[Federal Register Volume 91, Number 68 (Thursday, April 9, 2026)]
[Rules and Regulations]
[Pages 18056-18132]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2026-06808]
[[Page 18055]]
Vol. 91
Thursday,
No. 68
April 9, 2026
Part III
Environmental Protection Agency
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40 CFR Part 60
Reconsideration of Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil and
Natural Gas Sector Climate Review; Final Rule
Federal Register / Vol. 91, No. 68 / Thursday, April 9, 2026 / Rules
and Regulations
[[Page 18056]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2024-0358; FRL-12031-02-OAR]
RIN 2060-AW35
Reconsideration of Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: The U.S. Environmental Protection Agency (EPA) is finalizing
amendments to the New Source Performance Standards (NSPS) and Emission
Guidelines (EG) for Existing Sources for the Crude Oil and Natural Gas
Source Category in response to petitions for reconsideration of the
March 8, 2024, final rule. Specifically, this action finalizes discrete
technical changes to two aspects of the rules. First, this action
finalizes discrete technical changes to the temporary flaring
provisions for associated gas in certain situations. Second, this
action finalizes discrete technical changes to the vent gas net heating
value (NHV) continuous monitoring requirements and alternative
performance test (sampling demonstration) option for flares and
enclosed combustion device(s) (ECD). In a letter dated May 6, 2024, the
EPA notified petitioners and the public that the Agency granted
reconsideration on these two aspects of the final rule. These
amendments neither finalize changes to any other aspect of the March 8,
2024, final rule, nor finalize alterations to the substance of any
emission standards within that final rule. This action also finalizes a
technical correction to reinstate regulatory text for the reporting
requirements in 40 CFR 60.5420b(b)(1) through (15), which were
mistakenly deleted by the December 2025 Final Rule. Also, in this
action, the EPA finalizes changes to the regulatory text to meet the
Office of the Federal Register formatting and style requirements.
DATES: This final rule is effective on June 8, 2026. The incorporation
by reference of certain material listed in the rule is approved by the
Director of the Federal Register as of June 8, 2026.
ADDRESSES: The EPA has established a docket for this rulemaking under
Docket ID No. EPA-HQ-OAR-2024-0358. All documents in the docket are
listed on the https://www.regulations.gov/ website. Although listed,
some information is not publicly available, e.g., Confidential Business
Information (CBI) or other information whose disclosure is restricted
by statute. Certain other material, such as copyrighted material, is
not placed on the internet and will be publicly available only in hard
copy form. Publicly available docket materials are available
electronically through https://www.regulations.gov/.
FOR FURTHER INFORMATION CONTACT: For questions about this final rule,
contact Amy Hambrick, Natural Resources Division (E143-05), Office of
Clean Air Programs, U.S. Environmental Protection Agency, 109 T.W.
Alexander Drive, P.O. Box 12055 RTP, North Carolina 27711; telephone
number: (919) 541-0964; and email address: [email protected].
Additional questions may be directed to the following email address:
[email protected].
SUPPLEMENTARY INFORMATION:
Preamble acronyms and abbreviations. Throughout this document the
use of ``we,'' ``us,'' or ``our'' is intended to refer to the EPA. We
use multiple acronyms and terms in this preamble. While this list may
not be exhaustive, to ease the reading of this preamble and for
reference purposes, the EPA defines the following terms and acronyms
here:
ALT alternative
AGR acid gas removal
APA Administrative Procedure Act
API American Petroleum Institute
ASTM American Society for Testing and Materials
AXPC American Exploration and Production Council
BSER best system of emission reduction
Btu/lb British thermal units per pound
Btu/scf British thermal units per standard cubic feet
[deg]C degrees Celsius
CAA Clean Air Act
CBI Confidential Business Information
CFR Code of Federal Regulations
CO2 carbon dioxide
CRA Congressional Review Act
DRE destruction removal efficiency
ECD enclosed combustion device(s)
EG emissions guidelines
EIA U.S. Energy Information Administration
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
FR Federal Register
GC gas chromatograph
GHG greenhouse gas
HP high-pressure
H2S hydrogen sulfide
ICR information collection request
IFR interim final rule
LP low-pressure
MACT maximum achievable control technology
MCF thousand cubic feet
MS mass spectrometer
NAICS North American Industry Classification System
NHV net heating value(s)
NHVcz combustion zone NHV
NHVdil NHV dilution parameter
NRU nitrogen removal units
NSPS new source performance standards
NTTAA National Technology Transfer and Advancement Act
OGI Optical Gas Imaging
OMB Office of Management and Budget
PRA Paperwork Reduction Act
RFA Regulatory Flexibility Act
RLSO redline strike out
RTC Response to Comment
scf standard cubic feet
TAR Tribal Authority Rule
TCEQ Texas Commission on Environmental Quality
TXOGA Texas Oil and Gas Association
UMRA Unfunded Mandates Reform Act
U.S. United States
VISR Video Imaging Spectro-Radiometry
VOC volatile organic compound(s)
Organization of this document. The information in this preamble is
organized as follows:
I. General Information
A. Executive Summary
B. Does this action apply to me?
C. Where can I get a copy of this document and other related
information?
