by NSPS OOOOa, and establish methane emissions
guidelines for existing sources (Oil and Natural Gas Sector Climate
Review Proposed Rule).\26\ As part of that proposed rule, the EPA
addressed the inconsistencies between the methane and VOC standards in
NSPS OOOOa by proposing to repeal certain NSPS OOOOa amendments that
were made in the 2020 Technical Rule.\27\ Despite these complications,
EPA has focused its analysis for this U&O FIP on the currently
applicable state and federal requirements and guidance.
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\19\ Available at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/2016-control-techniques-guidelines-oil-and, accessed Mar. 11, 2022. CTGs are not regulations and do not
impose legal requirements directly on pollution sources; rather,
they provide recommendations for state and local air agencies to
consider as they determine what emissions limits to apply to covered
sources in their jurisdictions in order to meet RACT requirements.
\20\ 5 U.S.C. 801-808.
\21\ 85 FR 57018 (Sept. 14, 2020) (``2020 Policy Rule''; as of
June 30, 2021, no longer in effect due to CRA disapproval).
\22\ Public Law 17-23 (June 30, 2021) (resolving that Congress
``disapproves the [2020 Policy Rule] . . . and such rule shall have
no force or effect'').
\23\ 85 FR 57398 (Sept. 15, 2020) (``2020 Technical Rule'').
\24\ For requirements that currently apply, see Congressional
Review Act Resolution to Disapprove EPA's 2020 Oil and Gas Policy
Rule. Questions and Answers. U.S. Environmental Protections Agency.
Office of Air Quality Planning and Standards. June 30, 2021,
available at https://www.epa.gov/system/files/documents/2021-07/qa_cra_for_2020_oil_and_gas_policy_rule.6.30.2021.pdf, accessed Mar.
11, 2022.
\25\ For example, while the CTG recommends exempting low-
production well sites from monitoring fugitive VOC emissions, the
current OOOOa methane standards do not have such exemption.
\26\ Proposed Rule. Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review. See 86
FR 63110, November 15, 2021, available at https://www.regulations.gov (Document ID No. EPA-HQ-OAR-2021-0317-0001),
accessed Mar. 14, 2022. On the same day that this action is being
signed, the Administrator has also signed a supplemental notice
which proposes to update and expand on the 2021 Climate Review
proposal. See Supplemental notice of proposed rulemaking. Standards
of Performance for New, Reconstructed, and Modified Sources and
Emissions Guidelines for Existing Sources: Oil and Natural Gas
Sector Climate Review. Signed by the EPA Administrator on November
8, 2022, available at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry/epa-issues-supplemental-proposal-reduce. Today's action discusses certain aspects of the 2021 Climate
Review proposal, but does not attempt to describe the 2022
supplemental proposal, in light of the concurrent signature of the
latter action.
\27\ For example, the EPA is proposing to repeal the 2020
Technical Rule amendments that exempted low-production well sites
from monitoring fugitive VOC emissions, and those that changed
fugitive VOC emissions monitoring requirements at gathering and
boosting compressor stations from quarterly to semi-annually. The
proposed rule would also establish an LDAR applicability threshold
for existing, new, and modified oil and natural gas well sites of 3
tpy site-wide methane fugitive emissions (and co-proposed an
alternative threshold of 8 tpy site-wide methane fugitive
emissions).
---------------------------------------------------------------------------
That said, we acknowledge that the Agency's thinking on these
issues has evolved since we issued NSPS OOOOa and the CTG in 2016.
Among other developments, new information and analysis have been
presented in the Oil and Natural Gas Sector Climate Review Proposed
Rule that will likely be relevant for reducing emissions on the U&O
Reservation. When the EPA proposed this FIP, however, the Agency had
not yet proposed that other rule, and the Climate Review Rule is still
being developed. In the interest of moving quickly to achieve emissions
reductions, the EPA finds that it is necessary and appropriate to
finalize this FIP now. Our assessment of new, potentially relevant
information will continue in the context of the Oil and Natural Gas
Sector Climate Review Rule. If we finalize that proposed national rule
in the future, its
[[Page 75338]]
requirements will apply directly to covered sources. As to sources not
covered by a final national rule, the EPA may find it necessary or
appropriate to revisit this final action in the future and revise this
FIP based on information evaluated in issuance of a final Climate
Review Rule, providing public notice of the opportunity for review and
comment on any such revisions as part of the required rulemaking
process. Also, if the Uinta Basin Ozone Nonattainment Area's Marginal
classification is reclassified (``bumped up'') to a Moderate
nonattainment classification, or if air quality concerns otherwise
warrant, we may conclude that further rulemaking is necessary or
appropriate.
General applicability: The final rule applies to owners or
operators of oil and natural gas sources that produce oil and natural
gas or process natural gas, that are located on Indian country lands
within the U&O Reservation, and that meet the applicability criteria
specified for each set of requirements. The final rule is effective 60
days after the date of publication in the Federal Register. For new and
modified sources that construct on or after the effective date of this
final rule, compliance is required upon startup. Compliance for
existing sources that commence construction before the effective date
of the final rule is required no later than 12 months after the
effective date of the final rule. The final rule allows owners or
operators to request approval, on a case-specific basis and prior to
the compliance deadline, of an extension of the compliance deadline for
existing sources.
Delegation of authority of administration to the Tribe: The final
rule contains provisions for the Ute Indian Tribe to request delegation
to assist the EPA with administration of the federal rule and the
process by which the EPA may delegate such authority.
Emissions inventory: The final rule requires that each owner and
operator of affected oil and natural gas sources with the potential to
emit one or more NSR-regulated pollutants at levels greater than or
equal to 1 tpy must submit an inventory of actual emissions for each
emissions unit to the EPA every three years that covers emissions from
the previous calendar year (OMB Control No. 2008--New (2539.02)). The
emissions inventory serves the purpose of the triennial collection of
comprehensive Uinta Basin oil and natural gas emissions by the EPA, the
Ute Indian Tribe, and UDEQ, and corresponds with the years that
emissions inventory information is collected for the EPA National
Emissions Inventory (NEI).\28\
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\28\ Information available at https://www.epa.gov/air-emissions-inventories/national-emissions-inventory-nei, accessed Mar. 11,
2022.
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Storage vessels, glycol dehydrators and pneumatic pumps: The final
rule contains federally enforceable requirements for owners and
operators of each existing, new, and modified oil and natural gas
source that has the potential to emit 4 tons per year of VOC or more
from the collection of all storage vessels, glycol dehydrators and
pneumatic pumps. The rule requires that each affected oil and natural
gas source collect and route all VOC emissions from each storage
vessels, glycol dehydrator and pneumatic pump through a closed-vent
system to 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 route them to a flare or other control device
designed and operated to achieve at least 95.0 percent continuous VOC
emissions control efficiency.
Covers and closed-vent systems: The final rule requires owners and
operators of affected existing, new, and modified oil and natural gas
sources that are required to control VOC emissions from the collection
of all storage vessels, glycol dehydrators and pneumatic pumps, to: use
covers on any affected storage vessels that ensure flashing, working,
standing, and breathing losses are efficiently captured; and to capture
and route emissions from any affected storage vessel, glycol dehydrator
and pneumatic pump through closed-vent systems with equipment that
ensures all VOC emissions make it to the respective process or VOC
emissions control device. The rule contains construction and
operational requirements that are intended to provide legal and
practicable enforceability to ensure that all captured emissions are
routed to their intended destination with no detectable emissions.
Control devices: The final rule contains legally and practicably
enforceable construction, work practice, and operational requirements
for each required flare or enclosed combustor. Each 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
95.0 percent on a continuous basis, and must be tested by the
manufacturer, owner, or operator in accordance with the requirements of
40 CFR part 60 subparts OOOO or OOOOa. Flares and enclosed combustors
must be operated within specific parameters to ensure the effective
control of VOC emissions (including requirements to be equipped and
operated with a liquid knockout system, a continuously burning pilot
flame or electronically controlled automatic ignition device, and a
monitoring system for continuous monitoring and recording of
operational parameters; maintained in a leak-free condition; and
operated with no visible smoke emissions).
Fugitive emissions: The final rule requires implementation of a
semi-annual leak detection and repair (LDAR) program for the collection
of fugitive emissions components at each oil and natural gas source
with facility-wide potential emissions from the collection of all
storage vessels, glycol dehydrators and pneumatic pumps equal to or
greater than 4 tpy VOC, plus any additional well sites with production
of more than 15 barrels of oil equivalent (boe) per day.\29\ The final
rule also contains provisions allowing for the use of alternative
methods of leak detection, provided the method is approved by the EPA.
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\29\ As explained earlier, this FIP has been developed to
maximize air quality improvements in a manner that promotes a more
consistent regulatory environment across jurisdictional boundaries.
We evaluated several authorities to further these goals with respect
to fugitive emissions monitoring. The Oil and Gas CTG does not
recommend that well sites with production of less than 15 boe per
day (``low-production'' well sites) monitor fugitive emissions.
Using a different measure, the UDEQ applies LDAR requirements only
at well sites where the total actual uncontrolled VOC emissions from
the collection of storage vessels and glycol dehydrators is greater
than or equal to 4 tpy VOC (unless the well site is subject to the
LDAR requirements of NSPS OOOOa, in which case the operator would
comply with NSPS OOOOa).And as explained above, the NSPS OOOOa
requirements may be changed by the Oil and Natural Gas Sector
Climate Review Proposed Rule, which proposes to repeal some of the
amendments that were made to NSPS OOOOa as part of the 2020
Technical Rule. Among the provisions proposed for repeal are those
that exempted low-production well sites from fugitive emissions
monitoring and those that changed fugitive VOC monitoring
requirements at gathering and boosting compressor stations from
quarterly to semi-annually. Those fugitive VOC standards are still
in place today, and are in contrast to the 2016 fugitive methane
standards that were reinstated by the CRA disapproval of the 2020
Policy Rule. The proposed rule also would require quarterly
monitoring at oil and natural gas well sites of 3 tpy site-wide
methane fugitive emissions (and co-proposes semi-annual monitoring
for those with site-wide methane fugitive emissions between 3 and 8
tpy, with quarterly monitoring for those with site-wide methane
fugitive emissions above 8 tpy).
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VOC emissions control requirements for all sources: The final rule
contains VOC control requirements for all existing, new, and modified
oil and natural gas sources, regardless of source-wide or emission unit
specific
[[Page 75339]]
applicability criteria. These requirements include: (1) tank trucks
transporting crude oil, condensate, intermediate hydrocarbon liquids 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; and (3) all existing enclosed
combustors and flares present and operating at sources on a voluntary
basis must be equipped with an electronically controlled automatic
ignition device.
Monitoring, recordkeeping, notification and reporting: This U&O FIP
requires owners or operators to conduct source monitoring sufficient to
demonstrate compliance with the FIP's VOC emission reduction and
control requirements, including: (1) monthly inspections of each cover
and closed-vent system to ensure proper condition and functioning and
to identify defects that can result in air emissions, correcting or
repairing any defects identified within 30 days of identification; and
(2) monthly inspections of each VOC emissions control device to ensure
proper functioning whenever an operator is on site, at least once per
calendar month, and responding to any indication of malfunction (e.g.,
pilot flame failure, visible emissions) as soon as practicably and
safely possible after discovery.
C. Costs and Benefits
The EPA has projected the compliance costs, emissions reductions,
and benefits that may result from the U&O FIP. The discussion of
projected costs and benefits is presented in detail in the Regulatory
Impacts Analysis (RIA) accompanying this final rule.\30\ The RIA
focuses on the elements of the final rule--the provisions related to
VOC emissions control requirements--that are likely to result in
quantifiable costs, emissions changes, and benefits compared to a
baseline that includes operator-reported emissions from oil and natural
gas sources in the Uinta Basin for calendar year 2017, specifically on
the Indian country lands within the U&O Reservation. We estimated the
effects of the final rule for all sources that are conservatively
projected \31\ to be subject to compliance activities under this action
for the analysis years 2023 through 2032. The RIA also presents the
present value (PV) and equivalent annualized value (EAV) of costs,
benefits and net benefits of this action in 2016 dollars.
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\30\ Available in the docket for this rulemaking (Docket ID No.
EPA-R08-OAR-2015-0709).
\31\ As explained throughout this preamble, and in the RIA, this
quantitative projection does not account for those sources that may
be exempt from certain requirements of the rule because they are
subject to equivalent requirements in NSPS OOOO or OOOOa, or in
NESHAP HH. Therefore, it is likely that costs for those sources will
be less for certain activities than for sources subject to
requirements of the FIP.
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A summary of the key results of this final rule is presented in
Table 1. Table 1 presents the PV and EAV, estimated using discount
rates of 7 and 3 percent, of the benefits, costs and net benefits, as
well as the change in emissions under the final rule. The monetized net
benefits are the benefits (emissions reductions) minus the costs
(annualized compliance costs). These results present an incomplete
overview of the effects of the final FIP, because categories of
benefits--including benefits from reducing other types of air
pollutants--were not monetized and are therefore not reflected in Table
1.
Table 1--Benefits, Costs, Net Benefits and Emissions Reductions of the Final Rule 2023 Through 2032
[Dollar estimates in millions of 2016 dollars] \a\
----------------------------------------------------------------------------------------------------------------
Equivalent Equivalent
Present value annual value Present value annual value
----------------------------------------------------------------------------------------------------------------
3 Percent Discount Rate
----------------------------------------------------------------------------------------------------------------
Benefits \b\.................................... $1,000 $120 $1,000 $120
----------------------------------------------------------------------------------------------------------------
3 Percent Discount Rate
7 Percent Discount Rate
---------------------------------------------------------------
Net Compliance Costs............................ 610 72 560 81
Compliance Costs............................ 630 74 580 83
Product Recovery............................ 20 2 20 2
Net Benefits.................................... 390 48 440 39
----------------------------------------------------------------------------------------------------------------
Non-Monetized Benefits \c\...................... Ozone health and climate benefits from reducing 23,000 tons of
VOC/year and ozone health benefits from 59,000 tons of methane/
year from 2023 to 2032.
---------------------------------------------------------------
Ozone health and PM2.5 benefits from reducing 23,000 tons of
VOC/year from 2023 to 2032.
---------------------------------------------------------------
HAP benefits from reducing 3,100 tons of HAP/year from 2023 to
2032 (including 570 tons of benzene, 970 tons of toluene, 130
tons of ethylbenzene, 620 tons of xylenes and 770 tons of n-
hexane per year).
---------------------------------------------------------------
Visibility benefits.
---------------------------------------------------------------
Reduced vegetation effects from exposure to ozone.
----------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures. Totals may not appear to add correctly due to rounding.
[[Page 75340]]
\b\ Monetized benefits of the final rule include climate benefits associated with reductions in methane
emissions and are calculated using four different estimates of the social cost of methane (SC-CH4) (model
average at 2.5 percent, 3 percent, and 5 percent discount rates: 95th percentile at 3 percent discount rate).
For the presentational purposes of this table, we show the benefits associated with the average SC-CH4 at a 3
percent discount rate, but the Agency does not have a single central SC-CH4 point estimate. We emphasize the
importance and value of considering the benefits calculated using all four SC-CH4 estimates; the present value
(and equivalent annual value) of the additional benefit estimates (millions of 2016$) ranges from $480 to
$2,700 ($62 to $310) over 2023 to 2032 for the final rule. Please see Table 6-6 of the RIA for the full range
of SC-CH4 estimates. As discussed in Section 6.5 of the RIA, a consideration of climate benefits calculated
using discount rates below 3 percent, including 2 percent and lower, are also warranted when discounting
intergenerational impacts. All net benefits are calculated using climate benefits discounted at 3 percent.
\c\ There are important unquantified health and welfare benefits associated with reductions in other air
pollutants, which are discussed in Chapter 6 of the RIA.
This final rule is expected to result in net benefits (emissions
reductions) for human health and the environment in the Uinta Basin.
The estimated benefits include the monetized climate effects of the
projected reduction in methane emissions under the final rule resulting
from the targeted reduction of VOC emissions. The PV of these climate-
related benefits (emissions reductions), discounted at a 3-percent
rate, is estimated to be about $1 billion, with an EAV of about $120
million (Table 1).
In addition to directly controlling VOC emissions, which are
expected to lower ozone concentrations in the Uinta Basin, this action
is expected to lower HAP emissions and the formation of secondary
particulate matter with a diameter of 2.5 micrometers or less
(PM2.5) even though those pollutants are not directly
regulated under this action. While the EPA expects that the VOC
emissions reductions will improve air quality and have beneficial
health and welfare effects associated with reduced exposure to ozone,
PM2.5, and HAP, we did not quantify those effects. We note
that the absence of those monetized benefits from the analysis of
benefits does not imply that these benefits do not exist, but also has
no bearing on the legal or technical basis for the final action itself.
We qualitatively discuss these unquantified benefits in Chapter 6 of
the RIA. If the EPA were to quantify the ozone and PM2.5
impacts, the Agency would estimate the number and value of avoided
premature deaths and illnesses using an approach detailed in the
Particulate Matter NAAQS and Ozone NAAQS RIA.\32\ Such an analysis
would account for the distribution of air pollution-attributable risks
among populations most vulnerable and susceptible to PM2.5
and ozone exposure. As explained in the RIA for this final rule, due to
methodology and data limitations for areas experiencing elevated winter
ozone, we were unable to estimate the benefits associated with ozone,
PM2.5, and HAP emission changes that would occur as a result
of this rule, but the EPA continues to develop better methods for
analyzing the benefits of such reductions.
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\32\ U.S. EPA. Integrated Science Assessment (ISA) for
Particulate Matter (Final Report). EPA Office of Research and
Development (ORD), National Center for Environmental Assessment,
EPA/600/R-19/188 (Dec. 2019); available at: https://www.epa.gov/naaqs/particulate-matter-pm-standards-integrated-science-assessments-current-review, accessed Mar. 11, 2022, and U.S. EPA.
Integrated Science Assessment for Ozone and Related Photochemical
Oxidants. EPA ORD, EPA/600/R-20/012 (Apr. 2020); available at:
https://www.epa.gov/isa/integrated-science-assessment-isa-ozone-and-related-photochemical-oxidants. Accessed Mar. 11, 2022.
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The estimated capital and annualized compliance costs include the
monetized costs for affected owners or operators to comply with the
final rule. The net PV of these compliance costs (accounting for
product recovery), discounted at a 7-percent rate, is estimated to be
about $560 million, with an EAV of about $81 million (Table 1). Under a
3-percent discount rate, the PV of the compliance costs is about $610
million, with an EAV of about $72 million (Table 1).
The PV of the net benefits of this rule, discounted at a 7-percent
rate, is estimated to be about $440 million, with an EAV of about $39
million (Table 1). Under a 3-percent discount rate, the PV of net
benefits is about $390 million, with an EAV of about $48 million (Table
1).
II. General Information
A. Does this action apply to me?
Entities potentially affected by this rule include the Ute Indian
Tribe,\33\ as well as existing, new, and modified sources \34\ that are
in the oil and natural gas production and natural gas processing
segments of the oil and natural gas industry (see Table 2.) and are on
Indian country \35\ 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 U&O FIP
applies 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 are not covered by this U&O
FIP.\36\ In addition, this rule does not apply to any sources on non-
Indian-country lands, including any non-Indian country lands within the
exterior boundaries of the Reservation.\37\
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\33\ 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 (Jan. 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.
\34\ As specified at 40 CFR 49.4169(c).
\35\ 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.
\36\ 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 (Feb. 12, 1998) (``Tribal Authority
Rule''); Arizona Pub. Serv. Co. v. EPA, 211 F.3d 1280, 1285-86 (D.C.
Cir. 2000). The EPA's references in this 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 the 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 the 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
final 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.
\37\ 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 footnote 40.
[[Page 75341]]
Table 2--Source Categories Affected by This Action
----------------------------------------------------------------------------------------------------------------
Examples of regulated entities/description of
Industry category NAICS code industry category
----------------------------------------------------------------------------------------------------------------
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.
----------------------------------------------------------------------------------------------------------------
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
action. This table lists the types of entities that the EPA is now
aware could potentially be regulated by this action. Other types of
entities not listed in the table could also be regulated. To determine
whether your entity is regulated by this action, you should carefully
examine the applicability criteria found in 40 CFR 49.4169 through
49.4184. 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. 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 final action 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).
C. Judicial Review
Under section 307(b)(1) of the Act, petitions for judicial review
of this action must be filed in the United States Court of Appeals for
the appropriate circuit by February 6, 2023. Filing a petition for
reconsideration by the Administrator of this final rule does not affect
the finality of this rule for the purposes of judicial review nor does
it extend the time within which a petition for judicial review may be
filed and shall not postpone the effectiveness of such rule or action.
Under section 307(b)(2) of the Act, the requirements of this final
action with respect to which review could have been obtained under
section 307(b)(1) of the Act may not be judicially reviewed later in
civil or criminal proceedings brought by us to enforce these
requirements.
III. Background
A. Uintah and Ouray Indian Reservation
The Uintah and Ouray Indian Reservation is composed of lands that
were part of the original Uintah Valley and Uncompahgre Reservations,
which were established by executive order in 1861 and 1882,
respectively.\38\ In 1948 Congress extended the exterior boundary of
the Reservation with the Hill Creek Extension.\39\ The U&O
Reservation's boundaries have been addressed and explained in a series
of federal court decisions. Consistent with those decisions, the EPA
considers all lands within the U&O Reservation's boundaries to be
``Indian country'' as defined in 18 U.S.C. 1151, subject to federal
court decisions holding that specified Congressional acts removed
certain lands from Indian country status.\40\
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\38\ 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; U.S. Office of Indian Affairs, Dept. of the Interior, Annual
Report of the Commissioner of Indian Affairs, at 226 (1886).
\39\ 62 Stat. 72 (1948).
\40\ 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); Hackford v. Utah, 845 F.3d 1325,
1327 (10th Cir.), cert. denied, 138 S. Ct. 206 (2017).
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B. Tribal Authority Rule
Section 301(d) of the 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.\41\ 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.\42\
Acting principally under that authority, on February 12, 1998, the EPA
promulgated the Tribal Authority Rule (TAR).\43\ In the TAR, we
determined that it was appropriate to treat eligible tribes in the same
manner as states for
[[Page 75342]]
all CAA statutory and regulatory purposes, except a list of specified
CAA provisions and implementing regulations thereunder.\44\ 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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\41\ 42 U.S.C. 7601(d)(1) and (2); See 63 FR 7254-57 (Feb. 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).
\42\ 42 U.S.C. 7601(d)(4).
\43\ ``Indian Tribes: Air Quality Planning and Management.'' see
63 FR 7254 (Feb. 12, 1998); 40 CFR 49.1-49.11.
\44\ 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.'' \45\ 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.'' \46\ 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
TIP is submitted or approved.\47\
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\45\ See 63 FR at 7265 (Feb. 12, 1998).
\46\ Id.
\47\ 40 CFR 49.11(a).
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The Ute Indian Tribe has not applied for treatment in a similar
manner as a state (TAS) for the purpose of administering a TIP under
the CAA; nor has it submitted a TIP for review and approval. Thus, with
respect to Indian country lands within the U&O Reservation, there is
currently no submitted or EPA-approved TIP that would address the air
quality purposes described earlier. This FIP 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).\48\ As
a part of this regulation, the EPA made a finding that it was necessary
or appropriate to protect air quality by developing 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 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.'' \49\ 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 a final rule on July 1, 2011, and the FIP
became effective on August 30, 2011. \50\
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\48\ ``Review of New Sources and Modifications in Indian
Country,'' Proposed Rule, 71 FR 48696 (Aug. 21, 2006).
\49\ ``Review of New Sources and Modifications in Indian
Country,'' Final Rule, 76 FR 38748, 38754 (July 1, 2011).
\50\ See 76 FR 38748.
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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 where there is no
EPA-approved program in place. \51\ Tribes can elect to develop and
implement their own EPA-approved program under the TAR but are not
required to do so.\52\ 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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\51\ 40 CFR 49.153. Existing sources are only subject to the
registration requirements unless they undergo modification.
\52\ 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. 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 oil and natural gas
source 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
[[Page 75343]]
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.\53\
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\53\ 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 MRR requirements of the major
NSR program.
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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 minor NSR thresholds,\54\ 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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\54\ See 40 CFR 49.153, 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 and the minor NSR
thresholds for VOC are 5 tpy in those Indian country portions of the
Reservation. 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 Indian
country 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).\55\ 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 2012-2020
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 the three-year
period from 2017 to 2019 was from the Ouray monitor at 89 ppb.\56\ The
current (three-year period from 2018 to 2020) highest valid ozone
design value in the Uinta Basin is also from the Ouray monitor at 76
ppb. Additionally, higher single 8-hour average ozone concentrations
were observed at some monitoring sites, before the sites were
designated as regulatory monitors.\57\ 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.'' \58\
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\55\ See 80 FR 65292 (Oct. 26, 2015).
\56\ 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 Mar. 14, 2022.
\57\ A ``regulatory'' monitor is a monitor that meets the EPA's
air quality monitoring requirements, including requirements for
siting, equipment selection, data sampling protocols, and quality
assurance, under the EPA's monitoring regulations at 40 CFR part 58.
\58\ 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.
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As discussed previously, the EPA designated areas in the Uinta
Basin below 6,250 feet, including portions of the Indian country lands
within the U&O Reservation, as marginal nonattainment for the 2015
ozone standard. The fourth maximum ambient air concentration
measurement for 2020, the attainment year, is 66 ppb, which is lower
than the 2015 ozone NAAQS. Accordingly, Utah and the Ute Indian Tribe
requested to extend the August 3, 2021, attainment date for the Uinta
Basin Ozone Nonattainment Area by 1-year. On April 13, 2022, the EPA
proposed to grant a 1-year attainment date extension for the Uintah
Basin Ozone Nonattainment area.\59\ The proposal explains that
preliminary 2021 ozone monitoring data indicate that the area may not
attain the 2015 ozone NAAQS by the proposed extended attainment date of
August 3, 2022, but that the area could meet the air quality criteria
for a second 1-year extension. As of February 9, 2022, the Uinta Basin
area's preliminary 2019-2021 design value was 78 ppb and the
preliminary 2021 fourth highest daily maximum 8-hour concentration
value was 72 ppb. To qualify for a second 1-year extension, an area's
fourth highest daily maximum 8-hour value, averaged over both the
original attainment year and the first extension year, must be 70 ppb
or less (40 CFR 51.1307(a)(2)). If the preliminary 2021 ozone data are
certified, then the fourth highest daily maximum 8-hour value, averaged
over 2020 and 2021, would be 69 ppb. \60\ The EPA is issuing this
notice of final rulemaking (NFRM) because we have concluded that it is
necessary and appropriate to take action to protect air quality on the
Indian country lands within the U&O Reservation to address these
elevated ozone levels.
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\59\ See 87 FR 21842 (Apr. 13, 2022), available at https://www.govinfo.gov/content/pkg/FR-2022-04-13/pdf/2022-07513.pdf,
accessed Apr. 29, 2022. The criteria to qualify for requesting a 1-
year extension of the attainment date are: (1) the state has
complied with all requirements and commitments pertaining to the
area in the applicable implementation plan; and (2) for a first
attainment date extension, an area's fourth highest daily maximum 8-
hour value for the attainment year must not exceed the level of the
standard.
\60\ Preliminary air quality data is available at https://www.epa.gov/outdoor-air-quality-data/download-daily-data, accessed
Apr. 29, 2022.
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Ambient ozone is a secondary pollutant formed when the two primary
ozone precursors, 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 NAAQS are due to a combination of
abundant local ground-level emissions of VOC and NOX with
the unique meteorological and topographic features in the Uinta Basin:
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 meteorological conditions persist.\61\ The
[[Page 75344]]
state of Utah conducted field studies in the Uinta Basin from 2011 to
2014 to understand the emissions sources and the unique photochemical
processes that contribute to winter ozone concentrations within the
Uinta Basin. Reports for winter ozone field studies for each year are
available on the UDEQ website.\62\ These studies found that the oil and
natural gas production industry is the most significant anthropogenic
contributor of VOC and NOX emissions in the Basin and
primarily responsible for winter ozone formation. The studies also
concluded that winter ozone production in the Basin is sensitive to
changes in VOC emissions, and that there is greater uncertainty about
its sensitivity to changes in NOX emissions.
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\61\ The RIA for this final 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).
\62\ ``Uinta Basin Ozone Studies (UBOS),'' https://deq.utah.gov/air-quality/uinta-basin-ozone-studies-ubos, accessed Mar. 11, 2022.