II. Statutory Background and Regulatory History
A. Statutory Background of CAA Sections 111(b), 111(d), and
General Implementing Regulations
B. What is the regulatory history and background of NSPS and EG
for the Crude Oil and Natural Gas source category?
C. Judicial Review and Administrative Review
III. Summary of Final Amendments to NSPS OOOOb and EG OOOOc
A. Temporary Flaring Provisions for Associated Gas in Certain
Situations
B. Vent Gas NHV Continuous Monitoring Requirements and
Alternative Performance Test (Sampling Demonstration) Option for
Flares and Enclosed Combustion Devices
C. Correction of Inadvertent Deletion of Regulatory Text
IV. Significant Comments and Changes Since Proposal for NSPS OOOOb
and EG OOOOc
A. Temporary Flaring Provisions for Associated Gas in Certain
Situations
B. Vent Gas NHV Continuous Monitoring Requirements and
Alternative Performance Test (Sampling Demonstration) Option for
Flares and Enclosed Combustion Device
V. How do these final amendments impact the implementation of EG
OOOOc?
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Executive Order 14192: Unleashing Prosperity Through
Deregulation
[[Page 18057]]
C. Paperwork Reduction Act (PRA)
D. Regulatory Flexibility Act (RFA)
E. Unfunded Mandates Reform Act (UMRA)
F. Executive Order 13132: Federalism
G. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
H. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
J. National Technology Transfer and Advancement Act (NTTAA) and
1 CFR Part 51
K. Congressional Review Act (CRA)
I. General Information
A. Executive Summary
1. Purpose of the Regulatory Action
On March 8, 2024, the EPA published a final rule for the Crude Oil
and Natural Gas source category under CAA section 111(b) and (d) at 89
FR 16820 (``March 2024 Final Rule''). The EPA finalized NSPS OOOOb for
GHG and VOC emissions from new, modified, and reconstructed sources in
this source category. The EPA also finalized EG OOOOc for GHG emissions
from existing sources in this source category. The March 2024 Final
Rule became effective on May 7, 2024. The March 2024 Final Rule applies
to thousands of new sources and will apply to hundreds of thousands of
existing sources when the EG is implemented in the crude oil and
natural gas source category. Crude oil production applicability
includes the well and extends to the point of custody transfer to the
crude oil transmission pipeline or any other forms of transportation;
and natural gas production applicability includes processing,
transmission, and storage, which includes the well and extends to, but
does not include, the local distribution company custody transfer
station.
After the publication of the March 2024 Final Rule, the EPA
received multiple petitions \1\ for reconsideration. On May 6, 2024, we
notified certain petitioners and the public that we granted
reconsideration on two discrete aspects of the March 2024 Final Rule:
the temporary flaring provisions for associated gas in certain
situations; and the vent gas NHV continuous monitoring requirements and
alternative performance test (sampling demonstration) option for flares
and enclosed combustion devices.\2\
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\1\ See Docket No. EPA-HQ-OAR-2024-0358 for petitions for
reconsideration received.
\2\ See Docket No. EPA-HQ-OAR-2024-0358 for May 6, 2024, letter
granting reconsideration.
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On January 15, 2025, the EPA proposed amendments to the New Source
Performance Standards and Emission Guidelines for Existing Sources for
the Crude Oil and Natural Gas Source Category in response to these
petitions for reconsideration (``January 2025 Proposal'').\3\
Specifically, we proposed discrete technical changes to two different
aspects of the rules (i.e., technical changes to the temporary flaring
provisions for associated gas in certain situations; technical changes
to the vent gas NHV continuous monitoring requirements and alternative
performance test (sampling demonstration) option for flares and
enclosed combustion devices).\.\ This action finalizes amendments to
the March 2024 Final Rule resulting from our reconsideration of these
two discrete issues.\4\
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\3\ 90 FR 3734 (January 15, 2025).
\4\ In the May 6, 2024, letter to petitioners, the EPA also took
the opportunity to clarify the applicable timeframe for performance
testing with respect to NHV sampling.
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On January 20, 2025, the President issued Executive Orders 14154
(Unleashing American Energy) \5\ and 14156 (Declaring a National Energy
Emergency).\6\ Then, on January 31, 2025, the President issued
Executive Order 14192 (Unleashing Prosperity through Deregulation).\7\
On March 12, 2025, against this backdrop, the EPA announced plans for
deregulatory actions to, among other things, unleash American
energy.\8\ On that same day, and as part of the larger Agency plan, the
EPA announced plans to reconsider the regulations promulgated via the
March 2024 Final Rule ``to ensure they do not prevent America from
unleashing energy dominance.'' \9\
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\5\ 90 FR 8353 (January 29, 2025).
\6\ 90 FR 8433 (January 29, 2025).
\7\ 90 FR 9065 (February 6, 2025).
\8\ https://www.epa.gov/newsreleases/epa-launches-biggest-deregulatory-action-us-history.
\9\ https://www.epa.gov/newsreleases/trump-epa-announces-oooo-bc-reconsideration-biden-harris-rules-strangling-american.
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On July 31, 2025, the EPA promulgated an IFR which extended
deadlines for certain provisions related to control devices, equipment
leaks, storage vessels, process controllers, and covers and closed vent
systems in the NSPS OOOOb.\10\ Within that IFR, the EPA also extended
the date for future implementation of the Super Emitter Program and
extended the State plan submittal deadline in the EG OOOOc. In December
2025, the EPA promulgated a final rule which responded to comments
received on the July 2025 IFR and concluded that the regulatory
amendments made in the IFR were still appropriate after consideration
of comments.\11\ In response to comments received, the December 2025
Final Rule also provided an additional 180-day extension (from the
final rule's effective date) (until June 1, 2026) to the compliance
dates related to NHV monitoring of flares and ECD found in 40 CFR
60.5417b(d)(8)(i) through (iv) and (vi), as well as 360 days from the
effective date of the December 2025 Final Rule (November 30, 2026) for
owners or operators to submit initial annual reports pursuant to 40 CFR
60.5420(b).\12\
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\10\ 90 FR 35966 (July 31, 2025).
\11\ 90 FR 55671 (December 3, 2025).
\12\ See 90 FR at 35970-35972 (July 31, 2025), and 90 FR 55675-
55676 (December 3, 2025) for discussion of the rationale for NHV
monitoring extension.
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In this final rule, the EPA is finalizing changes to two aspects of
the March 2024 Final Rule (i.e., temporary flaring and NHV monitoring)
after consideration of comments received on the January 2025 Proposal.
First, this action finalizes discrete technical changes to the
temporary flaring provisions for associated gas in certain situations.
These changes include:
Extending the baseline time limit for temporary flaring of
associated gas in certain situations from 24 hours to 72 hours with
allowances to go beyond 72 hours in the event of exigent circumstances
such as extreme inclement weather that prevent an owner or operator
from safely accessing a well site to resolve an emergency or
maintenance issue:
[cir] Requiring owners and operators to cease flaring as soon as
the malfunction is resolved or the temporary flaring limit is reached,
whichever occurs first, and
[cir] Clarifying recordkeeping and reporting requirements to
include a written description of the exigent circumstance, steps taken
to resolve the issue, date and time when it took place, and the total
duration of flaring.
Second, this action finalizes discrete technical changes to the
vent gas net heating value (NHV) continuous monitoring requirements and
alternative performance test (sampling demonstration) option for flares
and ECDs. These changes include:
Revising numerous aspects of vent gas NHV continuous
monitoring requirements and alternative performance test (sampling
demonstration) options for flares and enclosed combustion devices by:
[[Page 18058]]
[cir] Expanding gas streams that are exempt from monitoring due to
high NHV content to include all flare types (unassisted and assisted),
as well as ECDs for both new and existing sources, and
[cir] Requiring NHV monitoring via continuous monitoring or
alternative sampling demonstration in cases where inert gases are
added, or for other miscellaneous scenarios which decrease the NHV
content of the inlet gas stream for all flare types and ECDs for both
new and existing sources.
2. Summary of the Major Provisions of This Regulatory Action
After considering comments received on the January 2025 Proposal,
the EPA is allowing up to 72 hours for certain types of temporary
flaring of associated gas based on information indicating that more
than 24 or 48 hours is needed in some instances. While we acknowledge
owners or operators have an economic incentive not to flare due to
product (natural gas) loss that can equate to lost revenue, we have
included a backstop requirement that owners or operators cease flaring
after resolving the incident causing the need to flare. Collectively,
the EPA is increasing the allowance of temporary flaring to 72 hours
and including a backstop requirement, so owners or operators have both
the economic incentive and a regulatory obligation to cease flaring of
associated gas after an equipment malfunction or failure is addressed.
Additionally, the EPA solicited comments in the January 2025
Proposal on specific situations that would be considered ``exigent
circumstances.'' Based on comments received and a re-assessment of data
provided to the EPA, we are finalizing an allowance to flare for
greater than 72 hours if an exigent circumstance persists and there is
a need to extend the temporary flaring duration for maintenance, safety
issues, or repairs. While we expect that the vast majority of temporary
flaring situations to be addressed within the 72-hour timeframe, we
recognize that there may be equipment malfunction incidents that
require more than 72 hours to resolve due to circumstances beyond an
owner's or operator's control. However, to ensure flaring does not
continue beyond the time that is necessary to resolve a malfunction
incident, we are including a backstop to this extended timeframe of
flaring until such equipment malfunctions during these exigent
circumstances are resolved or no longer present, whichever is sooner.