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The EPA has determined that this final action will result in large
reductions of VOC emissions, and that this result is expected to reduce
ambient ozone and reduce the severity of exceedances of the 2008 and
2015 ozone NAAQS.\63\ As discussed in more detail later, the final
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.
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\63\ As discussed in the RIA for this final rule (available at
https://www.regulations.gov, Docket ID #EPA-R08-OAR-2015-0709),
adoption of the VOC control measures required under this FIP may
result in very small NOX emission increases. We estimate
that these additional NOX emissions would be at most 27
tpy total. Considering the large amount of VOC emission reductions
that the same controls will achieve, the small potential
NOX emissions increase will not counteract the effect of
the VOC reductions or adversely affect the area's ability to attain
the NAAQS.
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We had previously informed the public of our intent to undertake
action specific to the Indian country lands within the U&O Reservation;
as noted earlier, in the preamble to the National O&NG FIP, we stated:
``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.'' \64\ After further review, and
considering the emissions information presented below, the EPA
concludes that those concerns are still warranted, and that this action
is necessary and appropriate to address poor air quality on the Indian
country lands within the U&O Reservation.
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\64\ See 81 FR at 35963 (June 3, 2016).
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E. Emissions Information
In 2020, the EPA, in cooperation with the UDEQ and the Ute Indian
Tribe, developed the UBEI2017-Update, 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.\65\ 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 2017 National Emissions Inventory (2017 NEI); \66\
(2) a study by the Western Regional Air Partnership (WRAP); \67\ (3)
existing true minor source registration data and new and modified true
minor source registration submitted to the EPA under the Federal Indian
Country Minor NSR Program; \68\ and (4) EPA Greenhouse Gas Reporting
Program, subpart W Petroleum and Natural Gas Systems.\69\ They are
discussed in more detail in the Regulatory Impact Analysis (RIA) for
this final rule.\70\
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\65\ The inventory and supporting analysis can be viewed in the
docket for this rule, in the Microsoft Excel spreadsheet titled,
``UO FIP cost and emissions analysis.xlsx'' (Docket ID No. EPA-R08-
OAR-2015-0709). This U&O FIP requires owners and operators to submit
triennial emissions inventories, similar to a requirement finalized
by the UDEQ in March of 2018. These triennial updates will provide
information on how emissions are changing in the Basin from the 2017
baseline. See Section V (Summary of FIP Provisions).
\66\ See 2017 National Emissions Inventory (2017 NEI), available
at https://www.epa.gov/air-emissions-inventories/2017-national-emissions-inventory-nei-data, accessed Sept. 28, 2020. Queried:
Duchesne & Uintah Counties VOC-NOx all sectors; Ute Indian Tribe of
the Uintah & Ouray Indian Reservation VOC-NOx all sectors. EPA's
analysis of the 2017 NEI data is available in the docket for this
rulemaking (Docket ID No. EPA-R08-OAR-2015-0709), Microsoft Excel
spreadsheet titled ``2017 NEI Uinta Basin_Duchesne Counties_U&O_VOC-
NOx.xlsx. The UDEQ submitted the UBEI2017 to the 2017 NEI, but later
updated it for storage vessel, pneumatic controller, pneumatic pump,
fugitive, gas well liquid unloading, blowdowns and pigging and
oilfield wastewater emissions that are planned to be submitted to
the NEI at a future date (see footnote 75). Analysis of the 2017 NEI
for the purposes of this final U&O FIP was prepared using the
version publicly available before incorporating these updates from
the UDEQ.
\67\ 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/PhaseIII.aspx, accessed Mar.
14, 2022. 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.
\68\ Data from existing true minor source registration reports
and data from new and modified true minor oil and natural gas source
registrations under the National O&NG FIP, 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.
\69\ 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 Mar. 14, 2022.
\70\ The RIA can be viewed in the docket for this rulemaking
(Docket ID No. EPA-R08-OAR-2015-0709).
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The 2017 NEI provides a general picture of the relative
contributions of ozone-forming emissions from the oil and natural gas
sector as compared to other industry sectors, estimating that emissions
from the production segment of the oil and natural gas sector were the
largest anthropogenic \71\ contributor of both VOC and NOX
emissions in the Uinta Basin, at 97 percent of the VOC emissions and 64
percent of the NOX emissions. 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 Indian country lands within the
U&O Reservation. 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
UBEI2017-Update 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.
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\71\ The calculation excludes biogenic sources of VOC and
NOX, because elevated ozone occurs during the winter when
vegetation and soils are presumed to not be a contributor because
they are dormant or covered by snow.
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The UBEI2017-Update indicates that the majority of existing oil and
natural gas sources in the region are on Indian country lands within
the U&O Reservation. As explained in more detail below, most of these
are minor sources and are uncontrolled. The 2017 NEI indicates that,
compared to other industry sector sources, existing oil and natural gas
sources are cumulatively the largest anthropogenic contributor of VOC
(97 percent) and NOX (64 percent) 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 Indian
country lands within the U&O Reservation were previously either subject
to less stringent regulation or no regulation at all.
[[Page 75345]]
Specifically, the UBEI2017-Update shows that 76 percent of all
existing oil and natural gas facilities (including well sites
processing fluids from multiple individual wells, as well as compressor
stations and other processing facilities) in the Uinta Basin are
located on Indian country lands within the U&O Reservation. According
to the inventory, almost 73,000 tons of VOC and over 6,700 tons of
NOX emissions were emitted in 2017 from existing oil and
natural gas sources on Indian country lands within the U&O Reservation.
That is approximately 89 percent of the total oil and natural gas-
related VOC emissions in the Uinta Basin and approximately 63 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 Indian country lands
within the U&O Reservation are uncontrolled. According to the UEBI2017-
Update, on the Indian country lands within the U&O Reservation, 85
percent of the total number of existing storage vessels, 98 percent of
the total number of existing glycol dehydrators and 99 percent of
existing pneumatic pumps are uncontrolled emitters of VOC. By contrast,
in areas of the Basin where the EPA has approved the UDEQ to implement
the CAA, 68 percent of the total number of existing storage vessels and
52 percent of the total number of existing glycol dehydrators are
uncontrolled (uncontrolled pneumatic pump numbers are relatively
equivalent to Indian country at 99 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.\72\ Now that the revised and new requirements are effective, we
expect the percentage of uncontrolled existing storage vessels and
glycol dehydrators in areas of the Basin where the EPA has approved the
UDEQ to implement the CAA will decrease from what was reported in the
UBEI2017-Update. The UDEQ's rule revisions and new rules are discussed
in more detail in the preamble to the proposed FIP.\73\ In addition,
the UBEI2017-Update shows that emissions from oil and natural gas
wastewater disposal facilities on the Indian country lands within the
U&O Reservation comprise approximately 35 percent of the total VOC
emissions from oil and natural gas activity on the Indian country lands
within the U&O Reservation. As explained in the preamble to the
proposed FIP,\74\ 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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\72\ Utah State Bulletin, Official Notices of Utah State
Government, Filed Jan. 3, 2018, 12:00 a.m. through Jan. 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 in the docket for
this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709.
\73\ See 85 FR 3504-3506, Section IV. D. Developing the Proposed
Control Requirements, 3. Evaluation of State Oil and Natural Gas and
Permitting-Related Requirements.
\74\ See 85 FR 3503-3504, Section IV. D. Developing the Proposed
Control Requirements, 2. Evaluation of Federal Oil and Natural Gas
and Permitting-Related Requirements.
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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 Indian country lands within 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 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.'' \75\ In that rule, we took an important initial step to
control 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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\75\ See 78 FR 17836 (Mar. 22, 2013).
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This U&O FIP specific to Indian country lands within the U&O
Reservation will reduce VOC emissions related to the formation of
ozone. Exceedances of both the 2008 and the 2015 ozone NAAQS have
occurred at air quality monitors on and around the Reservation, and
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. There are no currently approved TIPs that apply to existing oil
and natural gas sources on Indian country lands within the U&O
Reservation. Finally, the majority of the sources covered by this U&O
FIP have not previously been subject to federally required emissions
controls, as discussed further in Section IV.A of the preamble to the
proposed FIP.\76\ For all of these reasons, we have concluded that is
both necessary and appropriate to protect air quality on the Indian
country lands within the U&O Reservation by promulgating this FIP.
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\76\ See 85 FR 3501, Section IV. Developing the Proposed Control
Rule, A. Rationale for the Proposed Rule.
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G. Oil and Natural Gas Industry in the Uinta Basin
The oil and natural gas industry 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 industry in the Uinta Basin includes all
operations from the well to 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 industry.
Thus, with respect to
[[Page 75346]]
crude oil, the oil and natural gas industry ends where crude oil enters
an oil transmission pipeline or other means of transportation to a
petroleum refinery. For natural gas, the industry includes all
operations from the well to the final end user.
The oil and natural gas industry 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 U&O FIP for oil and natural gas
sources on Indian country lands within 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 industry
on the Indian country portion of the U&O Reservation. There are more
than 6,870 individual oil and natural gas sources (operated by 33
distinct entities) on the Indian country lands within the U&O
Reservation, the majority of which are well sites in the oil and
natural gas production segment.\77\ As discussed earlier, the 2017 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 2017 NEI as contributing less than one percent each of
the total VOC and NOX emissions in the Uinta Basin.\78\ Of
the 13,363 individual active oil and natural gas wells in the Uinta
Basin, over 10,108 wells, or about 76 percent, are on Indian country
lands within the U&O Reservation.
---------------------------------------------------------------------------
\77\ 2017 Uinta Basin Oil and Natural Gas Emissions Inventory
Update (UBEI2017-Update). The inventory and supporting analysis can
be viewed in the docket for this rulemaking. See ``UO FIP cost and
emissions analysis.xlsx'' (Docket ID No. EPA-R08-OAR-2015-0709).
\78\ Based on the NEI Source Type to Sector Crosswalk in the
2017 NEI, available at https://www.epa.gov/air-emissions-inventories/2017-national-emissions-inventory-nei-data, accessed
Mar. 14, 2022. Queried: Duchesne & Uintah Counties VOC-NOx all
sectors; Ute Indian Tribe of the Uintah & Ouray Indian Reservation
VOC-NOx all sectors. The EPA's analysis of the 2017 NEI data is
available in the docket for this rulemaking (Docket ID No. EPA-R08-
OAR-2015-0709), Microsoft Excel spreadsheet titled ``2017 NEI Uinta
Basin_Dechesne Counties_U&O_VOC-NOx.xlsx.''
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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.\79\
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\79\ The RIA for the final rule can be viewed in the docket for
this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
---------------------------------------------------------------------------
IV. Summary of the Final U&O FIP
A. Overview
The emissions control and other requirements of this final FIP that
will reduce VOC emissions from existing, new, and modified oil and
natural gas sources on Indian country lands within the U&O Reservation
are summarized in this section. Significant changes since proposal are
discussed in more detail in section V of this preamble. The FIP
includes emissions control efficiency requirements and operational and
work practice standards, each with associated monitoring, testing,
recordkeeping, and reporting requirements, as appropriate. Oil and
natural gas sources must comply with these requirements, except as
specifically exempted under the FIP for certain equipment or activities
otherwise subject to existing federal standards 40 CFR part 60,
subparts OOOO or OOOOa, or 40 CFR part 63, subpart HH. Also discussed
in this section are the features of the FIP that are necessary to
facilitate its implementation.
This final rule applies to owners or operators of oil and natural
gas sources that either produce oil and natural gas or process natural
gas, that are located on Indian country lands within the U&O
Reservation, and that meet the applicability criteria specified for
each set of requirements. It includes the following provisions in 40
CFR part 49:
49.4169 Introduction.
49.4170 Delegation of authority of administration to the Tribe.
49.4171 General provisions.
49.4172 Emissions Inventory.
49.4173 VOC emissions control requirements for storage vessels.
49.4174 VOC emissions control requirements for dehydrators.
49.4175 VOC emissions control requirements for pneumatic pumps.
49.4176 VOC emissions control requirements for covers and closed-vent
systems.
49.4177 VOC emissions control devices.
49.4178 VOC emissions control requirements for fugitive emissions.
49.4179 VOC emissions control requirements for tank truck loading.
49.4180 VOC emissions control requirements for pneumatic controllers.
49.4181 Other combustion devices.
49.4182 Monitoring and testing requirements.
49.4183 Recordkeeping requirements.
49.4184 Notification and reporting requirements.
We do not expect a substantial number of the existing oil and
natural gas sources subject to this U&O FIP to also be subject to NSPS
OOOO or OOOOa, or NESHAP HH, for the specific equipment and activities
regulated. However, to minimize regulatory burdens where such a
potential overlap does exist, this rule finalizes the proposed
provisions that equipment or activities that are affected
[[Page 75347]]
by any requirement in this U&O FIP and that are also subject to the
substantive emissions control requirements in those EPA standards will
not be subject to this FIP's substantive emissions control requirements
for such equipment and activities. As an example, given the exemptions
being finalized, if an existing, new, or modified oil and natural gas
source on Indian country lands within the U&O Reservation has storage
vessels, pneumatic pumps, and fugitive emissions components that 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 vessels,
pneumatic pumps, or fugitive emissions components.
B. Introduction
In 40 CFR 49.4169 (Introduction) we are finalizing our proposal to
specify: (1) the purpose of this U&O FIP; (2) the general applicability
of this U&O FIP; and (3) the compliance schedule for this U&O FIP.
We are finalizing text that: (1) establishes provisions for
delegation of authority to allow the Ute Indian Tribe to assist the EPA
with administration of this U&O FIP in 40 CFR 49.4170; (2) establishes
general provisions and definitions applicable to oil and natural gas
sources in 40 CFR 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 2023 in 40 CFR
49.4172; and (4) establishes, in 40 CFR 49.4173 through 49.4184,
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 on Indian country lands within the U&O Reservation.
This final rule provides that compliance with the rule for oil and
natural gas sources that commence construction on or after the
effective date of the final rule is required upon startup. Compliance
for sources existing as of the effective date of the final rule is
required no later than 12 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
requirements, and (3) securing the necessary trained personnel to
install compliant devices and associated piping and instrumentation. We
expect that there will be about 2,165 existing oil and natural gas
sources that may require equipment retrofit and installation of VOC
emission control equipment (combustion controls) under the final rule.
Additionally, we estimate that more than 700 high-bleed pneumatic
controllers will need to be retrofitted to low-or no-bleed. We have
determined that providing 12 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, while ensuring that
meaningful emissions reductions will be achieved that provide near-term
benefits to improve air quality and make progress toward future
attainment.\80\
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\80\ 12 months is a tighter compliance timeframe than is
required for existing sources 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 final rule
allows sources to request extensions of the compliance date beyond
the 12 months if needed.
---------------------------------------------------------------------------
We are also finalizing a provision to allow an owner or operator on
a case-specific basis to submit a written request to the EPA for an
extension of the compliance deadline for existing sources, which must
include appropriate justification of the reason for the request. Any
approval or denial of an extension request, including the length of any
approved extension, will be based on the merits of each case. Factors
that the EPA will consider in deciding whether to grant an extension
request under the provision include the economic and technical
feasibility of meeting this U&O FIP's control requirements in the
prescribed timeframe. The final FIP specifies the criteria that the EPA
will apply in responding to requests for extension of the compliance
period, including that the request must be submitted before the
compliance deadline, must identify the specific provisions for which an
extension is being requested and include an alternative compliance
deadline, and must provide a rationale for the request with supporting
information explaining how the operator will effectively meet all
applicable requirements after the requested alternative compliance
deadline.
C. Provisions for Delegation of Administration to the Ute Indian Tribe
We are establishing in 40 CFR 49.4170 (Delegation of authority of
administration to the Tribe) 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 provides for administrative delegation of this federal rule and
does not affect the TAS eligibility criteria under CAA section 301(d)
and 40 CFR 49.6 should the Ute Indian Tribe decide to seek such
treatment for the purpose of administering its 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.
D. General Provisions
We are finalizing in 40 CFR 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. Determination of whether acceptable
operating and maintenance procedures are being used will be based on
information available to the EPA, including monitoring results, review
of operating and maintenance procedures, and inspection of the source;
and (2) definitions.
E. Emissions Inventory Requirements
We are finalizing in 40 CFR 49.4172 a requirement for owners/
operators of oil and natural gas sources with the
[[Page 75348]]
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 beginning with calendar year 2024, that covers
emissions from the previous calendar year (2023 for the first required
inventory). Each triennial inventory must be submitted no later than
April 15th of the year after each inventory year. The triennial
emissions inventory requirement will suffice for the purpose of
continued updates to the comprehensive Uinta Basin oil and natural gas
emissions inventory by the UDEQ, the Ute Indian Tribe, and the EPA.
Owners/operators must 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. The format will be consistent with the format used by the UDEQ
to collect information from sources in the Uinta Basin outside of
Indian country lands within the U&O Reservation.
F. VOC Emissions Control Requirements
The discussion in this section details the final VOC emissions
control requirements of this FIP 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 final VOC emissions
control requirements of this FIP and the Utah Oil and Gas Rules \81\
and Utah Permit Requirements \82\ is that the Utah permit by rule's 4
tpy total VOC emissions threshold for requiring controls does not
include pneumatic pump emissions. We have determined that emissions
from pneumatic pumps are a large source of VOC emissions on the Indian
country lands within the U&O Reservation, but a negligible source of
VOC emissions in the areas in the Basin where the EPA has approved the
UDEQ to implement the CAA. This difference in the share of pneumatic
pumps emissions in the inventory is because the majority of natural gas
production operations, which use gas-driven pneumatic pumps, occurs on
the Reservation, while lands where air quality is managed by the UDEQ
feature mostly oil production. This difference is explained in more
detail later in this section.
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\81\ Utah Administrative Code Chapter R307-500 Series (Oil and
Gas), available in the docket for this rulemaking (Docket ID No.
EPA-R08-OAR-2015-0709). These rules, referred to collectively as the
``Utah permit by rule,'' are state-only rules and the UDEQ has not
submitted them to the EPA for approval in the Utah SIP.
\82\ Utah Administrative Code Chapter R307-401 (Permits: New and
Modified Sources), available in the docket for this rulemaking
(Docket ID No. EPA-R08-OAR-2015-0709); See 40 CFR part 52, subpart
TT.
\83\ 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 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. In
addition, the EPA issued subsequent rules that revised certain
provisions of NSPS OOOO and OOOOa (The 2020 Policy Rule and 2020
Technical Rule; see discussion above in Section I.B.). The 2021 CRA
resolution disapproved the policy amendments of NSPS OOOO and OOOOa.
PL 17-23 (June 30, 2021). The requirements summarized in this table
reflect the standards that are in effect today--the methane
standards in the 2016 NSPS OOOOa and the 2016 VOC standards in NSPS
OOOO and OOOOa, as they were amended in 2020. The EPA's Oil and
Natural Gas Sector Climate Review Proposed Rule would revise
existing VOC standards under NSPS OOOO and OOOOa, establish new
methane and VOC standards for new and modified emissions sources not
previously covered by NSPS OOOO and OOOOa, and establish emissions
guidelines for existing sources. This table does not reflect those
proposed standards and guidelines. We may revisit this final action
in the future based on any final action we take under CAA section
111 with the Oil and Natural Gas Sector Climate Review rulemaking.
Table 3--U&O FIP VOC Emissions Control Requirements for Existing, New, and Modified Oil and Natural Gas Sources Versus UDEQ and Other Federal \83\
Control Requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
U&O FIP VOC Emissions Controls Utah oil and gas
------------------------------------------------------------------------- rules and Utah
Final FIP requirements (section Applicability Control efficiency permit NSPS OOOO NSPS OOOOa NESHAP HH
in 40 CFR part 49) threshold (percent) requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
Storage vessel VOC emission Source-wide Reduce VOC by 95.0 Issued Utah Permit Reduce VOC by 95.0 Reduce VOC by 95.0 Reduce HAP by 95.0
control requirements (Sec. potential for VOC percent or route Requirements percent or route percent or route percent or route
49.4173). emissions from to a process. (BACT for site- to a process for to a process for to a process for
the collection of See also VOC specific & individual individual individual
all storage emission control general approval storage vessels storage vessels storage vessels
vessels, devices later in orders)--Reduce with potential with potential with potential
dehydrators and this table (Sec. VOC by 98 percent for >=6 tpy per for >=6 tpy per for flash
pneumatic pumps 49.4177). or route to a storage vessel storage vessel emissions and
>=4 tpy. process where constructed, constructed, actual annual
source-wide reconstructed or reconstructed or average
uncontrolled modified after modified after hydrocarbon
actual VOC August 23, 2011, September 18, liquid throughput
emissions from and on or before 2015 >=79,500 liters/
the collection of September 18, (alternatively, day.
all storage 2015 no control
vessels, (alternatively, required if
dehydrators and no control uncontrolled
pneumatic pumps required if actual VOC
>=4 tpy. uncontrolled emissions
Utah Oil and Gas actual VOC maintained <4tpy).
Rules--Reduce VOC emissions
by 95 percent or maintained <4
route to a tpy).
process if total
uncontrolled
actual emissions
from the
collection of
dehydrators and
storage vessels
>=4 tpy VOC (does
not include
pneumatic pump
emissions), or if
source with
storage vessels
only has through
put >=8,000 bbl
crude oil or
2,000 bbl
condensate, on
rolling 12-month
basis--unless <=4
tpy source-wide
uncontrolled
actual emissions
of VOC from the
collection of all
storage vessels.
[[Page 75349]]
Dehydrators VOC emission control See VOC emission Issued Utah Permit Not covered....... Not covered....... For units at major
requirements (Sec. 49.4174). control devices Requirements HAP sources and
later in this (BACT for site- non-urban area
table (Sec. specific & sources with
49.4177). general approval actual annual
orders)--Reduce average flowrate
VOC by 98 percent of natural gas
or route to a >=85,000 standard
process where m3/day, reduce
source-wide HAP by 95.0
uncontrolled percent or route
actual VOC to a process.
emissions from Units with actual
the collection of annual average
all storage flowrate of
vessels, natural gas
dehydrators and <85,000 standard
pneumatic pumps m3/day not
>=4 tpy. covered--this is
Utah Oil and Gas the majority of
Rules--Reduce VOC units on Indian
by 95 percent if country lands
total within the U&O
uncontrolled Reservation.
actual emissions
from the
collection of
dehydrators and
storage vessels
>=4 tpy VOC (does
not include
pneumatic pump
emissions).
Pneumatic pumps VOC emission See VOC emission Issued Utah Permit Not covered....... Reduce VOC by 95.0 Not covered.
control requirements (Sec. control devices Requirements percent (if
49.4175). later in this (BACT for site- control device is
table (Sec. specific & already on site)
49.4177). general approval or route to a
orders)--Reduce process (if
VOC by 98 percent technically
or route to a feasible) for
process where natural gas-
source-wide driven diaphragm
uncontrolled pneumatic pumps
actual VOC at well sites
emissions from constructed,
the collection of reconstructed or
storage vessels, modified after
dehydrators and September 18,
pneumatic pumps 2015.
>=4 tpy. Zero natural gas
Utah Oil and Gas emissions for
Rules does not natural gas
require control processing plants
of pneumatic pump constructed after
emissions. September 18,
2015.
Covers and closed-vent system Source-wide 100 percent of VOC 100 percent of 100 percent of 100 percent of 100 percent of HAP
VOC emission control potential for VOC emissions routed storage vessel, storage vessel storage vessel emissions, if
requirements (Sec. 49.4176). emissions from to process or dehydrator and VOC emissions emissions routed required to
the collection of control device. pneumatic pump routed to control to control device control glycol
all storage emissions routed device or process. or process. dehydrators and/
vessels, to control device or storage
dehydrators and or process in vessels.
pneumatic pumps issued Utah
>=4 tpy. Permit
Requirements and
Rules (BACT for
site-specific &
general approval
orders).
Utah Oil and Gas
Rules--100
percent storage
vessel and
dehydrator
emissions routed
to control device
or process (Utah
Oil and Gas Rules
do not include
routing pneumatic
pump emissions).
VOC emission control devices Source-wide 95.0 percent 98.0 percent 95.0 percent 95.0 percent If required to
(Sec. 49.4177). potential for VOC continuously. continuous VOC continuous VOC continuous VOC control glycol
emissions from control control control dehydrator or
the collection of efficiency for efficiency. efficiency. storage vessel
all storage Issued Utah HAP emissions,
vessels, Permit must reduce HAP
dehydrators and Requirements by 95.0 percent,
pneumatic pumps (BACT for site- or maintain <20
>=4 tpy. specific & parts per million
general approval volume (ppmv) or
orders). 1 tpy benzene.
95 percent
continuous
control
efficiency for
Utah Oil and Gas
Rules.
[[Page 75350]]
Fugitive emissions VOC emission Source-wide NA-Semi-annual Utah Oil and Gas For natural gas For well sites and Ensure closed-vent
control requirements (Sec. potential for VOC surveys. Rules--semi- processing plants compressor system operates
49.4178). emissions from annual surveys at constructed, stations with no
the collection of all registered reconstructed, or constructed, detectable
all storage well sites modified after reconstructed or emissions if
vessels, required to August 23, 2011, modified after required to
dehydrators and control storage and on or before September 18, control glycol
pneumatic pumps vessel and/or September 18, 2015--Fugitive dehydrator or
>=4 tpy. dehydrator VOC 2015--LDAR emissions surveys storage vessel
Or................ emissions. requirements as using OGI HAP emissions.
Well site Issued Utah Permit referenced in conducted
production >15 Requirements NSPS VVa, with semiannually
boe per day (sources exempt periodic EPA (well sites) and
(rolling from Utah Oil and Method 21 surveys quarterly
consecutive 12- Gas Rules) on specific (compressor
month average). require LDAR, equipment types. stations).
ranging from For natural gas
annual to processing plants
quarterly for all constructed,
approved (i.e., reconstructed or
permitted) oil modified after
and natural gas September 18,
sources, 2015--LDAR
including requirements as
compressor referenced in
stations. NSPS VVa, with
periodic EPA
Method 21 surveys
on specific
equipment types.
Tank truck loading VOC emission None--applies to NA--Bottom filling Utah Oil and Gas Not covered....... Not covered....... Not covered.
control requirements (Sec. all existing or submerged fill Rules--more
49.4179). sources. pipe. stringent, as
capture and
control of VOC
emissions (95
percent
efficiency)
required at
registered
sources required
to control
storage vessel
and glycol
dehydrator
emissions.
Pneumatic controllers VOC NA--meet the Utah Oil and Gas For continuous For continuous Not covered.
emission control requirements standards of NSPS Rules--Meet bleed natural gas bleed natural gas
(Sec. 49.4180). OOOO or OOOOa. standards of NSPS driven pneumatic driven pneumatic
OOOO. controllers controllers
constructed, constructed,
reconstructed or reconstructed or
modified after modified after
October 15, 2013 September 18,
and on or before 2015, zero-bleed
September 18, for processing
2015, zero-bleed plants and low-
for processing bleed (<6 scfh)
plants and low- elsewhere.
bleed (<6 scfh)
elsewhere.
Other combustion devices (Sec. NA--must be Utah Oil and Gas Not covered....... Not covered....... Not covered.
49.4181). equipped with Rules--must be
automatic equipped with
ignition device. automatic
ignition device.
--------------------------------------------------------------------------------------------------------------------------------------------------------
1. Storage Vessels, Glycol Dehydrators, and Pneumatic Pumps
For existing, new, and modified sources, we are finalizing in 40
CFR 49.4173 (Storage vessel VOC emission control requirements), 40 CFR
49.4174 (Dehydrators VOC emission control requirements), and 40 CFR
49.4175 (Pneumatic pumps VOC emission control requirements) the
requirement that owners and operators of affected storage vessels,
glycol dehydrators, and natural gas-driven pneumatic pumps either: (1)
reduce VOC emissions from flashing, working, standing, and breathing
losses from the collection of all crude oil, condensate, intermediate
hydrocarbon and produced water storage vessels, 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 the collection of all
storage vessels, glycol dehydrators, and pneumatic pumps at a rate of
less than 4 tpy. We are finalizing the requirement 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 requiring that applicability be determined using potential for VOC
emissions. Potential for VOC emissions must be calculated using a
generally accepted model or calculation methodology based on the
maximum average daily throughput, as determined for existing sources
using the highest 30-day period of production in the 12 consecutive
months before the compliance deadline of the rule for each affected
source. The determination may take into account requirements under
legally and practicably enforceable limits in an applicable operating
permit or other applicable federal requirement, such as those in NSPS
OOOO or OOOOa, or NESHAP HH. For oil and natural gas sources that begin
operation or modification after the effective date of the final rule,
we are requiring that applicability for glycol dehydrators and
pneumatic pumps be determined using potential to emit VOC, and that
emissions from the collection of all storage vessels be controlled upon
startup for a minimum of 12 consecutive months. This requirement for
new and modified storage vessels is being finalized 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 the collection of
all storage vessels, glycol dehydrators, and pneumatic pumps are
demonstrated to be less than 4 tpy.
We are requiring that owners or operators demonstrate that the
source-wide uncontrolled actual VOC emissions from the collection of
all
[[Page 75351]]
crude oil, condensate, intermediate hydrocarbon liquids and produced
water storage vessels, 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 final rule requires that the owner or operator re-evaluate the
source-wide uncontrolled actual VOC emissions 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, 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
finalizing an exemption to the VOC emissions control requirements for
each emergency storage vessel that meets the following requirements:
(1) the storage vessel is not used as an active storage vessel; (2) the
owner or operator empties the storage vessel no later than 15 days
after receiving fluids; (3) the storage vessel is equipped with a
liquid level gauge or equivalent device; and (4) records of the use of
each vessel are kept indicating the date the vessel received fluids or
was discovered to have received fluids, the date the vessel was emptied
and the volume of fluids emptied in barrels.
The final VOC emissions control applicability provisions and other
requirements are the same as or comparable on balance with the
requirements in the Utah Permit Requirements and/or Utah Oil and Gas
Rules. The methods for determining applicability of the control
requirements are the same as those 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 the collection of all storage vessels,
glycol dehydrators, and pneumatic pumps at oil and natural gas sources
\84\ when the source-wide potential for VOC emissions from that
equipment is 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 Indian country
lands within the U&O Reservation.\85\ The methods for determining
applicability of the control requirements are comparable on balance
with the UDEQ's recently adopted Utah Oil and Gas Rules, except that
those rules do not consider emissions from or control of pneumatic
pumps.\86\ The reason for this difference is discussed later when we
describe this FIP's requirements for pneumatic pumps. The Utah Oil and
Gas Rules require all new and modified storage vessels (i.e., those
that begin operation on or after January 1, 2018) to control emissions
upon startup of operation for a minimum of one year. The requirement in
this FIP to control emissions from the collection of all new and
modified storage vessels for at least 12 consecutive months, the
exemption for emergency storage vessels, and the provision allowing
removal of controls from the collection of all storage vessels, glycol
dehydrators, and pneumatic pumps are also the same as the requirements
in the Utah Oil and Gas Rules, with the exception of pneumatic pump
emissions and control mentioned earlier, which will be discussed in
more detail later.
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\84\ The docket for this rulemaking 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 potential for 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.
\85\ The RIA in the docket for this rulemaking (Docket ID No.
EPA-R08-OAR-2015-0709) contains more detailed information on our
analyses.
\86\ 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
rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
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We are finalizing the option that the owner or operator capture and
route all subject emissions through a closed-vent system to an enclosed
combustor or 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 established under conditions
specified in 40 CFR 49.4176 (VOC emission control requirements for
covers and closed-vent systems), and requirements for operation and
monitoring of control devices are established under conditions
specified in 40 CFR 49.4177 (VOC Emission Control Devices) and 40 CFR
49.4182 (Monitoring Requirements), all of which are discussed in detail
below in the summaries of Covers, Closed-Vent Systems, and VOC Emission
Control Devices and Monitoring Requirements.
We are finalizing the alternative option that the owner or operator
design operations to recover 100 percent of the emissions and recycle
them for use in a process unit or incorporate them into a product.
These control options are the same as the Utah Permit Requirements and
the Utah Oil and Gas Rules.
As described earlier, regulating pneumatic pumps in this U&O FIP is
not comparable to the UDEQ's Utah Oil and Gas Rules, because those
rules do not include requirements for pneumatic pumps.\87\ But the
approach in this U&O FIP to controlling pneumatic pumps by routing
emissions to the same control device that controls emissions from the
collection of all storage vessels and glycol dehydrators is the same as
the UDEQ's approach to controlling pneumatic pumps in site-specific
approval orders issued under Utah Permit Requirements. We are confident
that this approach will help achieve ozone air quality improvements
through this U&O FIP, as the UBEI2017-Update shows that VOC emissions
from pneumatic pumps constitute 16 percent of the total oil and natural
gas-related VOC emissions on Indian country lands within the U&O
Reservation.\88\
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\87\ We note that the Utah Oil and Gas Rules do not contain
requirements for pneumatic pumps. We are finalizing 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.
\88\ By contrast, the UBEI2017-Update shows that there are a
very low number of pneumatic pumps installed and operating on lands
in areas of the Basin where the EPA has approved the UDEQ to
implement the CAA; 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 existing oil and
natural gas sources that would meet the applicability criteria of this
U&O FIP will also be subject to NSPS OOOO or OOOOa, or NESHAP HH.
However, to address any potential regulatory overlap, we are providing
that any affected storage vessels, glycol dehydrators, or pneumatic
pumps that
[[Page 75352]]
are subject to the emissions control requirements in those EPA
standards, are not subject to the requirements in this U&O FIP for such
equipment and activities, including monitoring, recordkeeping, and
reporting requirements associated with such equipment and activities.
2. Covers, Closed-Vent Systems
For affected existing, new, and modified sources that are required
to control emissions from the collection of all storage vessels, glycol
dehydrators and pneumatic pumps per 40 CFR 49.4173 through 49.4175, we
are finalizing in 40 CFR 49.4176 (VOC emission control requirements for
covers and closed-vent systems) to require, as applicable, the use of
covers on all storage vessels, and the use of closed-vent systems with
equipment that captures and routes VOC emissions to the respective
vapor recovery or VOC emission control devices. Because closed-vent
systems are common to control requirements for storage vessels, glycol
dehydrators and pneumatic pumps, we are finalizing these requirements
in a separate section to avoid redundancy. Section 49.4176 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 existing, new, and modified sources
that are required to control emissions from the collection of all
storage vessels, glycol dehydrators and pneumatic pumps, in 40 CFR
49.4177 (VOC emission control devices) we are finalizing specific
legally and practicably enforceable construction and operational
requirements for enclosed combustors and flares.
We are finalizing in 40 CFR 49.4176 (VOC emission control
requirements for covers and closed-vent systems) the requirement that
each owner or operator equip the openings on each affected storage
vessel with a cover that ensures that flashing, working, standing and
breathing losses are efficiently routed through a closed-vent system to
a vapor recovery system, an enclosed combustor, or a flare. We are
finalizing the requirement that each cover and all openings on the
cover (e.g., access hatches, sampling ports, and gauge wells) form a
continuous barrier over the entire surface area of the crude oil,
condensate, intermediate hydrocarbon liquids or produced water in the
storage vessel. 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 storage vessel 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 requiring 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 be maintained and operated properly at all times, and
that they 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 requiring that the owner
or operator 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 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 vessel thief hatches to be
closed and latched except during storage vessel unloading or other
maintenance activities. They also require that thief hatches be
inspected once every three months to ensure that thief hatches are
closed and latched, and that any associated gaskets 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. The U&O FIP requirements for covers and
closed-vent systems were developed by consulting the cover and closed-
vent system requirements of EPA standards, such as OOOO and OOOOa 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 existing, new, and modified sources that are required to
control VOC emissions from the collection of all storage vessels,
glycol dehydrators and pneumatic pumps, we are finalizing requirements
in 40 CFR 49.4177 (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 flare. Each 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 95.0 percent continuously. The
control efficiency required for each VOC emissions control device is
the same as the 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 U&O FIP, 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 vessels, glycol dehydrators or pneumatic
pumps) to the operating combustor, 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 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
[[Page 75353]]
more, on average, in practice when properly operated.\89\ Combustion
devices designed to meet 98.0 percent control efficiency may not,
however, be able to meet this efficiency level continuously in
practice, due to factors such as the variability of field conditions
and downtime.
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\89\ The EPA has 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 be able to continuously meet a
95.0 percent control efficiency level when they are designed,
monitored and operated in a way that ensures effective performance
on a continuous basis. 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) able to be continuously achieved by affected facilities (e.g.,
storage vessels, centrifugal compressors) nationwide. The EPA is aware
that enclosed combustors and flares may be capable of achieving
instantaneous control efficiencies greater than 95.0 percent,\90\ but
in determining BSER the EPA must be confident that the control
efficiency can be achieved continuously by affected facilities
nationwide to which it applies. We are confident that combustors and
flares can meet at least 95.0 percent VOC control efficiency on a
continuous basis when they are designed, monitored and operated in a
way that ensures effective performance 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,\91\ we are not confident that
the devices can achieve 98.0 percent continuous VOC control efficiency
in the field without stronger flare performance requirements than are
currently in effect today.\92\
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\90\ 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, 76 FR 52738 (Aug. 23, 2011), available at https://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)).
\91\ See Combustion Device Performance Testing Summary Table in
the docket for this rule.
\92\ The Oil and Natural Gas Sector Climate Review Proposed Rule
is soliciting comment and information that would help us better
understand the cost, feasibility, and emission reduction benefits
associated with establishing a 98 percent control efficiency
requirement for flares in the Crude Oil and Natural Gas source
category, including information on the level of performance being
achieved in practice by flares in the field, what conditions or
factors contribute to malfunctions or poor performance at these
flares, and what measures the EPA could or should require in order
to ensure that flares perform at a 98 percent level of control. See
86 FR 63110 (Nov. 15, 2021).
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We are requiring that all flares installed per this rule be
designed and operated in accordance with applicable requirements in 40
CFR 60.18(b).\93\ We are requiring that all enclosed combustors
installed per this rule be models: (1) that have been tested by the
manufacturer in accordance with specific requirements in NSPS OOOO and
OOOOa; or (2) for which the owner or operator has conducted performance
testing according to the requirements in NSPS OOOO and OOOOa. The Utah
Oil and Gas Rules require that compliance for VOC control devices be
demonstrated by meeting the performance test methods and procedures in
NSPS OOOO. The Utah Oil and Gas Rules do not distinguish between flares
and enclosed combustors. We determined, though, that it was important
to have specific requirements for the different types of control
devices that may be present at oil and natural gas sources on Indian
country lands within the U&O Reservation, because EPA standards
including NSPS OOOO and OOOOa and NESHAP HH make such distinctions for
legal and practical enforceability. Therefore, although for ease of
implementation this FIP's requirements for VOC control devices to
demonstrate compliance with the control efficiency requirements are
more detailed than the state's, they are comparable on balance with the
Utah Oil and Gas Rules that reference such requirements in NSPS OOOO,
as well as with NSPS OOOO and OOOOa and NESHAP HH.
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\93\ 40 CFR 60.18(b) for flares requires compliance with 40 CFR
60.18(c) through (f).
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We determined that certain work practice and operational
requirements are also necessary for the practical enforceability of the
VOC emission reduction requirements for flares or enclosed combustors.
We are requiring that flares and enclosed combustors be operated within
specific parameters to ensure the effective control of VOC
emissions.\94\ Specifically, we are requiring that each owner or
operator ensure that each enclosed combustor or flare is: (1) operated
at all times that emissions are routed to it; (2) equipped and operated
with a liquid knockout system to collect any condensable vapors (to
prevent liquids from going through the control device); (3) equipped
and operated with a flashback 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 flare; (6) maintained in a leak-free
condition; and (7) operated with no visible smoke emissions. These work
practice and operational requirements are comparable to requirements of
the Utah Oil and Gas Rules with respect to operation of the control
devices with no visible emissions.
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\94\ The necessity of such a requirement was discussed in detail
in the preamble and Technical Support Documents to the proposed and
final NSPS OOOO. These documents can be found in the docket for the
NSPS OOOO rulemaking (Docket ID EPA-HQ-OAR-2010-0505), available at
https://www.regulations.gov.
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To ensure legal and practical enforceability, other work practice
and operational requirements in this U&O FIP are different or more
prescriptive than the Utah Oil and Gas Rules in several areas. For
example, the Utah Oil and Gas Rules require all VOC emissions control
devices simply to be equipped and operated with an operational
automatic ignition device. This U&O FIP, on the other hand, requires
each enclosed combustor or flare to be equipped and operated with
either a continuous burning pilot flame or an electronically controlled
automatic ignition device. Further, under this FIP all enclosed
combustors and 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
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. Regarding
[[Page 75354]]
the requirement to equip enclosed combustors and flares with either 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 the
position as recently as 2016 that without a continuous ignition source,
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.\95\ Therefore, we
have maintained that automatic ignition devices alone 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 the final
FIP requires compliance with 40 CFR 60.18(c)(2) \96\ of the General
Provisions for 40 CFR part 60 when using a flare, a continuous pilot
flame is required, and we have determined that an equivalent
requirement should be applicable to enclosed combustion control devices
used for controlling emissions from storage vessels and other equipment
at affected oil and natural gas sources.
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\95\ The 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 (Docket ID
EPA-HQ-OAR-2010-0505-7632), available at https://www.regulations.gov, accessed Mar. 14, 2022.
\96\ Per 40 CFR 60.18(b).
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We recognize that the UDEQ requires automatic ignition devices on
all combustion devices. In the interest of establishing regulations on
Indian country lands within the U&O Reservation that are comparable on
balance with the UDEQ requirements, we are finalizing a hybrid approach
that allows owners and operators required to control VOC emissions from
the collection of all storage vessels, 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 requirements
for control devices will achieve a result comparable to the
requirements for VOC control devices in the Utah Oil and Gas Rules and
will ensure that the control device is operated properly to achieve the
required control efficiency while providing consistency with EPA policy
regarding flares and combustors.
Section 49.4177 allows owners or operators of oil and natural gas
sources, on receiving written approval, to use control devices other
than an enclosed combustor or flare, provided they continuously achieve
at least 95.0 percent VOC control efficiency. We expect that this
provision will allow owners and operators to take advantage of
technological advances in VOC emission control in the oil and natural
gas industry, and that it will provide us with valuable information on
new control technologies.
4. Fugitive Emissions Control
For existing, new, and modified sources, we are finalizing LDAR
requirements in 40 CFR 49.4178 (Fugitive emissions VOC emission control
requirements) that each owner or operator of an oil and natural gas
source conduct periodic inspections of the source to detect leaks from
fugitive emissions components and repair them if either of the
following is true: (1) the collection of fugitive emissions components
is located at an oil and natural gas source that is required to control
VOC emissions according to 40 CFR 49.4173 through 49.4177 of this FIP
(i.e., the source-wide potential for VOC emissions from the collection
of all storage vessels, glycol dehydrators, and pneumatic pumps is
equal to or greater than 4 tpy, as determined according to 40 CFR
49.4173(a)(1)); or (2) the collection of fugitive emissions components
is located at a well site, as defined in 40 CFR 60.5430a, that at any
time has total production greater than 15 boe per day based on a
rolling 12-month average.\97\ Owners and operators of the collection of
fugitive emissions components for which neither of the aforementioned
conditions are true have the option to either (1) implement a program
of periodic fugitive emissions inspections and repair, or (2)
demonstrate that the total daily oil and natural gas production of the
collection of all wells producing to the well site is at or below 1 boe
per day, based on a 12-month rolling average, calculated according to
specific procedures specified in 40 CFR 49.4178(e). Owners and
operators of the collection of fugitive emissions components at an oil
and natural gas source that is subject to the fugitive emissions
monitoring requirements of NSPS OOOOa are exempt from this FIP's
fugitive emissions monitoring requirements for those components.
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\97\ As explained earlier, the Oil and Natural Gas Sector
Climate Review Proposed Rule proposes a different approach for LDAR
applicability based on the level of facility wide methane fugitive
emissions. We are finalizing these requirements in the interest of
taking action now to reduce VOC emissions on the Indian country
lands within the U&O Reservation and recognizing the advantages of
maximizing emissions reductions while providing a measure of
consistency with the UDEQ and federal requirements that are in
effect today. We may revisit this rulemaking in the future based on
any final action we take under CAA section 111 with the Oil and
Natural Gas Sector Climate Review rulemaking.
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We are finalizing a definition of ``fugitive emissions component''
in 40 CFR 49.4171, consistent with the approach in NSPS OOOOa, that
includes valves, connectors, open-ended lines, pressure relief devices,
flanges, covers and closed-vent systems not subject to 40 CFR 49.4173
through 49.4175, thief hatches or other openings on controlled storage
vessels not subject to 40 CFR 49.4173, compressors, instruments and
meters.\98\ Each owner or operator is required to develop and implement
a Reservation-wide fugitive emissions monitoring plan for all of its
affected oil and natural gas sources on Indian country lands within the
U&O Reservation that must include the following elements, at a minimum:
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\98\ 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.
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(1) Conduct an initial monitoring of fugitive emissions components
at each affected source within 12 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 (limited to onsite optical gas imaging instruments, with a leak
defined as any visible emissions using an optical gas imaging
instrument, EPA Reference Method 21, with an instrument reading of 500
parts per million volume (ppmv) VOC defined as a leak, 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.
[[Page 75355]]
(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 discovering a
leak, and identification of timeframes (which must be no later than the
next required monitoring event after discovering the leak) to repair
leaks that are designated as difficult-to-monitor or unsafe-to-monitor,
or which require source shutdown. If the repair or replacement of a
fugitive emissions component designated difficult-to-monitor or unsafe-
to-monitor is technically infeasible, would require a vent blowdown, a
compressor station shutdown, a well shutdown or shut-in, or would be
unsafe to repair \99\ during operation of the unit, the repair or
replacement must be completed during the next scheduled compressor
station shutdown, well shutdown, well shut-in, after a planned vent
blowdown, or within 2 years, whichever is earlier.
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\99\ ``Unsafe to repair'' is defined in the final 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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(6) Procedures for verifying effective repair of leaking
components, no later than 30 days after repairing a leak.
(7) Specific training and experience needed to perform inspections.
(8) Description of procedures for calibration and maintenance of
any fugitive emissions monitoring device to be used.
(9) Standard monitoring protocols for each type of typical affected
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).
We are finalizing in 40 CFR 49.4179 an exemption for source owners/
operators from having to monitor and repair a fugitive emissions
component under certain circumstances: (1) the contacting process
stream only contains glycol, amine, methanol or produced water; or (2)
the component 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 in a manner that prevents access by a
monitor probe or optical gas imaging device.
The fugitive emissions LDAR requirements in this U&O FIP are
designed to be consistent with those in NSPS OOOOa. In developing the
final FIP LDAR requirements, we also reviewed the UDEQ requirements.
For existing, new, and modified sources subject to the Utah Oil and Gas
Rules, the LDAR requirements were designed to be procedurally
consistent with NSPS OOOOa, though the applicability threshold is
different. The UDEQ's site-specific approval orders, a general approval
order (GAO) for crude oil and natural gas well sites and tank
batteries,\100\ and the 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.
The Utah Oil and Gas Rules require semi-annual fugitive emissions
monitoring and repair for any affected source. Existing oil and natural
gas sources that were authorized under the UDEQ's site-specific
approval orders are required to conduct fugitive emissions monitoring
and repair at frequencies ranging from annual to quarterly. Existing
oil and natural gas sources that are authorized under the UDEQ's GAO
are subject to fugitive emissions monitoring at varying frequencies
based on production levels and number of leaks detected.
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\100\ The docket for this rulemaking (Docket ID No. EPA-R08-OAR-
2015-0709) contains an approval for coverage under the GAO for a
Crude Oil and Natural Gas Well Site and/or Tank Battery (DAQE-
MN149250001-14).
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The final FIP applicability threshold is consistent in part with
the UDEQ's LDAR applicability threshold, though the final FIP also
requires any additional sources where daily production exceeds 15 boe
per day to conduct an LDAR inspection program, which is consistent in
part with NSPS OOOOa. The LDAR inspection frequency requirements of
this U&O FIP are the same as the Utah Oil and Gas Rules and NSPS OOOOa.
For oil and natural gas sources that may have obtained coverage under
the UDEQ's approval orders or the GAO, we concluded that the UDEQ's
LDAR inspection frequency requirement is different than the LDAR
inspection frequency requirements for oil and natural gas sources under
this U&O FIP, which may require monitoring frequencies for only certain
sources that are equivalent to this U&O FIP.
We are finalizing 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. We are finalizing language specifying that to be
approved by the EPA, a demonstration that the alternative method
achieves emissions reductions that equal or exceed those that would
result from the application of either Method 21 or optical gas imaging
instruments must be made and any proposed approval by the EPA will be
subject to public notice and comment.
5. VOC Emissions Control Requirements for All Sources
Sections 49.4179 (VOC emission control requirements for tank truck
loading), 49.4180 (VOC emission control requirements for pneumatic
controllers) and 49.4181 (Other combustion devices) contain
requirements for all existing, new, and modified 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 areas of the Basin where the EPA has
approved the UDEQ to implement the CAA, the U&O FIP's requirements are
as follows: (1) tank trucks used for transporting crude oil,
condensate, intermediate hydrocarbon liquids 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,
flares present and operating at sources on a voluntary basis--that is,
those that are not required to control storage vessel, glycol
dehydrator, and pneumatic pump emissions (per 40 CFR 49.4173 through
49.4175)--must be equipped with an electronically controlled automatic
ignition device.
Our requirements for truck loading/unloading diverge in one respect
from what the UDEQ is requiring in the Utah Oil and Gas Rule. The UDEQ
requires that VOC emissions from tank truck loading and unloading at
sources required to control storage vessel emissions be captured using
a vapor capture line and routed to the onsite combustor or a separate
combustor for VOC control. We are not finalizing an equivalent
requirement at this time, as we did not receive sufficient cost and
emissions reduction information during the public comment period for
this rulemaking to sufficiently evaluate the cost effectiveness of such
a requirement for the limited estimated emissions for truck loading/
unloading on Indian country lands within the U&O Reservation, based on
the UBEI2017-
[[Page 75356]]
Update.\101\ The inventory identifies 595 tpy VOC from truck loading/
unloading. Assuming that the annualized cost to install a vapor capture
line to an existing combustor is similar to that of routing pneumatic
pump emissions to a combustor (approximately $1,627 per source) and
assuming that there are approximately 2,165 sources that would be
required to add a combustor, such a requirement to install an
additional truck vapor capture line would result in high annualized
costs relative to the VOC emissions reductions that would be achieved
(over $6,000 per ton of VOC reduced per year).
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\101\ The Oil and Natural Gas Sector Climate Review Proposed
Rule is soliciting comment and information that would help us better
understand the cost, feasibility, and emission reduction benefits
associated with controlling truck loading/unloading emissions. As
with LDAR applicability, we may revisit this rulemaking in the
future based on any final action we take under CAA section 111 with
the Oil and Natural Gas Sector Climate Review rulemaking.
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Concerning pneumatic controllers, the U&O FIP adopts by reference
the definitions of natural gas-driven pneumatic controller in NSPS OOOO
and OOOOa (40 CFR 60.5430 and 60.5430a, which are identical) and
requires owners/operators of affected pneumatic controllers (those
controllers not subject to and controlled in accordance with the
requirements for pneumatic controllers in NSPS OOOO or OOOOa) to meet
the standards established for pneumatic controllers in NSPS OOOO. We
are finalizing the requirement that owners/operators of affected
controllers meet the tagging requirements in 40 CFR 60.5390(b)(2),
60.5390(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, flares present and
operating at sources that would not be required to comply with the
substantive VOC emissions control requirements of sections 40 CFR
49.4173 through 49.4177, we are finalizing a requirement 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. In contrast to the 40 CFR
49.4177 (VOC Emission Control Devices) requirements for devices used to
comply with this FIP's substantive VOC emissions control requirements,
we determined that it would be unreasonable to require voluntarily
operated devices to have 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, and that such a requirement would
result in requirements for such sources on Indian country lands within
the U&O Reservation that are not comparable to requirements for such
sources in areas where the EPA has approved the UDEQ to implement the
CAA.
G. Monitoring and Testing Requirements
For existing, new, and modified sources, in 40 CFR 49.4182
(Monitoring and testing requirements) we are requiring each owner or
operator to conduct source monitoring necessary for the practical
enforceability of the U&O FIP's VOC emission reduction requirements,
including: (1) monthly inspections of each cover and closed-vent
system, including storage vessel openings, thief hatches, pressure
relief valves, and bypass devices, to ensure proper condition and
functioning and for defects that can result in air emissions consistent
with the procedures in 40 CFR 60.5416a(c) [NSPS OOOOa], correcting or
repairing any defects identified within 30 days of identification; and
(2) monthly inspections of each VOC emissions control device to ensure
proper functioning and demonstrate compliance with the VOC emissions
control device requirements by (a) checking the control device and
parameter monitoring system for proper operation, including system
integrity and leak-free operation, at least once per calendar month;
(b) responding to any indication of pilot flame failure and ensuring
the pilot flame is relit as soon as practicably and safely possible
after discovery; and (c) monitoring visible emissions consistent with
the requirements in 40 CFR 60.5412(d), using EPA Method 22 visual
emissions testing to demonstrate there are no visible smoke emissions.
These monitoring requirements are comparable on balance to 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 this
FIP's 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.
H. Recordkeeping Requirements
For existing, new, and modified sources, in 40 CFR 49.4183
(Recordkeeping Requirements) we are requiring 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 required
inspections, 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.
I. Notification and Reporting Requirements
For existing, new, and modified sources, we are finalizing in 40
CFR 49.4184 (Notification and reporting requirements) to require that
each owner or operator of an affected oil and natural gas source
prepare and submit an annual compliance report, with the initial report
due April 1st of the calendar year following the effective date of the
final rule and must cover all affected operations for the previous
calendar year on and after the effective date of the final rule.
Subsequent annual reports are due on the same date each year as the
date the initial annual report was submitted and must cover all
affected operations for the previous calendar year. The report must
include a summary of deviations or exceedances of any requirements of
the final FIP and the corrective measures taken for a specific subset
of targeted required records for each enclosed combustor or flare, each
cover and closed-vent system, fugitive emissions monitoring inspection,
and each high-bleed controller, as identified in the rule. Annual
reports may coincide with Title V, NSPS OOOO or OOOOa or NESHAP HH
reports as long as all the required elements of the annual report are
included. 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.
[[Page 75357]]
V. Significant Changes Since Proposal
This U&O FIP, which is intended to address winter air quality
impacts from ozone pollution, contains a common set of VOC emissions
control requirements for certain existing, new, and modified oil and
natural gas sources on the Indian country lands within the U&O
Reservation. We consulted existing federal CAA oil and natural gas
source category standards in developing the VOC emissions control
requirements of this U&O FIP. To make VOC emissions control
requirements across the Basin consistent, this U&O FIP goes beyond the
federal standards in some cases, regulating equipment and activities
that are not covered by those standards but that are regulated by the
UDEQ. Such equipment and activities include small, remote glycol
dehydrators; low throughput storage vessels; tank truck loading and
unloading; and certain voluntarily operated control devices.
Applicability of the 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.
As previously mentioned, 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 separate action amending
the National O&NG FIP. 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, does not
relieve the owners/operators from the other applicable VOC control
requirements of this U&O FIP, except that this U&O FIP exempts certain
equipment and activities from it that are in compliance with the
applicable requirements of the National O&NG FIP.
We have made some changes to the requirements in the U&O FIP after
considering public comments and evaluating more recent emissions
inventories and air quality information. More details on our evaluation
of available information and reasons for these decisions are described
in our summary of responses to comments in Section VI of this preamble,
and in the RIA and Response to Public Comments documents for this final
rule.\102\
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\102\ These documents can be found in the docket for this
rulemaking (Docket ID EPA-R08-OAR-2015-0709).
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A. Final Rule Effective Date and Compliance Deadline
In the proposed U&O FIP, we stated that we might issue a final
action based on the proposal as soon as the date of publication of a
final U&O FIP. We believed that there would be ``good cause,'' within
the meaning of 5 U.S.C. 553(d)(3), to make the final rule effective as
soon as published, if that proved necessary to ensure that this rule
began 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 final 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 Indian country lands within 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 achieved through this action to ensure that the previous
extension of the scope of the National O&NG FIP does not jeopardize air
quality.
After careful consideration of the comments received, and of the
requirements under the Congressional Review Act (CRA) specifying that a
major rule may become effective no earlier than 60 days after it is
published in the Federal Register,\103\ the EPA is finalizing an
effective date 60 days after the final rule is published in the Federal
Register.
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\103\ Id. at 5 U.S.C. 801(a)(3)(A). This rule is considered an
economically significant rule under Executive Order 12866, as a rule
that imposes costs or generates benefits of at least $100 million
per year, which is the same economic threshold applied in defining
what constitutes a ``major rule'' under the CRA (one that ``is or is
likely to result in . . . an annual effect on the economy of
$100,000,000 or more.'').
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We proposed to require compliance by oil and natural gas sources
existing as of the effective date of the final rule no later than 18
months after the effective date of the final rule. We have revised that
compliance period to a 12-month compliance deadline. The proposed 18-
month compliance period was informed by what we had learned about the
time needed for sources in areas of the Basin where the EPA has
approved the UDEQ to implement the CAA to comply with Utah's
requirements for oil and natural gas sources. We had been informed by
UDEQ compliance staff that the majority of existing oil and natural gas
sources in areas of the Basin where the EPA has approved the UDEQ to
implement the CAA that had been required to install VOC emission
control retrofits in had 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.\104\ The UDEQ
estimated that approximately 1,600 existing sources had been required
to install retrofits to control emissions from the collection of all
storage vessels, glycol dehydrators, and/or pneumatic pumps on non-
Indian country lands in the Uinta Basin. For the proposal, on the other
hand, we estimated that there were approximately 2,100 sources on
Indian country lands within the U&O Reservation that would be subject
to such requirements in this U&O FIP. We considered it likely in light
of this larger number of sources, and the presumably finite
availability of equipment and personnel, that owners and operators
would need longer than 9 months to complete the necessary retrofits to
the greater number of Indian country sources. Therefore, we proposed an
18-month compliance deadline for the U&O FIP as reasonable to
accommodate the challenges of procurement of equipment and labor to
complete the retrofits of a larger number of sources. Using the
UBEI2017-Update, we now estimate that 2,165 existing sources on the
Indian country lands within the U&O Reservation will be required to
install retrofits to control emissions from the
[[Page 75358]]
collection of all storage vessels, glycol dehydrators, and pneumatic
pumps under this U&O FIP, which is only slightly more than the number
of existing affected sources estimated for the proposed FIP using the
UBEI2014.
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\104\ Email correspondence with UDEQ staff regarding their
source inventory and experiences regulating existing oil and natural
gas sources in areas of the Basin where the EPA has approved the
UDEQ to implement the CAA 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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Although the number of estimated affected sources is still higher
than the number in areas where the EPA has approved the UDEQ to
implement the CAA, after considering public comments received on the
proposed 18-month compliance deadline and the demonstrated need for
more near-term air quality benefits to improve air quality in and
around the U&O Reservation, we have revised the proposed 18-month
compliance period to a 12-month compliance period from the effective
date of the rule. In the EPA's judgment, this shorter compliance
schedule (especially when combined with the 60-day effective date) will
sufficiently accommodate the potentially limited availability of
equipment and personnel, and thus still reasonably allow industry to
comply with the new requirements in a timely manner, while also
ensuring that meaningful reductions will be achieved that will help
make progress toward future attainment. Further, potentially affected
owners and operators have been on notice of the possibility that these
rules might come into effect since the proposed FIP was published in
January 2020.
We also enhanced the final FIP to specify the process the EPA would
take to decide requests for extension of the compliance period, in
particular adding the requirement that the request be submitted before
the compliance deadline, identify the specific provisions for which an
extension is being requested and include an alternative compliance
deadline, and provide a rationale for the request with supporting
information explaining how the operator will effectively meet all
applicable requirements after the requested alternative compliance
deadline.
B. Triennial Emissions Inventory
In the proposed FIP we contemplated establishing the due date for
the submittal of annual emissions covering the first triennial
inventory year 2020 as October 1, 2021, to allow operators time to set
up an appropriate emissions tracking and reporting system. However,
given the time that has elapsed since the proposal, we are revising the
proposal to require the first triennial emissions inventory to cover
calendar year 2023, with the first inventory due on April 15, 2024, and
thereafter, every three years, the inventory will be due on April 15th
of the year following the inventory year. This is in line with the
UDEQ's triennial emissions inventory collection, and the schedule for
the NEI. This revised schedule will also allow additional time for
operators to set up an appropriate emissions tracking and reporting
system, according to the instructions we will make available on our
website for the rule once it is finalized.
C. Streamlined Construction Authorization
In the proposed FIP we contemplated moving the authority for
streamlined construction authorization mechanism of 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
in the National O&NG FIP (through 40 CFR part 49, subpart K) to this
FIP, so as to consolidate air quality requirements for oil and natural
gas sources in the Indian country portions of the U&O Reservation that
are part of the Uinta Basin Ozone Nonattainment Area within one part of
the Code of Federal Regulations, which we believed could provide a more
efficient and user-friendly approach. However, we have decided not to
finalize that approach in this FIP because, after further
consideration, including consideration of public comments received, we
believe that modifying the National O&NG FIP is unnecessary.
D. Applicability
In the proposed FIP, we defined some terms, such as storage tank,
pneumatic pump, pneumatic controller, and fugitive emissions component,
in a way that were different from the definitions of equivalent
equipment and activities in NSPS OOOO and OOOOa. The proposed FIP was
designed in part for consistency with NSPS OOOO and OOOOa and the Oil
and Gas CTG, and for consistency with the Utah Oil and Gas Rules (which
were also designed for consistency with NSPS OOOO and OOOOa). After
considering public comments received, and for ease of implementation
and compliance, we have revised the proposed definitions, and are
finalizing definitions that are consistent with those in NSPS OOOO and
OOOOa.
Another difference with NSPS OOOO and OOOOa and the Oil and Gas CTG
that was identified in comments on the proposed FIP is in the method
used to calculate VOC emissions from the collection of all storage
vessels to determine applicability of the control requirements for
storage vessels, glycol dehydrators and pneumatic pumps in 40 CFR
49.4173 through 49.4177. We proposed that VOC emissions from the
collection of all storage vessels should be calculated based on
uncontrolled actual emissions. To provide consistency with NSPS OOOO
and OOOOa and the Oil and Gas CTG, we are finalizing requirements that
VOC emissions from the collection of all storage vessels be calculated
based on potential emissions, which may account for enforceable control
requirements already applicable to certain storage vessels. 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 total VOC emissions from the
collection of all storage vessels are demonstrated to be less than 4
tpy of uncontrolled actual 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. 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 actual VOC emissions are demonstrated to be less than 4
tons per year. For sources that operate only storage vessels and not
glycol dehydrators or pneumatic pumps, the proposed 8,000 bbl of crude
oil/2,000 bbl of condensate throughput applicability threshold for
control of storage vessel emissions was the same as the control
applicability threshold for storage vessels in the UDEQ's recently
adopted Utah Oil and Gas Rules. However, based on public comments
received on the proposed rule, we decided not to finalize the
production-based threshold for oil and natural gas sources with only
storage vessels and no glycol dehydrators or pneumatic pumps. Several
commenters expressed the view that, while they appreciated the effort
to establish consistent requirements across all areas of the Basin,
determining applicability for VOC combustion control requirements would
be simpler and more straightforward if applicability was based solely
on the annual facility-wide VOC emissions threshold for storage
vessels, glycol dehydrators and pneumatic pumps of 4 tpy.
[[Page 75359]]
We noted in the preamble to the proposed U&O FIP 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-
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 had drafted and
evaluated the emissions reductions and costs of the provisions in the
proposed U&O FIP. We noted our intent to evaluate and consider
incorporating equivalent associated gas requirements in a final U&O
FIP. After careful consideration of the comments received and
evaluation of the data used to estimate associated gas emissions in the
UBEI2017-Update used to analyze the costs and benefits of this final
FIP, we have decided not to finalize requirements to control associated
gas emissions in the U&O FIP, because we do not have adequate
information specific to the Uinta Basin operations to accurately assess
and develop cost-effective requirements.
In the proposed U&O FIP, we based the applicability of the
requirement to implement a semiannual fugitive emissions monitoring
program on whether the oil and natural gas source was required to
control facility-wide emissions from the collection of all storage
vessels, glycol dehydrators, and pneumatic pumps. After considering
public comments on the proposed FIP, we have revised the proposed
fugitive emissions monitoring applicability, and in the final rule are
requiring semiannual fugitive emissions monitoring for each owner or
operator of an oil and natural gas source where either of the following
is true: (1) As proposed, the collection of fugitive emissions
components is located at an oil and natural gas source that is required
to control VOC emissions according to 40 CFR 49.4173 through 49.4177 of
this FIP (i.e., the source-wide potential for VOC emissions from the
collection of all storage vessels, glycol dehydrators, and pneumatic
pumps is equal to or greater than 4 tpy, as determined according to 40
CFR 49.4173(a)(1)); or (2) As revised, the collection of fugitive
emissions components is located at a well site, as defined in 40 CFR
60.5430a, that at any time has total production greater than 15 boe per
day based on a rolling 12-month average.
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 Updated 2017 Uinta Basin
Emissions Inventory (UBEI2017-Update),\105\ the average number of wells
per well pad is 1.5. The inventory shows that fugitive emissions are
the second highest VOC emissions source on Indian country lands within
the U&O Reservation, at about 15,600 tpy. Studies have been conducted
specific to the Uinta Basin that investigated the sources of VOC
emissions from oil and natural gas production operations. Certain high
emitting sources, or ``super-emitters,'' are likely due to abnormal
process conditions.\106\ Examples of abnormal process conditions, which
could be persistent or episodic, include: failures of storage vessel
control systems; malfunctions upstream of the point of emissions (for
example, stuck separator dump valve resulting in produced gas venting
from storage vessels); 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).\107\ A July 2017 study
by Utah State University, TriCounty Health Department, and the UDEQ
surveyed 400 oil and natural gas well pads using an IR camera for
fugitive emissions detection at storage vessels and found that
emissions plumes were detected at 37 percent of well pads where the
storage vessels were controlled. A November 2018 Utah State University
study employed a hybrid of both ground based and aerial IR detection
methods. The study found that the majority of observed fugitive
emissions plumes originated from storage vessels (over 75 percent) and
that facilities where emissions were detected were primarily younger,
high production facilities with more liquid storage vessels, and, in
the case of the aerial observations only, that primarily produce oil.
The study found that emissions that were more likely to be
characterized as large were observed at well pads with controlled
storage vessels. The emissions were observed upstream of the control
device, from thief hatches, vents and piping on the tanks. The results
of these two studies strongly suggest that a significant quantity of
emissions from controlled storage vessels were not reaching the
designated control device. Requiring owners and operators of oil and
natural gas sources that are required to control storage vessel,
dehydrator and pneumatic pump emissions to implement a LDAR program
will help reduce fugitive emissions from well sites with controlled
storage vessels. We acknowledge that the definition of fugitive
emissions component in the final U&O FIP excludes valves, connectors,
pressure relief devices, open-ended lines, flanges, covers, closed-vent
systems, thief hatches, and other openings associated with storage
vessels or closed-vent systems subject to the control requirements of
40 CFR 49.4173 and 49.4176. Those activities are subject to specific
integrity monitoring requirements in 40 CFR 49.4182, discussed later in
this section, to ensure that 100 percent of the emissions are routed
either to a process or an emissions control device. However, the LDAR
requirements of final 40 CFR 49.4177 do apply to components associated
with storage vessels and closed-vent systems that are not subject to
the requirements of 40 CFR 49.4173 and 49.4176. We expect that the
combination of the LDAR requirements of final 40 CFR 49.4177 and the
integrity monitoring requirements of final 40 CFR 49.4182 will
effectively reduce VOC emissions from equipment leaks at oil and gas
sources with controlled storage vessels.
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\105\ UBEI2017-Update. The inventory and supporting analysis can
be viewed in the docket for this rulemaking, Microsoft Excel
spreadsheet titled, ``UO FIP cost and emissions analysis.xlsx''
(Docket ID No. EPA-R08-OAR-2015-0709).
\106\ Zavala-Araiza, D., Alvarez, R. A., Lyon, D. R., Allen, D.
T., Marchese, A. J., Zimmerle, D. J., & Hamburg, S. P.; ``Super-
emitters in Natural Gas Infrastructure are Caused by Abnormal
Process Conditions,'' Nature Communications 8, 14012 (2017).
``Storage Tank Emissions Pilot Project (STEPP): Fugitive Organic
Compound Emissions from Liquid Storage Tanks in the Uinta Basin,''
Final Report to The Utah State Legislature (USU, TriCounty Health
Dept, UDEQ, July 17, 2017) available in the docket for this
rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
``Hydrocarbon Emission Detection Survey of Uinta Basin Oil and
Gas Wells''. November 2018. Bingham Research Center, Utah State
University, available in the docket for this rulemaking (Docket ID
No. EPA-R08-OAR-2015-0709).
\107\ The UBEI2017-Update has not accounted for the phenomenon
of ``super-emitters.''
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We determined that to maximize VOC emissions reductions and the
resulting expected improvements in air quality on the U&O Reservation
and surrounding areas, finalizing a balance between the LDAR
applicability thresholds of the Utah Oil and Gas Rules and the CTG is
appropriate, as it will result in emissions reductions at more existing
sources than if we finalized the proposed applicability threshold. It
will not impose the requirement to implement an LDAR program at every
oil and natural gas source on the Indian country lands within the U&O
Reservation, which could potentially create a competitive disadvantage
to operating on the Reservation, resulting
[[Page 75360]]
in potentially negative economic impacts for the Ute Indian Tribe and
other mineral owners. We acknowledge that NSPS OOOOa currently contains
two different LDAR inspection standards for well sites and gathering
and boosting compressor stations controlling methane emissions and
those controlling VOC emissions and that the EPA has published a
proposed national rule to reduce methane and other pollutants from
existing, new, and modified sources in the oil and natural gas industry
that seeks to align those standards to require semiannual LDAR
inspections for all well sites (e.g., remove the exemption for low-
production wells) and quarterly LDAR inspections for all compressor
stations.\108\ We also acknowledge that the rule proposes to establish
new methane and VOC fugitive emissions monitoring standards for new and
modified sources and similar methane fugitive emissions monitoring
guidelines for existing sources.
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\108\ See 85 FR 63110. Nov. 15, 2021. Proposed Rule. Standards
of Performance for New, Reconstructed, and Modified Sources and
Emissions Guidelines for Existing Sources: Oil and Natural Gas
Sector Climate Review, available at https://www.regulations.gov
(Document ID #EPA-HQ-OAR-2021-0317-0001), accessed Mar. 14, 2022.
The regulatory inconsistencies stem from the recent joint resolution
under the Congressional Review Act that disapproved the 2020 Policy
Rule. That rule, which was issued by the previous Administration,
had eliminated important requirements to reduce methane and other
air pollution from new and modified sources in the oil and natural
gas source category. However, the joint resolution did not address a
separate 2020 rule known as the ``Technical Rule,'' which remains in
place today. The EPA is proposing to repeal amendments in the
Technical Rule that exempted low-production well sites from
monitoring fugitive emission; and changed VOC monitoring
requirements at gathering and boosting compressor stations from
quarterly to semi-annually.
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We expect that the final LDAR requirements of this FIP will result
in meaningful reductions in VOC emissions and ground-level ozone
production, significantly furthering our main objective for this U&O
FIP of improving air quality. We determined that, particularly for
existing sources, in order to meet our goal to provide consistent
requirements across the Uinta Basin, the LDAR inspection frequency
requirements in this U&O FIP should provide a measure of consistency
with the LDAR inspection frequency requirements 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 or the
GAO. If the sources in the Uinta Basin that are in areas where the EPA
has approved the UDEQ to implement the CAA are also subject to the LDAR
requirements of the NSPS OOOOa, the NSPS requirements supersede the
UDEQ requirements if the UDEQ requirements are less stringent.
Similarly, if the sources in the Uinta Basin that are regulated by the
EPA on Indian country lands within the U&O Reservation are subject to
the LDAR requirements of NSPS OOOOa, those sources are exempt from
complying with the LDAR requirements in this U&O FIP. We may revisit
this final action in the future based on any final action we take under
CAA section 111 with the Oil and Natural Gas Sector Climate Review
rulemaking to address application of LDAR at sources covered by this
FIP in a manner similar to the final national rule's provisions for
sources that it covers. Also, if the Uinta Basin Ozone Nonattainment
Area's Marginal classification is reclassified (``bumped up'') to a
Moderate nonattainment classification, or if air quality concerns
otherwise warrant, we may conclude that further rulemaking is necessary
or appropriate.
We proposed general language in the fugitive emissions provisions
allowing for the use of 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. We solicited information in
the proposed U&O FIP 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, 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
also solicited input on the criteria that the 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. We noted
that 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.
We did not receive any new information on the costs and effectiveness
of alternative leak detection methods during the public comment period.
However, we did receive suggestions for criteria we should consider in
approving alternative leak detection compliance methods to demonstrate
equivalency to EPA Reference Method 21 or optical gas imaging. Based on
those comments, we have added language to the final FIP specifying that
to be approved by the EPA, a demonstration that the alternative method
achieves emissions reductions that equal or exceed those that would
result from the application of either Method 21 or optical gas imaging
instruments must be made and any proposed approval by the EPA will be
subject to public notice and comment.
Studies specific to the Uinta Basin have investigated the viability
of leak detection method alternatives to conventional onsite instrument
detection, including detection methods from an aerial platform. One
study \109\ 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 United States basins. The goal
of this aerial survey was 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 that high-
emitting sites constituted 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. Another previously discussed study \110\
that employed a hybrid of both ground-based and aerial IR detection
methods found that observations using an IR camera from a helicopter in
winter were hampered by the cold land temperatures of the background
against which the plumes would be observed. The ground-based part of
this study, as previously discussed, showed a fairly high prevalence of
observed emissions from controlled storage vessels.
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\109\ ``Aerial Surveys of Elevated Hydrocarbon Emissions from
Oil and Gas Production Sites,'' Environmental Science and
Technology, 2016, 50 (9), pp 4877-4886, publication date Apr. 5,
2016, available at http://pubs.acs.org/doi/abs/10.1021/acs.est.6b00705, accessed Mar. 14, 2022.
\110\ ``Hydrocarbon Emission Detection Survey of Uinta Basin Oil
and Gas Wells''. Nov. 2018. Bingham Research Center, Utah State
University, available at available in the docket for this rulemaking
(Docket ID No. EPA-R08-OAR-2015-0709).
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We are finalizing the proposed provisions allowing operators to use
[[Page 75361]]
alternative methods of leak detection, other than EPA Reference Method
21 or optical gas imaging instruments, to demonstrate compliance with
the fugitive emissions monitoring requirements, provided the method is
approved by the EPA. We added language specifying that to be approved
by the EPA, a demonstration that the alternative method achieves
emissions reductions that equal or exceed those that would result from
the application of either Method 21 or optical gas imaging instruments
must be made and any proposed approval by the EPA will be subject to
public notice and comment. The total fugitive VOC emissions reduced
does not account for emissions due to abnormal process operations,
which was discussed earlier. 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) \111\
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
industry.
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\111\ See 81 FR 46670 (July 18, 2016).
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E. Monitoring and Testing
In response to several comments, and to clarify one provision, we
made some changes to the proposed monitoring requirements for covers
and closed vent systems and VOC emissions control devices to provide
more consistency with NSPS OOOO and OOOOa. The proposed requirements
for inspecting covers and closed vent systems were different than NSPS
OOOOa in that they did not allow the option to demonstrate compliance
by conducting optical gas imaging inspections on the same schedule as
fugitive emissions inspections. We have added that option to the final
FIP. Additionally, rather than adopt by reference the inspection
requirements of NSPS OOOOa at 40 CFR 60.5416a(c), we incorporated
streamlined inspection requirements for covers and closed vent systems
into a common set of provisions, because the separate provisions in
NSPS OOOOa are essentially the same. Although the preamble to the
proposed rule explained that it would require that facilities ``ensure
that each enclosed combustor or utility flare is. . . operated with no
visible smoke emissions,'' in the proposed regulatory text we
inadvertently mentioned only enclosed combustors, not flares, in the
provision requiring owners and operators to verify on a monthly basis
that there are no detectable smoke emissions. To make the regulatory
text of the FIP consistent with the intent explained in the proposed
rule as to flares, and also in response to comments that the FIP should
provide more consistency with NSPS OOOO and OOOOa, the monitoring
requirements being finalized today, consistent with NSPS OOOO and
OOOOa, require Method 22 monitoring for all VOC control devices. We
also streamlined the requirements to perform monthly inspections of the
covers closed-vent systems and monthly inspections of the VOC emissions
control devices, each separated by at least 15 days between each
inspection, to provide operators the flexibility to schedule
inspections in the same visit.
F. Recordkeeping and Reporting
In response to several comments, we also made some changes to the
proposed recordkeeping requirements to provide more consistency with
the records that the UDEQ requires of oil and natural gas sources, as
well as with the records required by NSPS OOOO and OOOOa. Regarding
annual reports, we made changes to clarify in the final FIP the April
1st due date of each annual report, and that the reporting period for
the initial annual report will be the period beginning with the
effective date of the final rule through the end of that calendar year.
Additionally, in response to public comments that annual reporting
should be limited to targeted records that most efficiently indicate
the degree of compliance with the U&O FIP, we have specified a subset
of required records that must be summarized in the annual report
related to each enclosed combustor or flare, each cover and closed-vent
system, fugitive emissions monitoring and each high-bleed pneumatic
controller, including deviations from rule requirements and corrective
actions taken to address deviations.
VI. Summary of Significant Comments and Responses
This section summarizes the significant public comments on the
proposed FIP and our response to those comments as they related to the
specific requirements being finalized today in this U&O FIP. More
detailed summaries of the comments and our responses are available in
the docket for this rulemaking.\112\
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\112\ Response to Public Comments. Proposed Federal
Implementation Plan: Managing Emissions from Oil and Natural Gas
Sources on Indian Country Lands within the Uintah and Ouray Indian
Reservation in Utah. May 2021, available in the docket for this
rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
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A. Major Comments Concerning Effective Date and Compliance Deadline
Comment: Industry commenters asserted that since the EPA has
determined that the rule is an economically significant regulatory
action subject to Office of Management and Budget Review under E.O.
12866, the rule must also be a ``major rule'' under the Congressional
Review Act, which mandates that it may become effective no earlier than
60 days after it is published in the Federal Register.
Response: We agree and have finalized an effective date 60 days
after publication in the Federal Register.
Comment: Industry commenters claimed that air quality studies in
the Uinta Basin and available air quality data support that emissions
reductions needed to attain the NAAQS only need to occur in the winter,
rather than year-round as the EPA proposed, and claimed it was
unreasonable and arbitrary that the EPA did not evaluate a seasonal
regulatory option.
Response: We disagree that it was unreasonable or arbitrary not to
evaluate a seasonal regulatory option to address elevated ozone and
emissions reductions with this rulemaking. Through the stakeholder
outreach we participated in during the rulemaking process, we heard
feedback from the Ute Indian Tribe, the UDEQ, and oil and natural gas
operators alike that consistent regulatory requirements across all
areas in the Basin are important to ensuring a cohesive strategy to
improve air quality, providing regulatory certainty and avoiding
disadvantages to development in one area versus another. Based on
verified ozone measurements during summer months at regulatory monitors
in the Basin from 2017 to 2020, there have been at least a few
exceedances of the 8-hour ozone daily maximum, and many other readings
that have been close to the NAAQS. Imposing a seasonal control program
for this rulemaking when the UDEQ requires year-round controls and the
majority of the existing VOC emissions in the Basin are occurring on
the Indian country lands within the U&O Reservation was not considered
for several reasons. Doing so would continue inconsistent regulatory
requirements across all areas in the Basin, potentially creating
incentives to develop sources with higher emissions on the Reservation.
Seasonal emissions reductions requirements would be complex to
implement, enforce and quantify the effects to defensibly justify
continued
[[Page 75362]]
minor source development on the Reservation. The opportunity to achieve
VOC emissions reductions that could improve ozone air quality close to
the NAAQS during summer months would be lost. We may consider seasonal
emissions mitigation measures in a future rulemaking if additional CAA
nonattainment requirements are triggered.
Comment: Environmental organization commenters asserted that the
EPA must ensure existing sources are in compliance immediately upon the
effective date of the final rule, rather than allowing an 18-month
period for affected sources to come into compliance. The commenters
claimed that the EPA failed to provide adequate justification for why
vendors need 18 months to provide equipment to owners and operators
when the estimated number of affected existing sources needing to
install retrofits is similar to the number that were cited as able to
install retrofits in in areas of the Basin where the EPA has approved
the UDEQ to implement the CAA. Commenters also asserted that the EPA
should promulgate the FIP with a specific process of how decisions will
be made to grant requested extensions of the 18-month compliance
period.
Response: We acknowledge the commenters' requests urging the agency
to finalize and fully implement the FIP in a shorter timeframe than was
proposed. We disagree that existing sources should be required to have
all required controls installed immediately upon the effective date of
the final rule. The final FIP may require operators of an estimated
2,165 existing sources on Indian country lands within the U&O
Reservation to retrofit existing equipment and install combustion
devices, at an estimated capital cost of about $230 million. We
determined it would not be practical for affected operators to acquire
the necessary equipment from vendors and have it installed at that many
existing sources in two months. The evaluation of anecdotal information
from the UDEQ on the time it took a similar number of existing sources
to come into compliance was not comparable to the FIP, as the UDEQ's
approvals were spread out over time and that information was only used
as a data point to help inform our belief that a certain period of time
is appropriate to allow existing sources to come into compliance. We
agree, however, given the urgency of the need to improve air quality in
the Basin and the fact that owners and operators have been on notice
that the rule might come into effect since the proposed rule was
published in January 2020, the compliance period can reasonably be
shortened to ensure meaningful VOC emissions reductions will be
achieved in a timely manner. Therefore, we are finalizing a 12-month
period for existing sources to come into compliance with the FIP. We
have retained flexibility for operators to request extensions to the
compliance deadline but agree with commenters that the regulatory
language should specify the process the EPA would take to make
decisions granting requested extensions of the compliance period and
have included such language in the final rule.
B. Major Comments Concerning Regulatory Authority for Minor Source
Streamlined Construction Authorization
Comment: Industry commenters asserted that, given the amendment of
the National O&NG FIP to permanently extend the streamlined approach
for approval of new and modified true minor oil and natural gas sources
to the portions of the Indian country lands within the U&O Reservation
that are part of the 2015 Uinta Basin Ozone Nonattainment Area was
already permanently finalized at its current location in the Code of
Federal Regulations (CFR), it is not necessary to remove the regulatory
authority from that FIP and add it to the final U&O FIP. The same
commenters also asserted that it is not appropriate to take comment on
the National O&NG FIP amendment as part of this rulemaking.
Environmental organization commenters asserted, on the other hand, that
the EPA must analyze the air quality impacts of the National O&NG FIP
amendment, claiming that the EPA failed to do so as part of that
action. The commenters noted that the EPA has a mandate under the CAA's
minor NSR provisions to ensure that implementation of the program
assures that the NAAQS are achieved and, therefore, cannot authorize
construction of new and modified sources in a nonattainment area unless
it demonstrates protection of the NAAQS through a modeling analysis and
a mechanism that tracks emissions consumed by new and modified sources
against emissions that are reduced.
Response: We agree with commenters that it is not necessary to move
the location of the authority for the already-effective amendments to
the National O&NG FIP to the final U&O FIP. We disagree that the
proposed U&O FIP provided a fresh opportunity to comment on the merits
of the National O&NG FIP amendment and that the proposed U&O FIP should
have analyzed the air quality impacts of extending the National O&NG
FIP to the Indian country portions of the nonattainment area. That
action was promulgated through a separate rulemaking process \113\ and
was not challenged within the judicial review period of that regulatory
action and is thus today fully effective. At most, the proposal to
include this authority in the U&O FIP would have shifted the location
of already-existing authority within the CFR, which might have promoted
easier compliance for affected oil and natural gas sources but would
not have established any new requirements. In any event, we have
decided not to finalize the proposed shift in the location of the
authority to the U&O FIP, as we determined that the agency resources
required to revise the National O&NG FIP through the rulemaking process
would outweigh any streamlining advantage gained; thus, the authority
will remain in the National O&NG FIP, as established in the May 24,
2019, final rule.
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\113\ See 84 FR 21240 (May 14, 2019).
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Further, we disagree with the assertion that only modeling can
support a conclusion that substantial emissions reductions from this
FIP could be relied on to support authorization to construct new and
modified minor oil and natural gas sources under the National O&NG FIP.
Unlike the NSR program for major sources in nonattainment areas, the
minor NSR program does not require emissions offsets from existing
sources in authorizing construction of new or modified minor sources in
nonattainment areas, but rather requires the reviewing authority to
demonstrate that new or modified minor sources in a nonattainment area
would not cause or contribute to a NAAQS violation. The reviewing
authority is not required to conduct modeling of minor source emissions
to make such a demonstration. Rather, the rule provides the reviewing
authority discretion to require modeling if it is concerned that new
construction may cause or contribute to NAAQS violations. That
discretion in demonstrating NAAQS protection was at work in the action
to amend the National O&NG FIP, where we relied on existing source
emissions reductions that we expect will be achieved from
implementation of a U&O FIP. Based on our analysis of the current pace
of new development under the National O&NG FIP, we expect that these
reductions will far exceed the expected emissions from new
construction. Our estimate for the expected magnitude of future
development was based on a
[[Page 75363]]
quantitative analysis of the rate of new and modified true minor source
development and emissions increases on the Indian country lands within
the Uintah & Ouray Reservation for each of the full calendar years
since the effective date of the National O&NG FIP (2017-2019). We have
updated that estimate for the final FIP to include 2020 and 2021 and we
find that the pace of development has not noticeably changed, such that
development of new and modified true minor oil and natural gas sources
would need to occur at over 90 times the current pace of development to
consume the annual headroom that full compliance with this FIP is
expected to generate.\114\ With this reevaluation, we continue to
support the conclusion that the reductions achieved by this FIP will
create more than enough headroom for the current or higher rates of
development for years to come while first and foremost improving ozone
air quality. We plan to periodically reevaluate our assumptions in the
future based on changes in the pace of development and may take
additional actions to protect air quality as necessary or appropriate.
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\114\ The analysis is included in the docket for this rulemaking
(Docket ID No. EPA-R08-OAR-2015-0709), Microsoft Excel spreadsheet
titled, ``OGFIP Emissions_UO_2017-2021.xlsx.''
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C. Major Comments Concerning Rule Applicability
Comment: (VOC Emissions from Storage Vessels, Glycol Dehydrators
and Pneumatic Pumps) Environmental organization commenters claimed that
the proposed VOC emissions control requirements for storage vessels,
glycol dehydrators and pneumatic pumps should be strengthened to place
a priority on the option of routing emissions to a process to meet the
emissions reduction requirement over the option of combusting those
emissions. The commenters reference the EPA's FIP for the FBIR (FBIR
FIP) \115\ and NSPS OOOOa \116\ as examples where the EPA has
previously done this. The commenters also asserted that, to the extent
that the EPA does permit gas combustion, it must only permit the use of
VOC emissions control devices designed to reduce VOC emissions by 98
percent and require annual control efficiency performance testing for
those devices.
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\115\ See 40 CFR 49.4164(d).
\116\ See 40 CFR 60.5375a(a)(1)(ii) and 60.5375a(a)(3).
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Response: Regarding the comment that priority should be codified
for the option of routing emissions to a process to meet the emissions
reduction requirement over the option of combusting those emissions, we
disagree. The commenters reference the EPA's FBIR FIP and NSPS OOOOa as
examples of placing such priority, but that is a misinterpretation of
the nuances of these regulations. The FBIR FIP allows lower-efficiency
combustion of produced gas during well completion and through the first
90 days of production (using what is commonly known as pit flares).
Within those first 90 days, the FBIR FIP requires all natural gas
emissions from production operations and storage operations to be
captured and routed through a closed-vent system to either a beneficial
process or a high-efficiency combustion device, only allowing limited
lower-efficiency combustion if routing to a process or high-efficiency
combustion is temporarily infeasible (not to exceed 500 hours
annually).\117\ The FBIR thus places a priority on routing to a process
or high-efficiency combustion over lower-efficiency combustion, but
there is equal allowance for routing to a process and routing to a
high-efficiency combustion device. NSPS OOOOa does prioritize routing
of produced gas to a process over combustion for each well completion
operation with hydraulic fracturing during the separation flowback
stage. However, the same prioritization is not expressed for treatment
of gases and vapors during ongoing production post-completion, which is
only covered under NSPS OOOOa for well sites through the requirements
for centrifugal compressors, reciprocating compressors, pneumatic
controllers, pneumatic pumps, storage vessels, and the collection of
fugitive emissions components at a well site's affected
facilities.\118\ Unlike the FBIR FIP and NSPS OOOOa, the final U&O FIP
does not cover well completion operations. As the primary goal is to
reduce existing source emissions to improve air quality in the Uinta
Basin, the U&O FIP covers ongoing production operations at existing,
new, and modified oil and natural gas sources that are not already
subject to federal standards, including NSPS OOOO and OOOOa and NESHAP
HH.
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\117\ See 40 CFR 49.4164(b) through (e) and 49.4165(d)(2)(ii).
\118\ See 40 CFR 60.5380a, 60.5385a, 60.5393a, 60.5395a,
60.5397a, 60.5410a, and 60.5411a.
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Regarding the comment that the EPA must only permit the use of VOC
emissions control devices designed to reduce VOC emissions by 98
percent and require annual control efficiency performance testing for
those devices, we disagree. As explained earlier,\119\ we are
reiterating our position in the proposed FIP that even devices that are
designed to achieve at least 98 percent VOC control efficiency and able
to demonstrate that control efficiency in controlled testing
environments may not reliably achieve 98 percent control efficiency in
the field on a continuous basis without stronger flare performance
requirements than are currently in effect today in EPA's federal
regulations that apply nationally. We believe that 95.0 percent
continuous control efficiency is achievable when supplemented by the
design, operational and parameter monitoring requirements in the final
FIP. We expect that requirements for robust design of combustion
devices, initial and subsequent performance testing (every 5 years) of
enclosed combustors according to the procedures in NSPS OOOO and OOOOa
(adopted by reference in the proposed FIP), and continuous monitoring
of manufacturer-specified parameters that indicate optimal operation of
a control device, including combustion temperature and a continuous
pilot flame while emissions are routed to a device, are effective at
indicating proper operation of a control device and more affordable and
flexible than requiring annual performance testing of thousands of
control devices or requiring exclusive use of particular devices.
Requiring 95.0 percent continuous control efficiency also provides
consistency with the EPA's federal regulations that apply nationally
and consistency across all areas in the Uinta Basin, which operators
are accustomed to complying with in the Uinta Basin already. Imposing
more stringent control requirements on Indian country lands within the
U& Reservation than are imposed in areas where the EPA has approved the
UDEQ to implement the CAA may also unnecessarily create a competitive
disadvantage to developing on the Indian country lands within the U&O
Reservation, causing economic impacts to the Ute Indian Tribe and its
citizens.
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\119\ See Section IV.F.3 of this preamble.
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Comment: Industry asserted that the definition of ``fugitive
emissions component'' and the repair timeline and inspection frequency
should be consistent with those in NSPS OOOOa, to avoid divergent
requirements for operators with sources subject to LDAR under the NSPS
and sources subject to LDAR under the FIP. Environmental organization
commenters asserted that the FIP applicability to the requirement to
implement an LDAR program should not be limited to the minimum
threshold for sources with total emissions from the collection of all
[[Page 75364]]
storage vessel, glycol dehydrator and pneumatic pump emissions equal to
or greater than 4 tpy VOC, because there is no inherent relationship
between the quantity of vented emissions from tanks, dehydrators and
pneumatic pumps (intended) and the source's fugitive emissions
(unintended), and because the proposed LDAR requirements apply to
components, such as compressors, that are categorically different than
storage tanks, dehydrators and pneumatic pumps. These commenters
asserted that all oil and natural gas sources should be required to
implement an LDAR program, based on the results of recent studies
indicating pneumatic devices often emit at higher rates than they are
designed. The same commenters also asserted that the definition of
``fugitive emissions component'' should not exclude natural gas-driven
pneumatic controllers and pumps that are designed to vent as part of
normal operations.
Response: We agree with comments that the definition of ``fugitive
emissions component'' should be consistent with that in NSPS OOOOa and
we have revised the definition accordingly in the final FIP. We
disagree with comments that the definition should not exclude pneumatic
devices. The EPA has already codified that exclusion in NSPS OOOOa.
Additionally, pneumatic devices are also subject to specific control
requirements in the FIP, namely the requirements to control VOC
emissions from pneumatic pumps at certain sources and to ensure that
pneumatic controllers have a bleed rate of 6 scf/hr or less (i.e.,
``low-bleed''). We are aware of the studies regarding malfunctioning
pneumatic controllers and refer the reader to the previous summaries of
comments and our responses in this section regarding the applicability
of pneumatic controllers. We agree with comments that the repair
timeline should be consistent with those in NSPS OOOOa. We have not
revised the LDAR inspection frequency of the proposed FIP to be
entirely consistent with the frequency that is in NSPS OOOOa. The
majority of the oil and natural gas sources that are subject to the FIP
are existing sources that are not subject to NSPS OOOOa. The final
semiannual inspection frequency for affected well sites is consistent
with what is in the Utah Oil and Gas Rules, the CTG and NSPS OOOOa. For
affected gathering and boosting compressor stations and natural gas
processing plants, it is less frequent than the CTG and NSPS OOOOa in
part.\120\ The Utah Oil and Gas Rules do not cover gathering and
boosting compressor stations or natural gas processing plants and the
Utah Permit Requirements require varying inspection frequencies ranging
from semiannual to monthly. There are far fewer existing gathering and
boosting compressor stations, and even less existing natural gas
processing plants, on the Indian country lands within the U&O
Reservation than there are well sites. Because the CTG VOC guidelines
and the NSPS OOOOa methane standards require at least quarterly
inspections for existing, new, and modified compressor stations and
natural gas processing plants, but the NSPS OOOOa VOC standards for new
and modified compressor stations and natural gas processing plants and
the Utah Permit Requirements for existing compressor stations and
natural gas processing plants mandate LDAR inspection frequencies
widely ranging from semi-annual to monthly, we determined that it is
reasonable to simplify compliance with the final FIP by requiring a
consistent semi-annual inspection frequency for all types of oil and
natural gas sources. We note that the gathering and boosting compressor
stations and natural gas processing plants subject to NSPS OOOOa would
be required to comply with those fugitive emissions inspection
requirements, rather than the FIP. We have, however, revised the
procedural LDAR requirements of the proposed FIP to maximize
consistency with the equivalent requirements of NSPS OOOOa, which
addresses the concern that operators would be subject to divergent
procedural requirements for sources subject to LDAR under the NSPS and
sources subject to LDAR under the FIP.
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\120\ As discussed earlier in Section V.D. of this preamble, we
acknowledge that NSPS OOOOa currently contains two different LDAR
inspection standards for well sites and gathering and boosting
compressor stations controlling methane emissions and those
controlling VOC emissions and that the EPA has published a proposed
national rule to reduce methane and other pollutants from existing,
new, and modified sources in the oil and natural gas industry that
proposes to align those standards to require semiannual LDAR
inspections for all well sites (no exemption for low-production
wells) and quarterly LDAR inspections for all compressor stations
(see 86 FR 63110, Nov. 15, 2021).
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In response to the comment criticizing our proposal to apply LDAR
requirements to sources that are required to control facility-wide VOC
emissions from the collection of all storage vessels, glycol
dehydrators and pneumatic pumps (i.e., emissions from those equipment
are greater than or equal to 4 tpy), we do agree that there is not
strong evidence of a direct inherent relationship between the quantity
of vented emissions from the collection of all storage vessels,
dehydrators and pneumatic pumps (intended) and a source's fugitive
emissions (unintended). We also agree that the proposed LDAR
requirements apply to components, such as compressors, that are
categorically different than storage vessels, dehydrators and pneumatic
pumps. But we disagree that these observations compel the conclusion
that the FIP should apply LDAR requirements to all sources, for the
reasons explained below. Applying LDAR requirements to all existing,
new, and modified oil and natural gas sources would be significantly
more stringent than the Utah Oil and Gas Rules given the total number
of existing oil and natural gas sources on the Reservation (6,870),
versus the number of sources we estimate will be required to implement
LDAR under this final rule (3,100). An even broader LDAR applicability
than what is being finalized today, which itself is already broader
than that in the Utah Oil and Gas Rules, would create inconsistency
across all areas of the Basin that may prompt operators to shift
development and associated emissions to areas of the Basin where the
EPA has approved the UDEQ to implement the CAA or to cease existing
production on Indian country lands within the U&O Reservation, both of
which could have economic disbenefits for the Ute Indian Tribe. We
evaluated whether there was a more appropriate measure to limit
applicability to a required LDAR program in the final FIP. We evaluated
exempting ``low-production'' well sites, or those with total daily
production less than or equal to 15 boe, similar to the CTG. We also
evaluated applying LDAR requirements to all oil and natural gas sources
that meet either criterion: (1) VOC emissions from the collection of
all storage vessels, glycol dehydrators and pneumatic pumps that are
greater than or equal to 4 tpy; or (2) well sites with production
greater than 15 boe per day. Applying LDAR to all oil and natural gas
sources was analyzed as part of regulatory Option 3. In the final FIP
we are applying LDAR requirements to all oil and natural gas sources
that meet either criterion: (1) VOC emissions from the collection of
all storage vessels, glycol dehydrators and pneumatic pumps that are
greater than or equal to 4 tpy; or (2) well sites with production
greater than 15 boe per day. We determined this approach would address
the comment that there is not strong evidence of a direct inherent
relationship between the quantity of vented emissions from storage
vessels, dehydrators and pneumatic pumps
[[Page 75365]]
(intended) and a source's fugitive emissions (unintended). This
approach is a middle ground that provides some consistency with both
the LDAR applicability of the Utah Oil and Gas Rules and that of the
CTG for existing sources. Additionally, from an air quality protection
perspective, it is reasonable to make a change from what was proposed
that would maximize VOC emissions reduced without requiring all
existing oil and natural gas sources to implement an LDAR program. We
acknowledge some recent studies indicating that leaks have consistently
been observed at certain well sites with less than 15 boe per day.\121\
We also acknowledge that the EPA has published a proposed national rule
to reduce methane and other pollutants from existing, new, and modified
sources in the oil and natural gas industry that proposes to repeal
amendments in the 2020 Technical Rule that exempted low-production well
sites from monitoring fugitive emission.\122\ We may revisit this final
action in the future based on any final action we take under CAA
section 111 with the Oil and Natural Gas Sector Climate Review
rulemaking to address application of LDAR at sources covered by this
FIP in a manner similar to the final national rule's provisions for
sources that it covers. Also, if the Uinta Basin Ozone Nonattainment
Area's Marginal classification is reclassified (``bumped up'') to a
Moderate nonattainment classification, or if air quality concerns
otherwise warrant, we may conclude that further rulemaking is necessary
or appropriate.
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\121\ A study by the Boulder County Health Department, ``Leak
Inspection and Repair at Oil and Gas Well Sites
Boulder County Public Health Voluntary Inspection Program
Results 2014-2018,'' tracked leaks at well pads in Boulder County
over a five-year period using OGI. The program resulted in 1,022
inspections at 147 well pad sites across the county from 2014
through 2018. Cumulatively, gas leaks were detected at 86 percent
[i.e., 126/147] of inspected sites, with the percentage each year
ranging from 38 percent to 49 percent. 64 percent of the sites with
leaks experienced them in multiple calendar years. An earlier
version of the study (2014-2016) was referenced via comments on the
proposed NSPS OOOOa technical revisions, available in the docket for
that rulemaking at https://www.regulations.gov (Docket ID No. EPA-
HQ-OAR-2010-0483-0748). Since then, two additional study years
through 2018 were added. The report is available in the docket for
this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709). We conducted
an analysis showing that of the average BOED per well ranged from
1.6 to 2.3 from 2014-2018, indicated in the November 18, 2019, email
from Cindy Beeler, EPA, available in the docket for this rulemaking
at https://www.regulations.gov (Docket ID No. EPA-R08-OAR-2015-
0709); and Deighton, J. A., Townsend-Small, A., Sturmer, S. J.,
Hoschouer, J., & Heldman, L. (2020). Measurements show that marginal
wells are a disproportionate source of methane relative to
production. Journal of the Air & Waste Management Association,
available at https://www.tandfonline.com/doi/full/10.1080/10962247.2020.1808115, accessed Mar. 14, 2022.
\122\ See 86 FR 63110 (Nov. 15, 2021).
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Comment: Environmental organization commenters asserted that the
proposed FIP requirement that all pneumatic controllers be continuous
low-bleed controllers, consistent with NSPS OOOO and OOOOa, is
insufficient, adding that while continuous low-bleed controllers are
superior to high-bleed controllers, they are documented in recent
studies to emit significant VOC emissions both from normal operations
(i.e., by design) and often due to equipment malfunctions. The
commenters asserted that recent evidence indicates zero-emissions
controllers (e.g., electric valve, instrument air-actuated, and solar
power valve actuated) are cost-effective, widely used, and
environmentally necessary.
Response: We disagree that the EPA mandating zero-emissions
controllers is necessary or required here and provided reasoning in the
proposed FIP for requiring low-bleed pneumatic controllers rather than
zero-emissions pneumatic controllers. The EPA believes that, within the
context of this rulemaking and the specific purposes it is intended to
accomplish, we do not have sufficient information to finalize such a
requirement for the Indian country lands within the U&O Reservation at
this time. Further, including such a requirement in the final FIP would
not serve to further the EPA's goal of providing regulatory consistency
at this time. In the interest of improving air quality by achieving
emissions reductions as soon as possible and in a manner that promotes
regulatory consistency across all areas in the Uinta Basin, we are
finalizing the FIP with the requirement that pneumatic controllers be
at least low-bleed. Although zero-bleed controllers are not
specifically required, the regulatory text of the final U&O FIP does
not prohibit operators from using zero-bleed controllers to comply with
the rule, as it incorporates by reference the pneumatic controller
requirements of NSPS OOOOa at 40 CFR 60.5390a, which specify at 40 CFR
60.5390a(c)(1) that ``Each pneumatic controller affected facility at a
location other than at a natural gas processing plant must have a bleed
rate less than or equal to 6 standard cubic feet per hour.'' (emphasis
added). We acknowledge that the EPA's Oil and Gas Sector Climate Review
Proposed Rule proposes to require pneumatic controllers to have zero
emissions, subject to limited exceptions.\123\ However, that proposed
requirement is not yet final and the EPA did not include a similar
requirement as part of the proposal for this rulemaking. We may revisit
this final action in the future based on any final action we take under
CAA section 111 with the Oil and Natural Gas Sector Climate Review
rulemaking to address pneumatic controllers at sources covered by this
FIP in a manner similar to the final national rule's provisions for
sources that it covers. Also, if the Uinta Basin Ozone Nonattainment
Area's Marginal classification is reclassified (``bumped up'') to a
Moderate nonattainment classification, or if air quality concerns
otherwise warrant, we may conclude that further rulemaking is necessary
or appropriate.
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\123\ See 86 FR 63110, Nov. 15, 2021.
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Comment: Environmental organization commenters asserted that the
proposed FIP should require capture and control of VOC emissions during
truck loading and unloading. The commenters claimed that the EPA failed
to take into account that truck loading and unloading is an activity
that occurs repeatedly and provides an opportunity for emissions
reductions and the EPA failed to provide calculations to support the
cost-prohibitiveness of requiring such controls.
Response: We disagree. In developing the proposed rule, we found
that the estimated annual share of VOC emissions from truck loading and
unloading in the UBEI2014 was only 2 percent of the VOC emissions
inventory and such a requirement would not be expected to contribute to
meaningful VOC reductions compared to submerged fill and bottom loading
requirements. The UBEI2017-Update indicates that truck loading and
unloading represents an even smaller portion of the VOC emissions
inventory at 1 percent. We did not receive new information during the
public comment period on the cost of capture and control of emissions
from truck loading and unloading to compel us to change the proposed
requirement. Therefore, we are finalizing truck loading and unloading
requirements as proposed. We may consider such a requirement in a
future rulemaking if additional action is required to address air
quality impacts from ozone pollution, or we may consider it as a
creditable emissions reduction to offset permitting of a new or
modified major source or demonstrating general conformity. We
acknowledge that the EPA's Oil and Natural Gas Sector Climate Review
Proposed Rule solicits comment on whether the EPA should propose to
require capture and control
[[Page 75366]]
of VOC and methane emissions from truck loading and unloading.\124\ We
may revisit this final action in the future based on any proposal and
subsequent final action we take under CAA section 111 for the Oil and
Natural Gas Sector to address truck loading and unloading at sources
covered by this FIP in a manner similar to a final national rule's
provisions for sources that it covers. Also, if the Uinta Basin Ozone
Nonattainment Area's Marginal classification is reclassified (``bumped
up'') to a Moderate nonattainment classification, or if air quality
concerns otherwise warrant, we may conclude that further rulemaking is
necessary or appropriate.
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\124\ See 86 FR 63110, Nov. 15, 2021.
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Comment: Several commenters claimed the EPA should regulate VOC
emissions from additional equipment or activities as part of the final
FIP, including oil and natural gas wastewater pond evaporation
facilities, intermittent bleed pneumatic devices, well production
associated gas and small two-stroked rich-burn engines. Commenters also
asserted that the EPA should regulate sources of NOX
emissions as part of the final FIP, as it is an ozone precursor and
some studies have indicated the NOX reductions in the Uinta
Basin may result in meaningful reductions in the formation of ozone.
NOX emissions sources that commenters asserted should be
covered by the FIP include engines, turbines, boilers, heaters, flares
and thermal incinerators.
Response: Regarding the comments that the FIP should cover
additional VOC emissions sources, we are not finalizing emissions
control requirements for any sources in addition to what was proposed.
The primary reason is that we proposed to act on the sources as to
which we had sufficient cost and emissions reduction information
specific to the Uinta Basin and from which we expected that significant
emissions reductions could be achieved in a manner that maximizes
regulatory consistency across all areas in the Basin. We are finalizing
this rule as applicable to those sources in order to achieve emissions
reductions quickly and improve air quality and public health within the
U&O Reservation as soon as possible. It may be possible in the future
to achieve further reductions by regulating additional sources, and if
we conclude that such further regulation is appropriate, we will
propose action on it in a future U&O Reservation rulemaking in order to
receive public comment. The EPA is actively participating in ongoing
research to better understand emissions from all of the aforementioned
VOC emissions sources in the Uinta Basin. We acknowledge that the EPA's
Oil and Natural Gas Sector Climate Review Proposed Rule has presented
new information and analysis that will likely be relevant for reducing
emissions on the U&O Reservation and solicits additional information on
evaluating and potentially covering at least some of these sources on a
national basis.\125\ Our assessment of new, potentially relevant
information will continue in the context of the Climate Review Rule
still being developed. If we finalize a national Climate Review Rule in
the future, its requirements will apply directly to covered sources. As
to sources not covered by a final national rule, we may find it
necessary or appropriate to revisit this final action in the future and
revise it through the rulemaking process (including public notice and
comment) based on information evaluated in issuance of that final
national rule. Also, if the Uinta Basin Ozone Nonattainment Area is
reclassified to a Moderate nonattainment classification, or if air
quality concerns otherwise warrant, we may find that further rulemaking
is necessary or appropriate.
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\125\ See 86 FR 63110 (Nov. 15, 2021).
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Regarding the comments that the FIP should cover sources of
NOX emissions, we maintain our conclusion from the proposed
rule that most recent studies on winter ozone in the Uinta Basin
indicate that ozone in the Basin is sensitive to changes in VOC
emissions and that the effect of changes in NOX emissions is
less certain, and, therefore, VOC reductions will have the most cost-
effective impact in reducing winter ozone formation in the Basin. We
may consider focusing on NOX emissions reduction in future
rulemakings if additional action is required to address air quality
impacts from ozone pollution and any control technology and cost
information commenters provided may be useful in those cases. We may
also consider future NOX emissions reductions as creditable
to offset permitting of a new or modified major NOX
emissions source or in demonstrating general conformity. We refer the
reader to the Response to Comments document in the docket for this
rulemaking for more details on our consideration comments related to
regulating additional VOC emissions sources and regulating
NOX emissions sources.
Comment: Industry commenters asserted that the U&O FIP should only
apply to Indian country lands within the Uinta Basin Ozone
Nonattainment Area boundary, rather than all Indian country lands
within the U&O Reservation, as proposed. Environmental organization
commenters asserted that the term ``Uintah and Ouray Reservation'' must
be defined in the regulatory text of the rule and should mean the lands
``within the exterior boundaries of the U&O Reservation.''
Response: We disagree with the comment that the FIP should only
apply to Indian country lands within the Uinta Basin Ozone
Nonattainment Area boundary. We are finalizing the FIP to impose the
VOC emissions reduction requirements to all Indian country lands within
the U&O Reservation for multiple reasons: (1) Implementing the
requirements only to sources in the nonattainment area would be complex
to implement, because it would present a second layer to already
complex case-specific determinations of CAA jurisdiction and
applicability to the FIP and would result in operators potentially
needing to comply with different regulatory requirements within Indian
country; and (2) Applying the FIP only to the Indian country portions
of the nonattainment area would result in inconsistent requirements
across all areas in the Uinta Basin, as the Utah Oil and Gas Rules
apply to all oil and natural gas sources in areas of the Bain where the
EPA has approved the UDEQ to implement the CAA, not just those in the
nonattainment area. We agree with the comment that the term ``U&O
Reservation'' was undefined in the regulatory text of the proposed rule
and have added clarification to the final rule regulatory text in 40
CFR 49.4169 that ``U&O Reservation'' refers to the ``Uintah and Ouray
Indian Reservation.'' We disagree that the rule text should state that
it applies ``within the exterior boundaries of the U&O Reservation.''
The proposed rule stated that it applies to the ``Indian country lands
within the U&O Reservation.'' There are non-Indian country lands within
the exterior boundaries of the U&O Reservation. Therefore, we have
added a definition of ``Indian country'' to 40 CFR 49.4171 that
references the corresponding definition at 18 U.S.C. 1151.
D. Major Comments Concerning Monitoring and Testing Requirements
Comment: Industry commenters asserted that the proposed requirement
to perform auditory/visual/olfactory (AVO) surveys while crude oil,
condensate, intermediate hydrocarbon liquids and produced water storage
vessels are being filled is impractical, due to the non-static nature
of separators cycling and liquids transfer
[[Page 75367]]
that could result in an operator being on location for a burdensome
period of time to comply. The commenters also asserted that the
proposed required monthly AVO inspections should not be finalized
because they go beyond NSPS OOOOa and the UDEQ requirements and are
duplicative of the proposed monthly inspections required in 40 CFR
49.4183(c) and (e) and the semi-annual monitoring of fugitive emissions
components in 40 CFR 49.4179. The commenters asserted that the final
FIP should provide more flexibility in determining compliance with the
no detectable emissions limit for covers and closed-vent systems by
allowing multiple options to perform inspections, including AVO and
OGI.
Response: We agree with the commenters that the monitoring
requirements in proposed 40 CFR 49.4183(c), (d) and (e) contained some
redundancy and risk affected sources being subject to duplicative
requirements. We have revised paragraphs (c) through (e) to merge
paragraphs (c) and (d) (now in 40 CFR 49.4182 in the final FIP) for
more consistency with NSPS OOOOa. We have also incorporated more
streamlined language that is still consistent with that section, rather
than incorporate by reference the cover and closed vent system
inspection requirements from 40 CFR 60.5416a(c). Additionally, we agree
with comments that, in addition to AVO inspections, consistent with
NSPS OOOOa, the FIP should provide the option to conduct optical gas
imaging inspections of covers and closed vent systems at the same
frequency as required fugitive emissions inspections and have included
a similar option.
Regarding the proposed requirement that monthly inspections must be
performed while storage vessels are being filled, we acknowledge that
storage vessel filling at certain well sites may occur less frequently
than at other sites, due to the non-static nature of separator cycling
and liquids transfer. We have removed the portion of the requirement
that inspections must be performed while storage vessels are being
filled. Because one cannot always hear or smell emissions from the
collection of all storage vessels, we continue to hold the view that
inspections conducted during filling events can be valuable for
identifying storage vessel and closed vent system integrity defects, as
filling events generate the largest flashing emissions. To maintain the
effectiveness of visual inspections in identifying defects, in light of
removal of the requirement that they be conducted during filling
events, we have added language to 40 CFR 49.4182(c) that inspectors
should note whether there are signs of oil releases around storage
vessel thief hatches, seals and pressure relief valves (i.e., staining
on the storage vessel), which may indicate over-pressure events that
have occurred when the storage vessel was being filled. We emphasize
that final 40 CFR 49.4173(c)(1) requires that all flashing, working,
standing and breathing losses from storage vessels must be routed
through a closed-vent system. This includes flashing losses during
filling events.
Comment: Industry commenters suggested that the FIP should include
language consistent with the provisions of NSPS OOOOa for unsafe and
difficult to monitor fugitive emissions components and delay of repair
if repair or replacement is technically infeasible, would require a
vent blowdown, compressor station shutdown, well shutdown or shut-in,
or would be unsafe to repair during operation of the unit.
Response: We agree and have revised the language of the proposed
FIP to include language more consistent with the difficult-to-monitor
and unsafe-to-monitor provisions of the NSPS, including exceptions for
the timelines to inspect and repair such fugitive emissions components
and requirements that the fugitive emissions plan include the
specialized timelines.
Comment: Environmental organization commenters asserted that, given
the urgent need to reduce ozone pollution in the Uinta Basin and the
high cost-effectiveness of LDAR, the FIP must require quarterly or
monthly LDAR surveys instead of the proposed semi-annual surveys, and
must require leaking equipment repair more quickly than 30 days after
discovering the leak. While the proposed requirements are consistent
with NSPS OOOOa, the commenters referenced that EPA either contemplated
during proposal or had required such provisions in previous versions of
NSPS OOOOa and that other oil and gas producing states impose such
requirements.
Response: Regarding LDAR survey frequency, we direct the reader to
our response to comments on LDAR applicability. We disagree with
commenters suggesting the final FIP should contain stricter procedural
LDAR requirements than are effective in NSPS OOOOa, including repair of
leaking equipment more quickly than 30 days after discovering the leak.
We determined that finalizing procedural LDAR requirements that are
consistent with NSPS OOOOa (and by extension, UDEQ oil and gas rules)
addresses the concern expressed by other commenters that affected
operators would have to comply with different fugitive emissions
monitoring programs than they are required to implement for sources in
the same area that are subject to NSPS OOOOa or the UDEQ Oil and Gas
Rules and will allow for more straightforward compliance throughout the
Basin. Implementing LDAR requirements in the final FIP that are
procedurally different than the requirements in NSPS OOOOa or the Utah
Oil and Gas rules may also potentially create disincentives for
development on the Reservation and of Tribally owned resources, leading
to economic disadvantages for the Ute Indian Tribe and its members.
While we appreciate the alternative cost information and comparison of
state oil and gas LDAR requirements provided by commenters, we do not
agree that the information provided is relevant to establishing
requirements for monitoring in the Uinta Basin for the purposes and
goals of this rulemaking. We determined that the LDAR procedural
requirements will still result in meaningful VOC emissions reductions
from LDAR on the Indian country lands within the U&O Reservation, while
avoiding a complex regulatory scheme for entities that operate some
sources subject to the FIP requirements and other sources subject to
NSPS OOOOa or requirements in areas where the EPA has approved the UDEQ
to implement the CAA.
E. Major Comments Concerning Recordkeeping and Reporting
Comment: Industry commenters suggested that the recordkeeping and
reporting requirements should align with those in the UDEQ regulations,
saying that the proposed FIP requirements were in many cases more
detailed, prescriptive and stringent than those in UDEQ regulations and
could result in discouraging oil and gas development on the U&O
Reservation. Examples provided of discrepancies in recordkeeping
requirements included that the UDEQ does not require annual compliance
reports or that records be kept of all required monitoring of
operations every time an operator is on site. The commenters referenced
other examples where the UDEQ requires certain records that were not
proposed in the U&O FIP. The commenters suggested recordkeeping and
reporting requirements should be limited to those that help demonstrate
compliance with the VOC emission reduction requirements, such as
records of instances when closed-vent-systems conveying emissions to a
control device bypass the device, records of observed
[[Page 75368]]
instances when the combustor or flare is inoperable or not operating
properly, as well as information on actual emissions. The commenters
encouraged the EPA to increase the number of recordkeeping requirements
in alignment with the UDEQ requirements in exchange for removing the
annual compliance reporting requirement.
Response: We agree with commenters that required elements of
recordkeeping and reporting in the final FIP should be limited to the
most relevant information to assure compliance with the emissions
control requirements of the FIP. We have revised the list of required
records accordingly and streamlined the required annual report content
to only include summaries of the records of the most relevant
information to demonstrate compliance. We disagree with commenters that
the U&O FIP should not require compliance reporting. Reporting at
regular intervals is an important mechanism to ensure that regulations
are enforceable as a practical matter. We recognize that the UDEQ
regulations do not require annual compliance reporting and are not
commenting on the efficacy of the UDEQ's regulations with this
response. It is not reasonable for the EPA to rely only on records to
assure compliance, particularly in an area with thousands of affected
facilities, as we do not have the resource capacity to visit every
facility to access them and it would be inefficient to use CAA section
114 authority on a case-by-case basis to obtain them. It is common for
the EPA to require both recordkeeping and reporting in CAA regulations,
using the broad authority of section 114, sufficient for practical
enforceability of the requirements and so that the public has
transparent access to records demonstrating compliance.
Comment: Commenters requested the proposed requirement to keep
records of the inspector signature be removed from the recordkeeping
and reporting requirements, because many operators have moved to
digital recordkeeping systems and physical signatures are not feasible
with those systems. Commenters instead requested that it would be
sufficient to just require inspector IDs be maintained and reported.
Response: We agree that recordkeeping and reporting requirements
should facilitate the increasing use of digital recordkeeping and have
finalized regulatory text in 40 CFR 49.4184(a)(1)(v)(D) accordingly to
require the inspector's name or identification number.
F. Major Comments Concerning Cost-Benefit Analysis
Comment: Industry commenters asserted that the cost benefit
analysis completed by the EPA for the proposed FIP lacked transparency
and relied on information collected over 5 years ago for the CTG,
failing to check the accuracy of the cost information included for that
action and disregarding information previously submitted for the
proposed CTG specific to VOC emissions control and storage vessel
retrofit costs. Commenters incorporated those comments by reference in
their comments to the proposed U&O FIP. The commenters also claimed
that the EPA did not account for all burdens and costs associated with
compliance with the VOC emissions control requirements, particularly
higher costs for retrofitting existing storage vessels with controls,
monthly storage vessel inspections and associated recordkeeping and
reporting costs.
Response: The EPA responded to the referenced comments submitted
for the draft CTG and we are, therefore, not including new responses to
those comments here.\126\ We note that in response to those comments,
the EPA did make small changes to the cost elements included in the
cost analysis for existing storage vessels that did not result in any
change to the EPA's recommended applicability threshold for storage
vessels in the final CTG. We based costs for retrofitting existing
storage vessels on those costs in the final CTG that included those
minor revisions. The costs recognize that it is more expensive to
retrofit existing storage vessels for emissions control than to install
controlled equipment upon construction. We did not update any of those
costs for the final FIP, as we did not receive any new cost information
on retrofitting storage vessels during the comment period for the
proposed FIP. We acknowledge that the EPA's Oil and Natural Gas Sector
Climate Review Proposed Rule \127\ uses updated costs and emissions
reduction estimates, including for fugitive emissions monitoring,
retrofitting of existing storage vessels, storage vessel monthly
inspections, installing zero emissions pneumatic devices, and
associated recordkeeping and reporting costs.128 129 In
order to achieve emissions reductions quickly and improve air quality
and public health within the U&O Reservation as soon as possible, we
have not updated our costs and emissions reductions estimates for the
final FIP using those proposed estimates. If we conclude that further
regulation is necessary or appropriate in the future, we will propose
action on it in a future U&O Reservation rulemaking in order to receive
public comment and would analyze any such rulemaking using the best
available costs and emissions reductions estimates at that time.
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\126\ Responses to Public Comments on the Draft Control
Techniques Guidelines for the Oil and Natural Gas Industry. Final
Document. October 2016. Available in https://www.regulations.gov,
Document ID No.EPA-HQ-OAR-2015-0216-0235, accessed Mar. 14, 2022.The
Response to Comments Document for the U&O FIP summarizes the
comments and the EPA's responses to those comments on the proposed
CTG, as they relate to various provisions of the proposed U&O FIP.
\127\ See 86 FR 63110, Nov. 15, 2021.
\128\ Regulatory Impact Analysis for the Proposed Standards of
Performance for New, Reconstructed, and Modified Sources and
Emissions Guidelines for Existing Sources: Oil and Natural Gas
Sector Climate Review. Nov. 14, 2021, available at https://www.regulations.gov, Document ID No. EPA-HQ-OAR-2021-0317-0173,
accessed Mar. 14, 2022.
\129\ Oil and Natural Gas Sector: Emission Standards for New,
Reconstructed, and Modified Sources and Emission Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review. October
2021, available at https://www.regulations.gov, Document ID No. EPA-
HQ-OAR-2021-0317-0166. In general, many of the cost factors used
were taken from technical support documents for earlier rulemakings,
such as the 2012 NSPS OOOO, the 2016 CTG and NSPS OOOOa, and the
2020 Technical Rule, and were only updated to reflect 2019$. Most of
the cost and emission reduction factors that were reevaluated for
the 2021 proposed rule evaluated alternative compliance options,
rather than significantly updating costs for control measures. Cost
factor changes were characterized as minor. For example, see Tables
12-8a and 12-8b.
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Comment: Industry commenters also incorporated by reference
portions of the comments they submitted for the draft CTG in their
comments on the proposed FIP with regard to LDAR costs being
underestimated.
Response: Again, the EPA previously responded to the referenced
comments in issuing the final CTG and, therefore, we are not including
new responses to those comments here. While we based the costs of
implementing an LDAR program at existing oil and natural gas sources
for the proposed FIP on those equivalent costs used for the final CTG,
since the proposed FIP was issued the EPA has issued final technical
revisions to NSPS OOOOa that included changes to fugitive emissions
monitoring costs and emissions reduction estimates.\130\ We have
updated our costs and emissions reductions estimates for the final U&O
FIP, relying in part on the updated fugitive emissions monitoring costs
and emissions reduction estimates
[[Page 75369]]
used for the final NSPS OOOOa revisions. We also acknowledge that the
EPA has published a proposed national rule to reduce methane and other
pollutants from existing, new, and modified sources in the oil and
natural gas industry \131\ that uses further updated fugitive emissions
monitoring costs and emissions reduction estimates. In order to achieve
emissions reductions quickly and improve air quality and public health
within the U&O Reservation as soon as possible, we have not updated our
costs and emissions reductions estimate for the final FIP using those
proposed estimates. If we conclude that further regulation is necessary
or appropriate in the future, we will propose action on it in a future
U&O Reservation rulemaking in order to receive public comment and would
analyze any such rulemaking using the best available costs and
emissions reductions estimates at that time.
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\130\ The Federal Register document for the rulemaking, known as
the technical amendments to the 2016 NSPS (85 FR 57398, Sept. 15,
2020), is available at https://www.regulations.gov, Document ID No.
EPA-HQ-OAR-2017-0483 2247, accessed Mar. 14, 2022.
\131\ See 86 FR 63110, Nov. 15, 2021.
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Comment: Environmental organization commenters asserted several
flaws in the EPA's cost-benefit analysis regarding the societal
benefits that will result from the avoided methane emissions due to VOC
emissions reductions under the FIP. The most prominent flaw the
commenters noted is the use of an interim value for the social cost of
methane (SC-CH4) that arbitrarily accounts only for domestic
benefits of reduced methane emissions, which diverted from previously
long-established and scientifically supported factors recognizing that
methane emissions reductions have global benefits. The commenters also
noted that the EPA arbitrarily discounted future climate effects at a 7
percent discount rate in addition to a 3 percent discount rate, which
is inconsistent with Circular A-4's requirements to distinguish social
discount rates from rates based on private returns to capital; to make
plausible assumptions; to adequately address uncertainty, especially
over long-time horizons; and to rely on the best available economic
data and literature.
Response: We acknowledge these comments and that EPA policies have
changed since we developed and analyzed the benefits of the proposed
U&O FIP. The SC-CH4 estimates presented in the RIA for the
final U&O FIP are the SC-CH4 estimates presented in the
Technical Support Document: Social Cost of Carbon, Methane, and Nitrous
Oxide Interim Estimates under Executive Order 13990 (IWG 2021)
(hereafter, ``February 2021 TSD''). EPA has evaluated the SC-
CH4 estimates in the February 2021 TSD and has determined
that these estimates are appropriate for use in estimating the social
benefits of CH4 emission reductions expected to result from
this final rule.\132\ These SC-CH4 estimates are interim
values developed for use in benefit-cost analyses until updated
estimates of the impacts of climate change can be developed based on
the best available science and economics. After considering the TSD,
and the issues and studies discussed therein, EPA concludes that it
agrees with the rationale for these estimates presented in the TSD and
summarized below.
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\132\ We note that the monetized climate benefits presented in
the RIA analysis and discussed here are not a part of the technical
or legal basis of this action but are instead presented as part of
the RIA analysis as required pursuant to Executive Orders, including
E.O. 12866.
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In particular, the IWG concluded that the SC-GHG estimates
developed under E.O. 13783, and used in the RIA of the proposed rule,
fail to reflect the full impact of GHG emissions in multiple ways.
First, the IWG concluded that those estimates fail to capture many
climate impacts that can directly and indirectly affect the welfare of
U.S. citizens and residents. Examples of affected interests include
direct effects on U.S. citizens and assets located abroad,
international trade, U.S. military assets and interests abroad, and
tourism, and spillover pathways such as economic and political
destabilization and global migration that can lead to adverse impacts
on U.S. national security, public health, and humanitarian concerns.
Those impacts are better captured within global measures of the social
cost of greenhouse gases.
In addition, assessing the benefits of U.S. GHG mitigation
activities requires consideration of how those actions may affect
mitigation activities by other countries, as those international
mitigation actions will provide a benefit to U.S. citizens and
residents by mitigating climate impacts that affect U.S. citizens and
residents. A wide range of scientific and economic experts have
emphasized the issue of reciprocity as support for considering global
damages of GHG emissions. Using a global estimate of damages in U.S.
analyses of regulatory actions allows the U.S. to continue to actively
encourage other nations, including emerging major economies, to take
significant steps to reduce emissions. The only way to achieve an
efficient allocation of resources for emissions reduction on a global
basis--and so benefit the U.S. and its citizens--is for all countries
to base their policies on global estimates of damages.
Therefore, for purposes of the RIA for this final rule EPA centers
attention on a global measure of SC-CH4. This approach is
the same as that taken in EPA regulatory analyses over 2009 through
2016, as well as in more recent regulatory analyses, including for the
Final Revised Cross-State Air Pollution Rule (CSAPR) Update for the
2008 Ozone NAAQS.\133\ The present value of net benefits is estimated
as the difference in the present values of monetized benefits and costs
calculated at the 3 percent percent discount rates. We do not discount
future climate effects at a 7 percent discount rate.
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\133\ Regulatory Impact Analysis for the Final Revised Cross-
State Air Pollution Rule (CSAPR) Update for the 2008 Ozone NAAQS
(EPA-452/R-21-002) (EPA Office of Air Quality Planning and
Standards, Mar. 2021); available at https://www.epa.gov/sites/default/files/2021-03/documents/revised_csapr_update_ria_final.pdf,
accessed July 30, 2021.
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Finally, a comprehensive estimate of climate damages to U.S.
citizens and residents does not currently exist in the literature.
Existing estimates are both incomplete and an underestimate of total
damages that accrue to the citizens and residents of the U.S. because
they do not fully capture the regional interactions and spillovers
discussed above, nor do they include all of the important physical,
ecological, and economic impacts of climate change recognized in the
climate change literature, as discussed further below. EPA, as a member
of the IWG, will continue to review developments in the literature,
including more robust methodologies for estimating the magnitude of the
various direct and indirect damages to U.S. populations from climate
impacts and reciprocal international mitigation activities, and explore
ways to better inform the public of the full range of carbon impacts.
While the IWG works to assess how best to incorporate the latest, peer
reviewed science to develop an updated set of SC-GHG estimates, it
recommended the interim estimates to be the most recent estimates
developed by the IWG prior to the group being disbanded in 2017. The
estimates rely on the same models and harmonized inputs and are
calculated using a range of discount rates.
The response to comments document and the RIA for the final FIP
provide more detailed discussion of the revised approach to estimating
climate benefits from reducing methane as a benefit to reducing VOC.
[[Page 75370]]
G. Other Comments of Significant Interest
Comments Concerning CAA Nonattainment Requirements
Comment: Environmental organization commenters asserted that CAA
general conformity requirements apply to the EPA's issuance of this
FIP, requiring a conformity analysis and a conformity determination.
Response: We disagree with these comments because under 40 CFR
93.153(a), the final action will not cause emissions increases above
the threshold required to trigger conformity requirements (i.e., no or
de minimis emissions increase, see 40 CFR 93.153(c)(2)).
Comment: Industry commenters asserted that the EPA should preserve
maximum flexibility for federal agencies to determine that their
actions conform and take steps to streamline conformity demonstrations,
such as including a statement that implementation of this FIP satisfies
federal agency general conformity obligations or a clarification that
all legal options for demonstrating conformity are available, including
those listed at 40 CFR 93.153(f), 93.158(a)(1), 93.158(a)(5)(i)(A),
93.158(a)(5)(i)(B), and 40 CFR 93.158(a)(5)(iv). One commenter asserted
that the EPA should clarify that the FIP is not a ``relevant''
implementation plan within the meaning of 40 CFR 93.158(a)(5)(iv) and
that approval of the final FIP will not limit federal agencies' ability
to rely on 40 CFR 93.158(a)(5)(iv) when demonstrating conformity.
Response: We disagree with these comments. We concluded that this
FIP is exempt from the general conformity requirements in 40 CFR part
93, subpart B (see 40 CFR 93.153(c)(2)). As such, the FIP does not
otherwise address general conformity or the responsibilities for the
EPA or other federal agencies and federal agencies authorizing new
emissions of NOX and VOC that are from sources not covered
by this FIP must conduct an applicability analysis, and must, if
project emissions are above the applicable de minimis thresholds, make
a conformity determination in accordance with 40 CFR part 93, subpart
B. This review would also consider whether any activities are on a
federal agency's Presumed to Conform List (PTC). (Individual federal
agencies can develop their own list of activities that are presumed to
conform (40 CFR 93.153(f) through (j)); to date, however, neither the
Ute Indian Tribe, BLM, the EPA, nor the state of Utah have developed a
PTC list for the Uinta Basin ozone nonattainment area.) Federal
agencies needing to make a general conformity determination have an
option available for the Indian country lands within the U&O
Reservation: Demonstrate that the emissions from the federal action are
fully offset within the nonattainment area through a revision to the
applicable SIP (or TIP or FIP) or an equally enforceable measure that
effects emissions reductions equal to or greater than the total of
direct and indirect emissions from the action so that there is no net
increase in emissions of that pollutant. 40 CFR 93.158(a)(5)(iii).
Comment: Environmental organization commenters asserted that the
EPA is required to directly address the ways in which this FIP will
have environmental justice implications and ensure that any final
action puts into practice environmental justice principles. The
commenters claimed that the EPA's environmental justice analysis for
the proposed FIP was insufficient in focusing only on demographic
information and concluding that the impacts would be positive for all
populations and failing to address whether the FIP will sufficiently
ameliorate the disproportionate public health impacts caused by high
ozone levels in the region.
Response: We agree that environmental justice implications are
required to be evaluated for any final U&O FIP action to improve the
degraded air quality in the Basin--the primary purpose for this
rulemaking. We expect this rulemaking to result in reductions of 23,000
tpy of VOC ozone precursor emissions on the Indian country lands within
the U&O Reservation and subsequent reductions in ground level ozone
formation in the Basin, which will reduce the adverse health impacts
caused by ozone for any population residing in the Basin, on and off
the Indian country lands within the U&O Reservation. We acknowledged in
the proposal that this FIP is an important initial step in bringing the
area back into attainment with the ozone NAAQS, but it is not expected
to meet the requirements of an attainment FIP that we may prepare per
the CAA if the area is bumped up to a Moderate nonattainment
classification or higher in the future. We anticipate that the effects
of this rulemaking will help demonstrate compliance in such future
actions, while allowing more time to improve our understanding of
emissions and our ability to model the full suite of actions necessary
to achieve NAAQS attainment. We made improvements in the environmental
justice analysis, contained in the RIA for this final rule, compared to
that for the proposed FIP, including incorporating data on potential
existing disproportionate impacts related to environmental burden,
socio-economic vulnerability, and health. Evaluation of the additional
data did not result in finalizing a substantially different rule than
was proposed and follows existing EPA guidance \134\ on environmental
justice in rulemaking per the directives to federal agencies in the
February 11, 1994, Presidential E.O. 12898 \135\ and the January 20,
2021, Presidential E.O. 13985.\136\
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\134\ According to the EPA's June 2016 Technical Guidance for
Assessing Environmental Justice in Regulatory Analysis, page 66 and
Section 2.1, the term ``disproportionate impacts'' refers to
differences in impacts or risks that are extensive enough that they
may merit Agency action. The determination of whether there is a
disproportionate impact that may merit Agency action is a policy
judgment informed by analysis of any discernable differences in
anticipated impacts from the rulemaking on population groups of
concern compared to all other population groups.
\135\ E.O. 12898, Federal Actions to Address Environmental
Justice in Minority Populations and Low-Income Populations, Feb. 11,
1994.
\136\ EPA expressed a commitment to conducting environmental
justice analysis for rulemakings based on a framework described in
the final revisions to the Cross-State Air Pollution Rule (86 FR
23054, 23162, Apr. 30, 2021). And E.O. 13895, Advancing Racial
Equity and Support for Underserved Communities Through the Federal
Government, Jan. 20, 2021.
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VII. Impacts of This Final FIP
A. Air Emissions Impacts
The EPA projects that from 2023 to 2032, relative to the baseline,
the final rule will result in about 23,000 tons of VOC emissions
reductions, 59,000 tons of methane emissions reductions, and 3,100 tons
of HAP emission reductions from affected oil and natural gas sources
annually. We have estimated regulatory impacts beginning in 2023 as it
is the first full year of implementation of this rule and have
estimated impacts through 2032 to illustrate the accumulating effects
of this rule over a longer period. The EPA did not estimate impacts
after 2032 for reasons including limited information, as explained in
the RIA.
B. Energy Impacts
There will likely be minimal change in emissions control energy
requirements resulting from this rule. Additionally, this final action
encourages the use of emission controls that recover hydrocarbon
products that can be used on-site as fuel or reprocessed within the
production process for sale. The energy impacts described in this
section are those energy requirements associated with the operation of
emission control devices.
[[Page 75371]]
Potential impacts on the national energy economy of the rule are
discussed in the economic impacts section.
C. Compliance Costs
The EPA estimates the total capital cost of the final FIP to be
$280 million for affected sources. We looked at the effect of recovered
methane as a cost saving measure. The value of recovered methane
amounted to $2.1 million per year. The net PV of the regulatory
compliance costs associated with this final rule over the 2023 to 2032
period when accounting for additional revenue from product recovery was
estimated to be $560 million (in 2016 dollars) using a 7 percent
discount rate and $610 million using a 3 percent discount rate. The net
EAV of these costs when accounting for additional revenue from product
recovery is estimated to be $81 million per year using a 7 percent
discount rate and $72 million using a 3 percent discount rate.
D. Economic and Employment Impacts
Executive Order 13563 directs Federal agencies to consider the
effect of regulation on job creation and employment. According to the
Executive order, ``our regulatory system must protect public health,
welfare, safety, and our environment while promoting economic growth,
innovation, competitiveness, and job creation. It must be based on the
best available science.'' (Executive Order 13563, 2011). While a
standalone analysis of employment impacts is not included in a standard
benefit-cost analysis, such an analysis is of concern in the current
economic climate given continued interest in the employment impact of
regulations such as this final rule.
With respect to energy markets, the EPA has concluded that, while
this action may affect the supply, distribution or use of energy, it is
not likely to have significant energy market effects. For small
entities, we conducted a screening analysis. Based on the results of
this screening analysis, which is presented in the RIA for the final
FIP, the EPA concluded that that the rule will not have a Significant
Impact on a Substantial Number of Small Entities (SISNOSE). For
employment impacts, we did not perform a quantitative analysis on all
categories of employment changes as a result of the rule. This rule is
expected to result in little change in oil and natural gas exploration
and production and is not expected to result in significant changes to
employment dedicated to these tasks. The EPA did, however, in its cost
analysis for the rule, estimate changes in labor due to compliance
activities. As presented in the RIA for this action, the EPA projected
there will be increases in the labor required for compliance-related
activities associated with this final rule. As the rule imposes VOC
emission control requirements that are consistent with federal
standards for the oil and natural gas industry that apply nation-wide
or rules for similar sources that apply in areas of the Basin where the
EPA has approved the UDEQ to implement the CAA, we expect that many
operators of affected oil and natural gas sources may already have
sufficient systems established for complying with the federal standards
for other sources they operate in the Basin, and therefore labor
impacts may be overstated in our estimates.
E. Benefits
The EPA expects climate and health benefits due to the VOC
emissions reductions projected under this final rule, as well as
climate benefits from methane emissions reductions. Climate benefits
from reducing emissions of CH4 can be estimated and
monetized using interim estimates of the social cost of methane (SC-
CH4). The SC-CH4 estimates used here are the SC-
CH4 estimates presented in the Technical Support Document:
Social Cost of Carbon, Methane, and Nitrous Oxide Interim Estimates
under Executive Order 13990 (IWG 2021) (hereafter, ``February 2021
TSD''). EPA has evaluated the SC-CH4 estimates in the
February 2021 TSD and has determined that these estimates are
appropriate for use in estimating the social benefits of CH4
emission reductions expected to result from this final rule. These SC-
CH4 estimates are interim values developed for use in
benefit-cost analyses until updated estimates of the impacts of climate
change can be developed based on the best available science and
economics. EPA and other agencies intend to undertake a fuller update
of the SC-GHG estimates that takes into consideration the advice of the
National Academies and other recent scientific literature.
We note that the methodology underlying the SC-CH4 estimates used
in this RIA been subject to public comment in the context of dozens of
proposed rulemakings as well as in a dedicated public comment period in
2013. Further, the monetized climate benefits presented in this
analysis are not a part of the technical or legal basis of the proposed
action for which the RIA was prepared. Rather, the monetized benefits
associated with projected reductions in greenhouse gas emissions that
may result from the final rule are presented solely for purposes of
compliance with E.O. 12866 and to present the public with information
regarding the full scope of potential benefits of the final rule. We
note that there is an ongoing interagency process to update the SC-GHG
estimates, including the SC-CH4 estimates used in this analysis, and
there will be further opportunity to provide public input on the SC-GHG
methodology through that process.\137\ The RIA for the final FIP
provides a more detailed discussion of the approach to estimating
climate benefits from reducing methane as a benefit to reducing VOC.
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\137\ For example, EPA, on behalf of the IWG, published a
Federal Register document on January 25, 2022, to solicit public
nominations of scientific experts for the upcoming peer review the
forthcoming update. See https://www.federalregister.gov/documents/2022/01/25/2022-01387/request-for-nominations-of-experts-for-the-review-of-technical-support-document-for-the-social-cost. EPA has a
web page where additional information regarding the peer review
process will be posted as it becomes available: https://www.epa.gov/environmental-economics/scghg-tsd-peer-review. There will be a
separate Federal Register document for the public comment period on
the forthcoming SC-GHG technical support document once it is
released.
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The EPA estimated the PV of monetized climate benefits over the
2023 to 2032 period to be $1 billion using a 3 percent discount rate
and estimated the PV of monetized net benefits to be $390 million using
a 3 percent discount rate and $440 million using a 7 percent discount
rate for costs and a 3 percent discount rate for benefits. We estimate
the EAV of monetized climate benefits over the 2023 to 2032 period to
be $120 million using a 3 percent discount rate. We estimated the EAV
of net benefits to be $48 million using a 3 percent discount rate for
both benefits and costs. We estimated the EAV of net benefits to be $39
million using a 3 percent discount rate for benefits and a 7 percent
discount rate for costs.\138\ These values do not account for health
effects of ozone exposure from the decrease in methane emissions. Under
the final rule, the EPA expects that VOC emissions reductions will
improve air quality and are likely to result in health and welfare
benefits associated with reduced exposure to ozone, PM2.5,
and HAP, but we did not quantify these effects at this time due to the
data limitations described below. This omission should not imply that
these benefits may not exist; rather, it reflects
[[Page 75372]]
the inherent difficulties in accurately modeling the direct and
indirect impacts of the projected VOC emissions reductions for the oil
and natural gas industry in the Uinta Basin. To the extent that the EPA
were to quantify these ozone and PM impacts, it would estimate the
number and value of avoided premature deaths and illnesses using an
approach detailed in the Particulate Matter NAAQS and Ozone NAAQS
RIAs.\139\ This approach relies on full-form air quality modeling for
the oil and natural gas source category that would be suitable for use
in regulatory analysis in the context of NSPS, including ways to
address the uncertainties regarding the scope and magnitude of VOC
emissions.
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\138\ As explained in the RIA, For the presentational purposes,
we discuss the benefits associated with the average SC-
CH4 at a 3 percent discount rate, but the Agency does not
have a single central SC-CH4 point estimate. The EAV of
benefits at a 3 percent discount rate is used to estimate the net
benefits at a 7 percent discount rate for costs.
\139\ U.S. EPA. December 2012. ``Regulatory Impact Analysis for
the Final Revisions to the National Ambient Air Quality Standards
for Particulate Matter.'' EPA-452/R-12-005. Office of Air Quality
Planning and Standards, Health and Environmental Impacts Division,
available in the docket for this rulemaking (Docket ID No. EPA-R08-
OAR-2015-0709).
U.S. EPA. September 2015. ``Regulatory Impact Analysis of the
Final Revisions to the National Ambient Air Quality Standards for
Ground-Level Ozone.'' EPA-452/R-15-007. Office of Air Quality
Planning and Standards, Health and Environmental Impacts Division,
available in the docket for this rulemaking (Docket ID No. EPA-R08-
OAR-2015-0709).
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When quantifying the incidence and economic value of human health
impacts of air quality changes, the Agency sometimes relies upon
alternative approaches to using full-form air quality modeling, called
reduced-form techniques, often reported as ``benefit-per-ton'' values
that relate air pollution impacts to changes in air pollutant precursor
emissions.\140\ Several studies have discussed the air quality and
health impacts from the oil and natural gas industry.\141\ The Agency
believes more work needs to be done to vet the analysis and
methodologies for all potential approaches to valuing the health
effects of VOC emissions changes in areas experiencing elevated winter
ozone before they are used in regulatory analysis, but is committed to
continuing this work. Recently, the EPA systematically compared the
changes in benefits, and concentrations where available, from its
benefit-per-ton technique and other reduced-form techniques to the
changes in benefits and concentrations derived from full-form
photochemical model representation of a few different specific
emissions scenarios.\142\ The Agency's goal was to create a methodology
by which investigators could better understand the suitability of
alternative reduced-form air quality modeling techniques for estimating
the health impacts of criteria pollutant emissions changes in the EPA's
benefit-cost analysis, including the extent to which reduced form
models may over-or-under-estimate benefits (compared to full-scale
modeling) under different scenarios and air quality concentrations. The
EPA Science Advisory Board (SAB) recently convened a panel to review
this report.\143\ In particular, the SAB will assess the techniques the
Agency used to appraise these tools; the Agency's approach for
depicting the results of reduced-form tools; and steps the Agency might
take for improving the reliability of reduced-form techniques for use
in future RIAs.
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\140\ U.S. EPA. 2018. ``Technical Support Document: Estimating
the Benefit per Ton of Reducing PM2.5 Precursors from 17
Sectors.'' February, available in the docket for this rulemaking
(Docket ID No. EPA-R08-OAR-2015-0709).
\141\ Fann, N., K.R. Baker, E.A.W. Chan, A. Eyth, A. Macpherson,
E. Miller, and J. Snyder. 2018. ``Assessing Human Health
PM2.5 and Ozone Impacts from U.S. Oil and Natural Gas
Sector Emissions in 2025.'' Environmental Science and Technology
52(15):8095-8103.
Litovitz, A., A. Curtright, S. Abramzon, N. Burger, and C.
Samaras. 2013. ``Estimation of Regional Air-Quality Damages from
Marcellus Shale Natural Gas Extraction in Pennsylvania.''
Environmental Research Letters 8(1), 014017.
Loomis, J. and M. Haefele. 2017. ``Quantifying Market and Non-
market Benefits and Costs of Hydraulic Fracturing in the United
States: A Summary of the Literature.'' Ecological Economics 138:160-
167.
\142\ This analysis compared the benefits estimated using full-
form photochemical air quality modeling simulations (CMAQ and CAMx)
against four reduced-form tools: InMAP, AP2/3 EASIUR, and the EPA's
benefit-per-ton.
\143\ 85 FR 23823 (Apr. 29, 2020).
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VIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is an economically significant regulatory action that
was submitted to the Office of Management and Budget (OMB) for review.
Any changes made in response to OMB recommendations have been
documented in the docket. The EPA prepared an analysis of the potential
costs and benefits associated with this action. This analysis,
``Regulatory Impact Analysis of the Final 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 VII. Impacts of this Final FIP.
B. Paperwork Reduction Act (PRA)
The information collection activities in this rule will be
submitted for approval to the Office of Management and Budget (OMB)
under the PRA. The Information Collection Request (ICR) document that
the EPA prepared has been assigned EPA ICR number 2539.02. You can find
a copy of the ICR in the docket for this rule, and it is briefly
summarized here. The information collection requirements are not
enforceable until OMB approves them.
This final action imposes a new information collection burden under
the PRA. The ICR covers information collection necessary to meet the
requirements in this U&O FIP. In general, owners or operators are
required to maintain records of required monitoring and other rule
compliance. This U&O FIP also requires annual reports containing
information for each oil and natural gas source, including a summary of
certain required records during the reporting period, and a summary of
certain instances where operation was not performed in compliance with
the requirements of this 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 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.
The EPA received one comment letter specifically on the ICR for the
proposed U&O FIP, as well as several other comments related to the
monitoring, recordkeeping, and reporting in the proposed rule. The EPA
responded to these comments, as summarized in Sections VI.E and F. of
this preamble and in the response to comments document in the docket
for this rulemaking.\144\
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\144\ Response to Public Comments, Proposed Federal
Implementation Plan: Managing Emissions from Oil and Natural Gas
Sources on Indian Country Lands within the Uintah and Ouray Indian
Reservation in Utah, April 2022, available in the docket for this
rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
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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
[[Page 75373]]
to protect tribal air resources. Promulgating this U&O FIP will address
winter ozone air quality concentrations that exceed the NAAQS, and
given the 2015 ozone NAAQS marginal 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
Indian country lands within 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 Indian country lands
within 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 in areas where the EPA has approved the UDEQ to implement
the CAA, which are governed by the UDEQ regulations and Utah Division
of Oil, Gas, and Mining regulations. Consistent with the regulatory
structure that exists in those areas, this 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 an average of
6,870 oil and natural gas sources will be subject to one or more
requirements in this U&O FIP over the next three years (including the
requirement to report triennial emissions inventories as one
requirement).
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: 154,630 hours per year (3-year average),
for all operators subject to this U&O FIP.
Total estimated cost: $26.2 million per year (3-year average);
includes labor cost of $9.6 million, annualized capital cost of $10.4
million, and $6.1 million in operation and maintenance costs for all of
the operators that would subject to this 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. When OMB
approves this ICR, the Agency will announce that approval in the
Federal Register and publish a technical amendment to 40 CFR part 9 to
display the OMB control number for the approved information collection
activities contained in this final rule.
C. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. The
small entities subject to the requirements of this action are owners/
operators of oil and natural gas sources on the Indian country lands
within the U&O Reservation. They were identified through a screening
analysis of existing oil and natural gas sources and emissions
submitted by owners/operators on the Indian country lands within the
U&O Reservation under UBEI2017-Update. The Agency has determined that
only two out of 14 total small entities, or 14 percent, may experience
an annualized cost impact of 1 percent to 3 percent of annual revenues,
and thus may potentially incur significant economic impact. It was
determined that the other 12 small entities would incur annualized
costs less than 1 percent of annual sales, and therefore, are not
expected to incur significant economic impacts from this rule. Details
of this analysis are presented in the RIA and can be viewed in the
docket for this rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
D. Unfunded Mandates Reform Act (UMRA)
This final 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 or the
private sector.
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 VII. Impacts of this Final FIP, the
estimated equivalent annualized costs of this rule in 2023, accounting
for additional revenue from recovered natural gas, are $81 million in
2016 dollars using a 7 percent discount rate and $72 million in 2016
dollars using a 3 percent discount rate.\145\ EPA estimates that the
rule will lead to equivalent annual monetized benefits of about $120
million using a 3 percent discount rate. The quantified equivalent
annualized net benefits of the regulation (the difference between the
equivalent annualized monetized benefits and net equivalent annualized
compliance costs) are estimated to be $39 million in 2016 dollars using
a 7 percent discount rate and $48 million using a 3 percent discount
rate.\146\ More in-depth information on costs and benefits of the final
regulation can be found in the RIA, including certain climate benefits
and other benefits that were not quantified or monetized.\147\
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\145\ The recordkeeping and reporting costs calculated for the
ICR analysis, discussed earlier, are imbedded in the total
annualized engineering costs included here.
\146\ Benefits (methane reductions) were only calculated at a 3
percent discount rate, as that is the only rate that both cost and
benefit analyses have in common. Therefore, the net benefits for the
7 percent discount rate were compared to benefits at a 3 percent
discount rate to calculate the annualized net benefits of the final
rule. The RIA in the docket for this rulemaking discusses this
calculation in detail.
\147\ 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
final rule for affected entities within the oil and natural gas
industry, including the installation, operation, and maintenance of
control equipment and control activities, as well as the labor
associated
[[Page 75374]]
with new reporting and recordkeeping requirements. We did not estimate
any potential changes in labor outside of the affected industry, and
due to data and methodology limitations we did not estimate net
employment impacts for the affected industry, 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). Option 1
would not include control of emissions from glycol dehydrators. This is
in contrast to preferred Option 2, which requires control of emissions
from glycol dehydrators where the source-wide VOC emissions from the
collection of all storage vessels, glycol dehydrators and pneumatic
pumps is equal to or greater than 4 tpy per 40 CFR 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 vessels with
controls or require controls less broadly. Retrofitting existing
storage vessels with controls is one of the higher costs evaluated in
this rulemaking. Such an option, however, would lead to even greater
disparity with the requirements for similar sources in in areas of the
Basin where the EPA has approved the UDEQ to implement the CAA than
Option 1. Option 3 (high impact) would require implementation of an
LDAR program at all existing oil and natural gas sources, regardless of
daily production, or storage vessel, dehydrator, and pneumatic pump
annual VOC emissions. We sought comment on the proposed FIP for whether
it was appropriate to consider less or more stringent regulatory
options, for example, an option that does not include retrofitting
existing storage vessels for controls. We acknowledged that if comments
supported finalizing less or more stringent regulatory options as
viable and if the agency decided to adopt an option that was not
offered in the proposal, the EPA may be required to hold an additional
public comment period on this rulemaking. We did receive comments
asserting both that less stringent and more stringent options were
appropriate for this rulemaking. We summarized our responses to
comments related to the regulatory options evaluated in the response to
comments document in the docket for this rulemaking.\148\
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\148\ Response to Public Comments, Proposed Federal
Implementation Plan: Managing Emissions from Oil and Natural Gas
Sources on Indian Country Lands within the Uintah and Ouray Indian
Reservation in Utah, March 2022, available in the docket for this
rulemaking (Docket ID No. EPA-R08-OAR-2015-0709).
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The EPA estimates the equivalent annualized costs of the preferred
option in 2023 in 2016 dollars using a 7 percent discount rate when
accounting for additional revenue from product recovery are $81 million
($3,500 per ton of VOC reduced). When using a 3 percent discount rate,
the estimates of total equivalent annualized costs of the final FIP
when accounting for additional revenue from product recovery are $72
million when accounting for additional revenue from product recovery
($3,200 per ton of VOC reduced).
The equivalent annualized costs of the less stringent option
(Option 1) when accounting for additional revenue from product recovery
would be $77 million in 2023 in 2016 dollars using a 7 percent discount
rate, resulting in a cost of control of $4,100 per ton of the estimated
19,000 tons of VOC reduced, and $69 million in 2023 using a 3 percent
discount rate, resulting in a cost of control of $3,600 per ton of VOC
reduced. Option 1 was analyzed to reduce burden on small entities,
while still achieving meaningful VOC emissions reductions. Although
this option would cost less overall than preferred Option 2, it would
achieve less benefits in the form of VOC emissions reductions (19,000
tons versus 23,000 tons for final Option 2), as emissions from glycol
dehydrators would not be controlled and a smaller number of oil and
natural gas sources would be required to control storage vessels and
pneumatic pumps, because a larger amount of VOC emissions would be
required from the collection of all storage vessels and pneumatic pumps
at sources that also have glycol dehydrators in order to trigger the
control applicability threshold than under Option 2.\149\ 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 vessels, pneumatic pumps and
fugitive emissions. Implementation of Option 1 would also result in
regulatory requirements that are inconsistent with the requirements for
equivalent sources in areas of the Basin where the EPA has approved the
UDEQ to implement the CAA, thus not meeting our goal of regulatory
consistency across the Uinta Basin.
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\149\ Under Option 1, the EPA would determine the 4 tpy
threshold triggering control with source-wide potential VOC
emissions from the collection of all storage vessels and pneumatic
pumps only.
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The equivalent annualized costs of the most stringent option
(Option 3) when accounting for additional revenue from product recovery
would be $88 million in 2023 in 2016 dollars using a 7 percent discount
rate, resulting in a cost of control of $3,500 per ton of the estimated
25,000 tons of VOC reduced, and $79 million in 2023 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 preferred Option 2 (25,000
tons versus 23,000 tons for final Option 2), it would also result in
increased costs (though the cost of control per ton of VOC reduced
would be about the same as Option 2). Additionally, Option 3 would
result in regulatory requirements that are inconsistent with the
requirements for equivalent sources in areas of the Basin where the EPA
has approved the UDEQ to implement the CAA, 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
final U&O FIP.
E. Executive Order 13132: Federalism
This final 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.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This final action has tribal implications, because it establishes
rules affecting a substantial number of industrial operations in Indian
country within the U&O Reservation. The emissions improvement measures
required by this rule will benefit the health and welfare of members of
the Tribe. In addition, some of these
[[Page 75375]]
operations provide revenue to the Ute Indian Tribe, directly or
indirectly. For example, the Tribe benefits from royalties paid by
companies developing oil and natural gas resources on the Indian
country lands within the U&O Reservation, which are administered by the
U.S. Bureau of Indian Affairs. However, this rule will neither impose
substantial direct compliance costs on federally recognized tribal
governments, nor preempt tribal law.
The EPA consulted with tribal officials under the EPA Policy on
Consultation and Coordination with Indian Tribes early in the process
of developing this regulation to permit them to have meaningful and
timely input on its development. A summary of that consultation and
other communications with the Ute Indian Tribe follows. The EPA has
conducted outreach on this final rule consistent with the EPA Policy on
Consultation and Coordination with Indian Tribes (May 4, 2011) via
ongoing monthly meetings with tribal environmental professionals \150\
before and during the development of this final action, and further as
follows: (1) via formal Tribal consultation and informal informational
meetings 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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\150\ 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; February 28, 2019; April 2, 2019; February 5, 2020;
and August 2, 2022. The EPA has also participated in tribally convened
stakeholder meetings on March 22, 2017, and June 1-2, 2017, as well as
many informal informational meetings with tribal elected officials and
air quality staff.\151\
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\151\ The records of communication for all formal consultations
and other 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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During the consultations and other discussions on this 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 reconcile regulatory
requirements for an even economic and regulatory playing field. 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 Indian country lands within 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.
Enacting a FIP for Indian country lands within the U&O Reservation
is directly responsive to the Ute Indian Tribe's air quality concerns
in that we are implementing 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 in areas of the Basin
where the EPA has approved the UDEQ to implement the CAA. We are
committed to supporting tribes' right to self-governance and to
protecting their inherent sovereignty. Throughout development of this
final action, we continued to provide outreach to tribal environmental
professionals and continued consultation with tribal leadership.
As required by section 7(a), the EPA's Tribal Consultation Official
has certified that the requirements of the executive order have been
met in a meaningful and timely manner. A copy of the certification is
included in the docket for this action.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is subject to Executive Order 13045 because it is an
economically significant regulatory action as defined by Executive
Order 12866 and the EPA has concluded that the environmental health or
safety risk addressed by this final action has a disproportionate
effect on children. Accordingly, we have evaluated the environmental
health or safety effects of exposure to elevated ozone concentrations
on children. This action's health and risk assessments are contained in
the Impacts of this Final FIP and Executive Order 12898: Federal
Actions to Address Environmental Justice in Minority Populations and
Low-Income Populations sections in this preamble (sections VII. and
VIII.K., respectively), with more detailed information contained in the
RIA for this rulemaking.\152\ This final U&O FIP should have a positive
effect on the health of the residents of the Indian country lands
within 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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\152\ 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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H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action is not a ``significant energy action'', because it is
not likely to have a significant adverse effect on the supply,
distribution, or use of energy. The basis for these determinations
follows.
The EPA prepared an analysis of the potential costs and benefits
associated with this action, which is included in the RIA,\153\ and is
summarized in Section VII. Impacts of this Final FIP. Based on this
analysis, 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
[[Page 75376]]
effects. Most owners/operators of existing oil and natural gas
production sources on Indian country lands within 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 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 source
category-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 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.\154\
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\153\ 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).
\154\ 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 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 rule, please
see the RIA, which is in the docket for this rule.
I. 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 and none were brought to its
attention in comments. \155\ 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.\156\
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\155\ ``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 Dec. 22, 2017,
available in the Docket for this rulemaking (Docket ID No. EPA-R08-
OAR-2015-0709).
\156\ 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 Mar. 14, 2022.
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J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
While the EPA finds that communities in the Uinta Basin with higher
proportions of low-income populations and people of color rank in the
90th percentile for ozone concentrations in the baseline based on
EJSCREEN, 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.\157\
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\157\ See 59 FR 7629 (Feb. 16, 1994).
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The documentation for this decision is contained in the RIA \158\
for this final rule. Our objective in developing this rule is to
improve air quality and thereby protect the communities in the Uinta
Basin, including those 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 final 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
VII.A. of this preamble, the EPA has quantified the expected emissions
impacts from this final action and found that the action will result in
large reductions of VOC emissions.
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\158\ 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 final action will also provide regulatory certainty to owners/
operators, by imposing, to the extent appropriate, requirements that
are the same as or consistent with those applicable to such existing
sources that in areas of the Basin where the EPA has approved the UDEQ
to implement the CAA because they are not on Indian country lands
within the Reservation. This will ensure that economic impacts are
consistent and air quality is protected consistently across the Uinta
Basin. Our Environmental Justice (EJ) analysis that can be found in the
RIA for this rulemaking supports the conclusion that this action is not
expected to result in disproportionate impacts.
K. Congressional Review Act (CRA)
This action is subject to the CRA, and the EPA will submit a rule
report to each House of the Congress and to the Comptroller General of
the United States. This action is a ``major rule'' as defined by 5
U.S.C. 804(2).
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.
Michael S. Regan,
Administrator.
For reasons set forth in the preamble, part 49 of title 40 of the
Code of Federal Regulations is 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''
immediately following Sec. 49.4168 and add Sec. Sec. 49.4169 through
49.4184 to subpart K to read as follows:
Subpart K-Implementation Plans for Tribes-Region VIII
* * * * *
[[Page 75377]]
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 VOC emissions control requirements for storage vessels.
49.4174 VOC emissions control requirements for dehydrators.
49.4175 VOC emissions control requirements for pneumatic pumps.
49.4176 VOC emissions control requirements for covers and closed-
vent systems.
49.4177 VOC emissions control devices.
49.4178 VOC emissions control requirements for fugitive emissions.
49.4179 VOC emissions control requirements for tank truck loading.
49.4180 VOC emissions control requirements for pneumatic
controllers.
49.4181 Other combustion devices.
49.4182 Monitoring and testing requirements.
49.4183 Recordkeeping requirements.
49.4184 Notification and reporting requirements.
Sec. 49.4169 Introduction.
(a) What is the purpose of Sec. Sec. 49.4169 through 49.4184?
Sections 49.4169 through 49.4184 establish legally and practicably
enforceable requirements for oil and natural gas sources on Indian
country lands within the Uintah and Ouray Indian Reservation (U&O
Reservation) 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 Federal Implementation Plan
(U&O FIP). Section 49.4171 contains general provisions and definitions
applicable to oil and natural gas sources. Sections 49.4173 through
49.4184 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 that
are located on Indian country lands within the U&O Reservation.
(b) Am I subject to Sec. Sec. 49.4169 through 49.4184? Sections
49.4169 through 49.4184, as appropriate, apply to each owner or
operator of an oil and natural gas source (as defined at 40 CFR 49.102)
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 U&O FIP.
(c) When must I comply with Sec. Sec. 49.4169 through 49.4184? For
oil and natural gas sources that commence construction before February
6, 2023, compliance with Sec. Sec. 49.4169 through 49.4171 and
Sec. Sec. 49.4173 through 49.4184, as applicable, is required no later
than February 6, 2024. You may submit a written request to the EPA for
an extension of the compliance date for existing sources. The extension
request must be submitted to the EPA at least 60 days before the
compliance deadline, must identify the specific provision(s) for which
you seek an extension, must include an alternative compliance
deadline(s), and must provide the rationale for the requested extension
with supporting information explaining how you will effectively meet
all applicable requirements after the requested alternative compliance
deadline. Any decision to approve or deny a request, including the
length of time of an approved request, will be based on the merits of
case-specific circumstances. For oil and natural gas sources that
commence construction on or after February 6, 2023, compliance with
Sec. Sec. 49.4169 through 49.4171 and Sec. Sec. 49.4173 through
49.4184, as applicable, is required upon startup.
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 U&O FIP. This section provides for
administrative delegation and does not affect the eligibility criteria
under Sec. 49.6 for treatment in the same manner as a state.
(b) How does the Ute Indian Tribe request delegation? To be
delegated authority to assist the EPA with administration of this 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) with 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 on 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 the EPA 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 document in the Federal Register informing
the public of any Delegation of Authority Agreement with the Ute Indian
Tribe to assist the EPA with administration of all or a portion of the
FIP and identifying such delegation in the FIP. The EPA will also
publish an announcement of the Delegation of Authority Agreement in
local newspapers.
[[Page 75378]]
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 crude oil,
condensate, intermediate hydrocarbon liquid, or produced water, and gas
collection, storage, processing, and handling operations covered under
Sec. Sec. 49.4171 and 49.4173 through 49.4184, 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.
Determination of whether acceptable operating and maintenance
procedures are being used will be based on information available to the
Administrator, including monitoring results, review of operating and
maintenance procedures, and inspection of the source.
(b) Definitions. As used in Sec. Sec. 49.4169 through 49.4184, all
terms not defined have the meaning given them in the Act, in 40 CFR
parts 60 and 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 Sec. 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 Sec. 49.102.
The following terms are defined here:
Bottom filling means the filling of a storage vessel through an
inlet at or near the bottom of the storage vessel 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.
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 flare. A combustion device is not considered a flare when
installed horizontally or vertically within an open pit and used to
combust produced natural gas during initial well completion or
temporarily during emergencies when enclosed combustors or flares
installed at a source are not operational or injection of recovered
produced natural gas is unavailable.
Flashing losses means natural gas emissions resulting from the
presence of dissolved natural gas in the crude oil, condensate,
intermediate hydrocarbon liquids or produced water, which are under
high pressure that occurs as the liquids are transferred to storage
vessels 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, flanges, covers and closed vent systems not subject to Sec.
49.4176, thief hatches or other openings on a controlled storage vessel
not subject to Sec. 49.4173, compressors, instruments, and meters.
Devices that vent as part of normal operations, such as natural gas-
driven pneumatic controllers or natural gas-driven pneumatic 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 locations other than the device's
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).
Indian country is defined at 18 U.S.C. 1151 and means.
(i) 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,
(ii) 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
(iii) All Indian allotments, the Indian titles to which have not
been extinguished, including rights-of-way running through the same.
Intermediate hydrocarbon liquids means any naturally occurring,
unrefined petroleum liquid.
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 controller means a natural gas-driven pneumatic
controller as defined at 40 CFR 60.5430 and 60.5430a.
Pneumatic pump means a natural gas-driven diaphragm pump as defined
at 40 CFR 60.5430a.
Pneumatic pump emissions means the VOC-containing emissions from
pneumatic pumps.
Produced natural gas means natural gas that is separated from
extracted reservoir fluids during oil and natural gas production
operations.
Produced water means water that is extracted from the earth from an
oil or natural gas production well, or that is separated from crude
oil, condensate, or natural gas after extraction.
Regional Administrator means the Regional Administrator of EPA
Region 8 or an authorized representative of the Regional Administrator
of EPA Region 8, except to the extent otherwise specifically specified
in a Delegation of Authority Agreement between the Regional
Administrator and the Ute Indian Tribe.
Repaired means, for the purposes of fugitive emissions components,
that fugitive emissions components are adjusted, replaced, or otherwise
altered in order to eliminate fugitive emissions as defined in Sec.
49.4178(d)(1)(iii), and subsequently monitored as specified in Sec.
49.4178(d)(1)(ii), and that it is verified that emissions from the
fugitive emissions components are below the applicable fugitive
emissions definition.
Standing and breathing losses means VOC emissions from fixed-roof
storage vessels as a result of evaporative losses during storage.
Storage vessel means a tank or other vessel that contains an
accumulation of crude oil, condensate, intermediate hydrocarbon
liquids, or produced water, and that is constructed primarily of non-
earthen materials (such as wood,
[[Page 75379]]
concrete, steel, fiberglass, or plastic), which provide structural
support. A well completion vessel that receives recovered liquids from
a well after startup of production following flowback for a period
which exceeds 60 days is considered a storage vessel under this
subpart. A tank or other vessel will not be considered a storage vessel
if it has been removed from service in accordance with the requirements
of Sec. 49.4173(a)(3), until that tank or other vessel has been
returned to service. For the purposes of this subpart, the following
are not considered storage vessels:
(i) Vessels that are skid-mounted or permanently attached to
something that is mobile (such as trucks, railcars, barges or ships),
and are intended to be located at a site for less than 180 consecutive
days. If you do not keep or are not able to produce records, as
required by Sec. 49.4183(a)(1)(iv), showing that the vessel has been
located at a site for less than 180 consecutive days, the vessel is
considered to be a storage vessel from the date it was first located at
the site. This exclusion does not apply to a well completion vessel as
described above.
(ii) Process vessels such as surge control vessels, bottoms
receivers, and knockout vessels.
(iii) Pressure vessels designed to operate in excess of 204.9
kilopascals and without emissions to the atmosphere.
Submerged fill pipe means any fill pipe with a discharge opening
that is entirely submerged when the liquid level is six inches above
the bottom of the storage vessel and the pipe normally used to withdraw
liquid from the storage vessel 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.
Visible smoke emissions means 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 not constitute visible
smoke emissions.
Working losses means natural gas emissions from fixed roof storage
vessels 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), 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 must submit an inventory for
every third year, beginning with the 2023 calendar year, for all
emission units at a source.
(c) The inventory must include the total emissions for
PM10, PM2.5, oxides of sulfur, nitrogen oxides,
carbon monoxide, and volatile organic compounds, as defined at 40 CFR
51.50, for each emissions unit at the source. Emissions for each
emissions unit at the source must be calculated using the emissions
unit's actual operating hours, appropriate emissions rates, the use of
performance test results where applicable, product rates and types of
materials processed, stored, or combusted during the calendar year of
the reporting period.
(d) The inventory must include the type and efficiency, for each
pollutant controlled, of any air pollution control equipment present at
the reporting source. The detail of the emissions inventory must be
consistent with the detail and data elements required by 40 CFR part
51, subpart A.
(e) The inventory must be submitted to the EPA no later than April
15th of the year following each inventory year.
(f) The inventory must be submitted in an electronic format
specific to this source category, as instructed on the EPA Region 8
website at https://www.epa.gov/air-quality-implementation-plans/approved-air-quality-implementation-plans-region-8.
Sec. 49.4173 VOC emissions control requirements for storage vessels.
(a) Applicability. The VOC emissions control requirements of this
section apply to storage vessels at an oil and natural gas source (as
specified in Sec. 49.4169(b)) as follows:
(1) For oil and natural gas sources that began operations before
February 6, 2023, the VOC emissions control requirements of this
section apply when the source-wide potential for VOC emissions from the
collection of all storage vessels, glycol dehydrators, and pneumatic
pumps is equal to or greater than 4 tpy, as determined according to
this section. The potential for VOC emissions must be calculated using
a generally accepted model or calculation methodology, based on the
maximum average daily throughput determined for a 30-day period of
production during the 12 months before the compliance deadline for the
affected source under this rule. The determination may take into
account requirements under a legally and practicably enforceable limit
in an operating permit or other federally enforceable requirement. You
must reevaluate the source-wide VOC emissions from the collection of
all storage vessels, glycol dehydrators and pneumatic pumps for each
modification to an existing source; or
(2) For oil and natural gas sources that began operations on or
after February 6, 2023, the VOC emissions control requirements of this
section apply upon startup of operation.
(3) Modification to an oil and natural gas source requires a re-
evaluation of the source-wide VOC emissions from the collection of all
storage vessels, glycol dehydrators and pneumatic pumps. Adding
production from a new well or increasing production at an existing well
is considered a modification of a well site. Increasing maximum
throughput at a tank battery, compressor station or natural gas
processing plant is considered a modification.
(b) Exemptions. (1) This section does not apply to storage vessels
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 vessel
located at an oil and natural gas source, if it meets the following
requirements:
(i) The emergency storage vessel is not used as an active storage
vessel;
(ii) The owner or operator empties the emergency storage vessel no
later than 15 days after receiving fluids;
(iii) The emergency storage vessel is equipped with a liquid level
gauge or equivalent device; and
(iv) Records are kept of the usage of each emergency storage vessel
as required in Sec. 49.4183(a)(3), including the date the vessel
received fluids, the volume of fluids received in barrels, the date the
vessel was emptied, and the volume of fluids emptied in barrels.
(3) This section does not apply to storage vessels that are removed
from service. If you remove a storage vessel from service, you must
comply with paragraphs (b)(3)(i) through (iii) of this section.
[[Page 75380]]
(i) For a storage vessel to be removed from service, you must
comply with the requirements of paragraphs (b)(3)(i)(A) and (B) of this
section.
(A) You must completely empty and degas the storage vessel, such
that the storage vessel no longer contains crude oil, condensate,
intermediate hydrocarbon liquids or produced water. A storage vessel
where liquid is left on walls, as bottom clingage, or in pools due to
floor irregularity is considered to be completely empty.
(B) You must keep records as required in Sec. 49.4183(a)(4),
identifying each storage vessel removed from service and the date of
its removal from service.
(ii) If a storage vessel identified in paragraph (b)(3)(i)(B) of
this section is returned to service, you must determine its
applicability as provided in paragraph (a) of this section, and you
must keep records as required in Sec. 49.4183(a)(4), identifying the
storage vessel and the date of its return to service.
(c) VOC emission control requirements. For each storage vessel, you
must comply with the VOC emissions control requirements of paragraph
(c)(1) or (c)(2) of this section.
(1) You must reduce VOC emissions from each storage vessel by at
least 95.0 percent on a continuous basis according to paragraph
(c)(1)(i) or (ii) of this section. You must equip each storage vessel
with a cover that meets the conditions specified in Sec. 49.4176(c),
and must route all flashing, working, standing and breathing losses
from the storage vessels through a closed-vent system that meets the
conditions specified in Sec. 49.4176(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 flare that is designed to reduce the
mass content of VOC in the natural gas emissions vented to the device
by at least 95.0 percent and that is operated as specified in Sec.
49.4177;
(2) You must maintain the source-wide uncontrolled actual VOC
emissions from the collection of all storage vessels, 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 the collection of all storage
vessels, 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 vessels, you
must equip each storage vessel with a cover that meets the requirements
of Sec. 49.4176(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 February 6, 2023, controls may
be removed if the source-wide uncontrolled actual VOC emissions from
the collection of all storage vessels, glycol dehydrators, and
pneumatic pumps has been maintained at a rate less than 4 tpy, as
determined according to paragraph (c)(2) of this section.
Sec. 49.4174 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 potential for VOC emissions from the collection of all storage
vessels, glycol dehydrators, and pneumatic pumps is equal to or greater
than 4 tpy, as determined according to Sec. 49.4173. You must
reevaluate the source-wide VOC emissions from the collection of all
storage vessels, glycol dehydrators and pneumatic pumps for each
modification to an existing source, as described in Sec.
49.4173(a)(3). Applicability for glycol dehydrators that began
operation before February 6, 2023 must be determined using uncontrolled
actual emissions. Applicability for glycol dehydrators that began
operation on or after February 6, 2023 must be determined using
potential to emit.
(b) Exemptions. This section does not apply to glycol dehydration
units subject to 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 (c)(1) or (2) of this section.
(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. 49.4176(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 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. 49.4177; or
(2) You must maintain the source-wide uncontrolled actual VOC
emissions from the collection of all storage vessels, 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. 49.4173(c)(2).
Sec. 49.4175 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 source-wide potential for VOC emissions
from the collection of all storage vessels, glycol dehydrators, and
pneumatic pumps is equal to or greater than 4 tpy, as determined
according to Sec. 49.4173. You must reevaluate the source-wide VOC
emissions from the collection of all storage vessels, glycol
dehydrators and pneumatic pumps for each modification to an existing
source, as described in Sec. 49.4173(a)(3). Applicability for
pneumatic pumps that began operation before February 6, 2023 must be
determined using uncontrolled actual emissions. Applicability for
pneumatic pumps that began operation on or after February 6, 2023 must
be determined using potential to emit.
(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.
[[Page 75381]]
(c) VOC Emission Control Requirements. For each pneumatic pump, you
must comply with the VOC emissions control requirements of paragraph
(c)(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. 49.4176(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 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. 49.4177; or
(2) You must maintain the source-wide uncontrolled actual VOC
emissions from the collection of all storage vessels, 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. 49.4173(c)(2).
Sec. 49.4176 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 storage vessel that is subject to
Sec. 49.4173, and to each closed-vent system that is used to convey
VOC emissions from the collection of all storage vessels, glycol
dehydration units, or pneumatic pumps (to a vapor recovery system or
control device) that are subject to Sec. Sec. 49.4173 through 49.4175.
(b) Exemptions. This section does not apply to covers and closed-
vent systems that are 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
storage vessel with a cover to ensure that all flashing, working,
standing and breathing loss emissions are routed through a closed-vent
system to a vapor recovery system, an enclosed combustor, or a 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, intermediate hydrocarbon liquids, or
produced water in the storage vessel.
(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 loss emissions
are routed through the closed-vent system to the vapor recovery system,
the enclosed combustor, or the 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 loss emissions are
routed through the closed-vent system to the vapor recovery system, the
enclosed combustor, or the 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 vessel
emissions from 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. 49.4173 through 49.4175.
(2) All vent lines, connections, fittings, valves, relief valves,
and any other appurtenances employed to collect or contain captured
storage vessel emissions from flashing, working, standing, and
breathing losses; glycol dehydration unit process vent emissions; or
pneumatic pump emissions; or 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. 49.4173 through 49.4175, 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 closed-vent system
monitoring requirements in Sec. 49.4182(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
vessel flashing, working, standing, and breathing losses; glycol
dehydration unit process vent emissions; or 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 (d)(4)(i)
or (ii) of this section 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 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. 49.4177 VOC emissions control devices.
(a) Applicability. The requirements in this section apply to all
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. 49.4173 through 49.4176,
as applicable.
(b) Exemptions. This section does not apply to VOC emission control
devices that are 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 flares. Each owner or operator must
meet the following requirements for enclosed combustors and flares:
(1) For each enclosed combustor or flare, the owner or operator
must follow the manufacturer's written operating instructions,
procedures, and
[[Page 75382]]
maintenance schedule to ensure good air pollution control practices for
minimizing emissions;
(2) The owner or operator must ensure that each enclosed combustor
or 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 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 flare is designed
and operated in accordance with the 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 that is:
(A) Demonstrated by a manufacturer to meet the VOC control
efficiency requirements of Sec. Sec. 49.4173 through 49.4176 using
EPA-approved performance test procedures specified in 40 CFR 60.5413;
or
(B) Demonstrated by the owner or operator to meet the VOC control
efficiency requirements of Sec. Sec. 49.4173 through 49.4176 according
to the procedures and schedule specified in Sec. 49.4182(d)(1);
(ii) Operated properly at all times that captured emissions are
routed to it;
(iii) Operated with a liquid knock-out system to collect any
condensable vapors (to prevent liquids from going through the control
device);
(iv) Equipped and operated with a flash-back flame arrestor;
(v) Equipped and operated with one of the following:
(A) A continuous burning pilot; or
(B) An operational electronically controlled automatic ignition
device;
(vi) Equipped with a monitoring system for continuous measuring and
recording of the parameters that indicate proper operation of each
enclosed combustor or flare, including each continuous burning pilot
flame or electronically controlled automatic ignition device, to
monitor and document proper operation of the enclosed combustor or
flare. Examples of such continuous monitoring systems may include a
thermocouple and a chart recorder, data logger or similar device, or
connection to a SCADA system;
(vii) Maintained in a leak-free condition; and
(viii) Operated with no visible smoke emissions.
(d) Other control devices. Upon prior written approval by the EPA,
the owner or operator may use control devices other than those listed
above that are determined by the EPA to be capable of reducing the mass
content of VOC in the natural gas routed to it by at least 95.0
percent, provided that:
(1) In operating such control devices, 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; and
(2) The owner or operator must ensure there is sufficient capacity
to reduce the mass content of VOC in the produced natural gas and
natural gas emissions routed to such other control devices by at least
95.0 percent for the minimum and maximum natural gas volumetric flow
rate and BTU content routed to each device.
(3) The owner or operator must operate such a control device to
reduce the mass content of VOC in the produced natural gas and natural
gas emissions routed to it by at least 95.0 percent.
Sec. 49.4178 VOC emissions control requirements for fugitive
emissions.
(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, located at any oil and natural gas source,
as identified in Sec. 49.4169(b), except that this section does not
apply to owners or operators of the collection of fugitive emissions
components at an oil and natural gas source that is subject to the
fugitive emissions monitoring requirements in 40 CFR part 60, subpart
OOOOa.
(b) Owners or operators of the collection of fugitive emissions
components must comply with paragraph (d) of this section if either of
the following is true:
(1) The collection of fugitive emissions components is located at
an oil and natural gas source that is required to control VOC emissions
according to Sec. Sec. 49.4173 through 49.4177 of this section (i.e.,
the source-wide potential for VOC emissions from the collection of all
storage vessels, glycol dehydrators, and pneumatic pumps is equal to or
greater than 4 tpy, as determined according to Sec. 49.4173(a)(1)); or
(2) The collection of fugitive emissions components is located at a
well site, as defined in 40 CFR 60.5430a, that at any time has total
production greater than 15 barrels of oil equivalent (boe) per day
based on a rolling 12-month average.
(c) Owners or operators of the collection of fugitive emissions
components for which neither (b)(1) nor (b)(2) is true must comply with
either paragraph (c)(1) or paragraph (c)(2) of this section.
(1) You must monitor all fugitive emissions components and repair
all sources of fugitive emissions in accordance with paragraph (d) of
this section. You must keep records in accordance with Sec. 49.4183
and report in accordance with Sec. 49.4184; or
(2) You must maintain the total production for the well site at or
below 15 boe per day based on a rolling 12-month average. You must
demonstrate that the total daily oil and natural gas production from
the collection of all wells producing to the well site is at or below
15 boe per day, based on a 12-month rolling average, according to the
procedures in paragraph (e) of this section. You must maintain records
as specified in Sec. 49.4183(a)(11).
(d) 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, at a minimum:
(i) A requirement to perform an initial monitoring of the
collection of fugitive emissions components at each oil and natural gas
source by February 6, 2024;
(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 4 months apart and no
more than 7 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
[[Page 75383]]
equipment requirements specified in 40 CFR part 60, subpart OOOOa; or
(C) Another method approved by the Administrator to demonstrate
compliance with the fugitive emissions monitoring requirements. To be
approved, you must demonstrate that the alternative method achieves
emissions reductions that equal or exceed those that would result from
the application of either Method 21 or optical gas imaging instruments.
Approval of an alternative method will be subject to public notice and
comment.
(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 inspecting and repairing leaking components that
are difficult-to-monitor, unsafe-to-monitor, or require source
shutdown, to be no later than the next required monitoring event, as
noted in paragraphs (c)(1)(v)(B)(1) through (3) of this section:
(1) If using Method 21, fugitive emissions components that cannot
be monitored without elevating the monitoring personnel more than 2
meters above the surface may be designated as difficult-to-monitor and
must meet the specifications in paragraphs (c)(1)(v)(B)(1)(i) through
(iv) of this section:
(i) For all fugitive emissions components designated difficult-to-
monitor, a written plan must be developed and incorporated into the
fugitive emissions monitoring plan.
(ii) The plan must include the identification and location of each
fugitive emissions component designated difficult-to-monitor.
(iii) The plan must include an explanation of why each fugitive
emissions component designated as difficult-to-monitor is difficult-to-
monitor.
(iv) The plan must include a schedule for monitoring the difficult-
to-monitor fugitive emissions components at least once per calendar
year and a schedule for repairing such fugitive emissions components
according to paragraph (c)(1)(v)(B)(3) of this section;
(2) Fugitive emissions components that cannot be monitored because
monitoring personnel would be exposed to an immediate danger while
conducting a monitoring survey may be designated as unsafe-to-monitor
and must meet the specification in paragraphs (c)(1)(v)(B)(2)(i)
through (iv) of this section:
(i) A written plan must be developed for all of the fugitive
emissions components designated unsafe-to-monitor and incorporated into
the fugitive emissions monitoring plan;
(ii) The plan must include the identification and location of each
fugitive emissions component designated unsafe-to-monitor.
(iii) The plan must include an explanation of why each fugitive
emissions component designated as unsafe-to-monitor is unsafe-to-
monitor.
(iv) The plan must include a schedule for monitoring the unsafe-to-
monitor fugitive emissions components as frequently as practicable
during safe to inspect times and for repairing such fugitive emissions
components according to paragraph (c)(1)(v)(B)(3) of this section;
(3) If the repair or replacement of a fugitive emissions component
designated difficult-to-monitor or unsafe-to-monitor is technically
infeasible; would require a vent blowdown, a compressor station
shutdown, a well shutdown, or well shut-in; or would be unsafe to
repair during operation of the unit, the repair or replacement must be
completed during the next scheduled compressor station shutdown, well
shutdown, or well shut-in; after a planned vent blowdown; or within 2
years, whichever is earlier; 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 and repairing a
fugitive emissions component under any of the following circumstances:
(i) The contacting process stream only contains glycol, amine,
methanol, or produced water; or
(ii) The component 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.
(e) Procedures for determining total well site production. The
total well site production must be determined according to the
following procedures:
(1) Calculate the total average boe per day for each calendar month
using:
(i) For existing well sites, the records of production for the
first 30 days after becoming subject to this section.
(ii) For well sites that commence construction, reconstruction or
modification on or after February 6, 2023, the first 30 days of
production, performing the calculation within 45 days of the end of the
first 30 days of production.
(2) Determine the daily oil and natural gas production for each
individual well at the well site for the month. To convert gas
production to equivalent barrels of oil, divide the cubic feet of gas
produced by 6,000.
(3) Sum the daily production for each individual well at the well
site to determine the total well site production and divide by the
total number of days in the calendar month. This is the average daily
total well site production for the month.
(4) Use the result determined in paragraph (e)(2) of this section
and average with the daily average well site production values
determined for each of the preceding 11 months to calculate the rolling
12-month average of the total well site production.
Sec. 49.4179 VOC emissions control requirements for tank truck
loading.
(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 and unloaded using measures to minimize VOC emissions. These
measures must include, at a minimum, bottom filling or a submerged fill
pipe, as defined in Sec. 49.4171(b).
Sec. 49.4180 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).
[[Page 75384]]
(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.
(d) Documentation requirements. The owner or operator of any
existing pneumatic controllers must meet the tagging requirements in 40
CFR 60.5390(a), except that the month and year of installation,
reconstruction or modification is not required.
Sec. 49.4181 Other combustion devices.
(a) Applicability. The VOC emission control requirements in this
section apply to each owner or operator of any existing enclosed
combustor or flare located at an oil and natural gas source as
identified in Sec. 49.4169(b) that is used to control VOC emissions,
but that is not required under Sec. Sec. 49.4173 through 49.4175 of
this rule.
(b) Retrofit requirements. All existing enclosed combustors and
flares must be equipped with an operational electronically controlled
automatic ignition device.
Sec. 49.4182 Monitoring and testing requirements.
(a) Applicability. The monitoring and testing requirements in
paragraphs (c) and (d) 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. 49.4173 through
49.4177.
(b) Exemptions. Paragraphs (c) and (d) of this section do not apply
to any storage vessels, glycol dehydration units, pneumatic pumps,
covers, or closed-vent systems, or to 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 each cover and closed-vent
system as specified in paragraphs (c)(1) or (2).
(1) Conduct olfactory, visual, and auditory inspections at least
once every calendar month, separated by at least 15 days between each
inspection, of each cover and closed-vent system, including each bypass
device, and each storage vessel thief hatch, seal, and pressure relief
valve, to ensure proper condition and functioning of the equipment to
identify defects that can result in air emissions according to the
procedures. Examples of defects are visible cracks, holes, or gaps in
the cover or piping, or between the cover and the separator wall; loose
connections; liquid leaks; and broken, cracked, or otherwise damaged
seals or gaskets on closure devices, caps, or other closure devices. If
the storage vessel is partially or entirely buried, you must inspect
only those portions of the cover that extend to or above the ground
surface, and those connections that are on such portions of the cover
(e.g., fill ports, access hatches, gauge wells) and can be opened to
the atmosphere. The inspector should note whether there are signs of
oil releases around storage vessel thief hatches, seals and pressure
relief valves (e.g., staining on the storage vessel), which may
indicate over-pressure events that occurred when the storage vessel was
being filled. Any defects identified must be corrected or repaired
within 30 days of identification.
(2) Conduct optical gas imaging inspections of each cover and
closed vent system for any visible emissions at the same frequency as
the frequency for the collection of fugitive emissions components
located at the oil and natural gas source, as specified in Sec.
49.4178(d)(1).
(d) Each owner or operator must monitor the operation of each
enclosed combustor and flare to confirm proper operation and
demonstrate compliance with the requirements of Sec. 49.4177(c), as
follows and as applicable:
(1) Demonstrate compliance with the requirement of Sec.
49.4177(c)(5)(i)(B) that each enclosed combustor must be demonstrated
by the owner or operator to meet the VOC control efficiency
requirements of Sec. Sec. 49.4173 through 49.4176, by conducting
performance tests using EPA-approved performance test methods and
procedures specified in 40 CFR 60.5413 and according to the schedule
specified in paragraphs (d)(1)(i) and (ii) of this section.
(i) You must conduct an initial performance test within 180 days
after the effective date of this rule for existing enclosed combustors,
and within 180 days after initial startup for new enclosed combustors.
You must submit the performance test results as specified in Sec.
49.4184(a) within 60 days of completing the test.
(ii) You must conduct periodic performance tests for all enclosed
combustors required to conduct initial performance tests. You must
conduct the first periodic performance test no later than 60 months
after the initial performance test required in paragraph (d)(1)(i) of
this section. You must conduct subsequent periodic performance tests at
intervals no longer than 60 months following the previous periodic
performance test or whenever you desire to establish a new operating
limit. You must submit the periodic performance test results as
specified in Sec. 49.4184(a) within 60 days of completing each test.
(iii) The owner or operator of an enclosed combustor whose model is
tested under, and meets the criteria of, Sec. 49.4177(c)(5)(i)(A) is
not required to conduct performance testing.
(2) Conduct inspections of each enclosed combustor or flare at
least once every calendar month, separated by at least 15 days between
each inspection, to confirm proper operation of the device, as follows:
(i) Demonstrate that each enclosed combustor or flare is operated
with no visible smoke emissions, except for periods not to exceed a
total of 1 minute during any 15-minute period, by conducting a visible
emissions test using section 11 of EPA Method 22 of appendix A-7 of 40
CFR part 60. The observation period must be of sufficient length to
meet the requirement for determining compliance with this visible
emissions standard. Devices failing the visible emissions test must
follow manufacturer's repair instructions, if available, or best
combustion engineering practice as outlined in the unit inspection and
maintenance plan, to return the unit to compliant operation. All
inspection, repair, and maintenance activities for each unit must be
recorded in a maintenance and repair log and must be available for
inspection. Following return to operation from maintenance or repair
activity, each device must pass a Method 22 of Appendix A-7 of 40 CFR
part 60 visual observation as described in this paragraph.
(ii) Conduct visual inspections to confirm that the pilot is lit
when vapors are being routed to the device and that the continuous
burning pilot or electronically controlled automatic ignition device
and the continuous parameter monitoring system is operating properly;
(iii) Conduct olfactory, visual and auditory inspections of all
other equipment associated with the combustion device to ensure system
integrity; and
(iv) 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.
(e) Where sufficient to meet the monitoring requirements in this
section,
[[Page 75385]]
the owner or operator may use a SCADA system to monitor and record the
required data.
Sec. 49.4183 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) Monthly calculations, as specified in Sec. 49.4173(c)(2),
demonstrating that the uncontrolled actual VOC emissions from the
collection of all storage vessels, glycol dehydrators, and pneumatic
pumps at an oil and natural gas source, as identified in Sec.
49.4169(b), have been maintained at less than 4 tpy;
(2) Records of monthly and rolling 12-month crude oil, condensate,
intermediate hydrocarbon liquids, produced water or natural gas
throughput;
(3) For each emergency storage vessel that is exempted from the
control requirements of Sec. 49.4173(b)(2), records of usage
including:
(i) The date the vessel received fluids;
(ii) The volume of fluids received in barrels;
(iii) The date the overflow vessel was emptied; and
(iv) The volume of fluids emptied in barrels.
(4) Identification of each storage vessel that is removed from
service or returned to service as specified in Sec. 49.4173(b)(3),
including the date the storage vessel was removed from service or
returned to service.
(5) For storage vessels that are skid-mounted or permanently
attached to something that is mobile (such as trucks, railcars, barges
or ships), records indicating the number of consecutive days that the
vessel is located at an oil and natural gas source. If a storage vessel
is removed from an oil and natural gas source and, within 30 days, is
either returned to the source or replaced by another storage vessel at
the source to serve the same or similar function, then the entire
period since the original storage vessel was first located at the
source, including the days when the storage vessel was removed, must be
added to the count of the number of consecutive days.
(6) For each enclosed combustor or flare at an oil and natural gas
source required under Sec. Sec. 49.4173 through 49.4177:
(i) Manufacturer-written, site-specific designs, operating
instructions, operating procedures and maintenance schedules, including
those of any operation monitoring systems;
(ii) Date of installation;
(iii) Records of required monitoring of operations in Sec.
49.4182(d)(1);
(iv) Records of any instances in which the pilot flame is not
present or the monitoring equipment is not functioning in the enclosed
combustor or flare, the date and times of the occurrence, the
corrective actions taken, and any preventative measures adopted to
prevent recurrence of the occurrence; and
(v) Records of any visible emissions tests conducted according to
Sec. 49.4182(d)(3), including any time periods in which visible smoke
emissions are observed emanating from the enclosed combustor or flare.
(7) For each closed-vent system:
(i) The date of installation; and
(ii) 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.
(8) Documentation of all storage vessel and closed-vent system
inspections required in Sec. 49.4182(c). All inspection records must
include the following information:
(i) The date of the inspection;
(ii) The findings of the inspection;
(iii) Any adjustments or repairs made as a result of the
inspection, and the date of the adjustment or repair; and
(iv) The inspector's name or identification number;
(9) The Uinta Basin-wide fugitive emissions monitoring plan for the
Indian country lands within the U&O Reservation, including all elements
required by Sec. 49.4178(d).
(10) Documentation of each fugitive emissions inspection conducted
in accordance with Sec. 49.4178(d). All inspection records must
include the following information:
(i) The date of the inspection;
(ii) The identification of any component that was determined to be
leaking;
(iii) The identification of any component designated difficult-to-
monitor or unsafe-to-monitor that was not inspected, and the reason it
was not inspected;
(iv) The date of the first attempt to repair the leaking component;
(v) The identification of any leaking component with a delayed
repair and the reason for the delayed repair:
(A) For unavailable parts:
(1) The date of ordering a replacement component; and
(2) The date the replacement component was received; and
(B) For a shutdown:
(1) The reason the repair is technically infeasible;
(2) The date of the shutdown;
(3) The date of subsequent startup after a shutdown; and
(4) Emission estimates of the shutdown and the repair if the delay
is longer than 6 months;
(vi) The date and description of any corrective action taken,
including the date the component was verified to no longer be leaking;
(vii) The identification of each component exempt under Sec.
49.4178(d)(2), including the type of component and a description of the
qualifying exemption; and
(viii) The inspector's name or identification number.
(11) For each well site complying with either Sec. 49.4178(b)(2)
or Sec. 49.4178(c)(2), you must maintain records of the rolling 12-
month average daily production no later than 12 months before complying
with Sec. 49.4178(b)(2) or Sec. 49.4178(c)(2).
(12) For each electronically controlled automatic ignition system
required under Sec. 49.4181, records demonstrating the date of
installation and manufacturer specifications; and
(13) 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 5 years from the date the record was
created.
Sec. 49.4184 Notification and reporting requirements.
(a) Unless otherwise specified, each owner or operator must submit
any documents required under this rule to: U.S. EPA Region 8,
Enforcement and Compliance Assurance Division, Air and Toxics
Enforcement Branch, 8ENF-AT, 1595 Wynkoop St., Denver, CO 80202, or
documents may be submitted electronically to
[email protected] and/or to the EPA's Compliance and
Emissions Data Reporting Interface (CEDRI). Information on CEDRI is
available at https://www.epa.gov/electronic-reporting-air-emissions/cedri; CEDRI can be accessed directly through the EPA's Central Data
Exchange (CDX) at https://cdx.epa.gov/. The EPA will make all the
information submitted through CEDRI available to the public without
further notice to you. Do not use CEDRI to submit information you claim
as confidential business information (CBI). Anything submitted using
CEDRI cannot
[[Page 75386]]
later be claimed CBI. Although we do not expect persons to assert a
claim of CBI, if you wish to assert a CBI claim, you must submit a
complete file, including the information claimed to be CBI, on a
compact disc, flash drive, or other commonly used electronic storage
media to the EPA, and the electronic media must be clearly marked as
CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, Attention: Group
Leader, Measurement Policy Group, MD C404-02, 4930 Old Page Rd.,
Durham, NC 27703. The same information, with the CBI omitted, must be
submitted to the EPA via [email protected] or the EPA's
CDX as described earlier in this paragraph. All claims of CBI must be
asserted at the time of submission. Furthermore, under CAA section
114(c), emissions data is not entitled to confidential treatment, and
the EPA is required to make emissions data available to the public.
Thus, emissions data will not be protected as CBI and will be made
publicly available.
(b) Each owner and operator of an affected oil and natural gas
source as identified in Sec. 49.4169(b) must submit an annual report
containing the information specified in paragraphs (b)(1) through (3)
of this section, as applicable. The annual report must cover affected
operations for the previous calendar year. The initial annual report is
due April 1st of the calendar year following February 6, 2023 and must
cover all affected operations for the previous calendar year on and
after February 6, 2023. 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, NSPS OOOO or OOOOa, or NESHAP HH reports as long
as all the required elements of the annual report are included. An
alternative schedule on which the annual report 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 the required
records specified in Sec. 49.4183 that are identified in paragraphs
(b)(3)(i) through (iv) of this section as they relate to the source's
compliance with the requirements of Sec. Sec. 49.4173 through 49.4183.
(i) For each enclosed combustor or flare at an oil and natural gas
source required under Sec. Sec. 49.4173 through 49.4177:
(A) Records of any instances in which the pilot flame is not
present or the monitoring equipment is not functioning, the date and
times of the occurrence, the corrective actions taken, and any
preventative measures adopted to prevent recurrence of the occurrence;
and
(B) Records of any time periods in which visible smoke emissions
are observed emanating from the enclosed combustor or flare.
(ii) For each closed-vent system:
(A) Records of any instances in which any closed-vent system or
control device was bypassed or down, the reason for each incident, its
duration, the corrective actions taken, and any preventative measures
adopted to avoid such bypasses or downtimes; and
(B) Records of any instances of defects identified during the
monthly inspection required in Sec. 49.4182(c), including:
(1) The date of the inspection;
(2) The findings of the inspection;
(3) Date and description of corrective adjustments or repairs made
as a result of the inspection or reason for delay of repair; and
(iii) For Fugitive Emissions Monitoring, records documenting each
fugitive emissions inspection, including:
(A) The date of the inspection;
(B) Identification of any component that was determined to be
leaking;
(C) Identification of any component designated difficult-to-monitor
or unsafe-to-monitor that was not inspected and the reason it was not
inspected;
(D) The date of repair of each leaking component;
(E) Identification of any leaking component with a delayed repair,
the reason for the delayed repair and the emission estimates associated
with any shutdown and 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 inspector's name or identification number;
(H) For each well site complying with Sec. 49.4178(c)(2), you must
specify that the well site is exempt from the requirements of Sec.
49.4178(d) and submit the average daily production for the well site;
and
(iv) For each pneumatic controller with a natural gas bleed rate
greater than the applicable standard, records of the reason for the use
of the controller.
[FR Doc. 2022-24677 Filed 12-7-22; 8:45 am]
BILLING CODE 6560-50-P