After considering input from commenters, the EPA is finalizing that
an ``exigent circumstance'' must be a situation that restricts an
owner's or operator's ability to reasonably access a site with the
necessary equipment and personnel to address and resolve equipment
malfunction incidents that cause the need to temporarily flare
associated gas for more than 72 hours.
Lastly, the EPA is finalizing recordkeeping and reporting
requirements when exigent circumstances are invoked. The EPA
anticipates that exigent circumstances will be invoked only in limited
cases, and that these additional recordkeeping and reporting
requirements will not add undue burden to owners and operators.
The March 2024 Final Rule requires owners and operators to perform
NHV sampling for flares and ECD through continuous monitoring of NHV or
through periodic testing with sampling demonstrations. Industry
petitioners submitted reconsideration petitions in response to the
January 2025 proposal claiming that the compliance demonstrations are
unnecessary, technically infeasible, and provide a limited timeline for
compliance. The petitioners argued that over 99 percent of historical
Btu stream data already complies with the prescribed minimum NHV
content values (depending on flare type) outlined in the March 2024
Final Rule. Industry petitioners asserted that NHV content is usually a
concern when inert gases are added to the process streams, which
typically occurs during scheduled situations and is known to the
operator of the affected source. The EPA made amendments to the NHV
provisions based on data submitted by industry supporting their claims
that the majority (over 99 percent) of facilities already complied with
the minimum NHV requirements, and NHV content is only a concern when
inert gases (and other miscellaneous scenarios) are added to the
process streams.
Based on information from these petitions, as well as further
information provided by industry following the January 2025 proposal,
the EPA is finalizing changes to the continuous monitoring requirements
and alternative performance test options (sampling demonstration) of
NHV for flares and ECD. First, the EPA is expanding the gas streams
that are exempt from monitoring due to high NHV content to include all
flare and ECD for both new and existing sources. However, the EPA is
also requiring that NHV monitoring be performed (via either continuous
monitoring or the alternative performance test (sampling demonstration)
option currently prescribed in the NSPS OOOOb and EG OOOOc regulations)
in cases where inert gases are added and for other miscellaneous
scenarios which decrease the NHV content of the inlet stream gas to all
flare and ECD for both new and existing sources. In addition, the EPA
is providing additional flexibility for alternative performance testing
via the NHV grab sampling option by allowing samples to be taken
upstream of the control device, provided that the sample is
representative of the gas being introduced to the control device.
Additionally, we are finalizing as proposed to allow breaks during
weekends and holidays for the March 2024 Final Rule's consecutive 14-
day sampling demonstration requirements to account for reasonable
operational pauses provided no sampling is spaced more than 3 operating
days apart from the previous sampling day. The EPA is also allowing
less than one-hour sampling times in cases where low or intermittent
flow makes it infeasible for both NSPS OOOOb and EG OOOOC sources,
provided the sampling time used and reason for the reduced sampling
time is documented and reported. Finally, the EPA is clarifying NHV
testing must be reported in volumetric units (Btu/scf) instead of
specific units (Btu/lb) in order to facilitate consistency in
reporting.
This action also finalizes a technical correction to reinstate
regulatory text for the reporting requirements in 40 CFR 60.5420b(b)(1)
through (15), which were mistakenly deleted by the December 2025 Final
Rule,\13\ under the authority of section 553(b)(B) of the
Administrative Procedure Act, 5 U.S.C. 553(b)(B), which states, when an
agency for good cause finds that public notice and comment procedures
are impracticable, unnecessary, or contrary to the public interest, the
agency may issue a rule without providing notice and an opportunity for
public comment. Lastly, in this action, the EPA is finalizing
formatting changes to the regulatory text to meet the required
formatting standards of the Office of the Federal Register.\14\
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\13\ 90 FR 55671 (December 3, 2025).
\14\ To view the final formatting changes, see the full redline
strike out (RLSO) of the regulatory text located in the public
docket at EPA-HQ-OAR-2024-0358.
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3. Costs and Benefits
The EPA estimated present values (PV) and equivalent annualized
values (EAV) of the estimated cost savings of this final
reconsideration in 2024 dollars over the 2024 to 2038 period. The cost
savings are represented in this analysis as the reduction in the number
of affected sources and a reduction in the number of tests required for
each affected source for the changes finalized
[[Page 18059]]
in this reconsideration. In simple terms, these cost savings are an
estimate of the decreased industry expenditures resulting from the
final changes to the March 2024 Final Rule requirements. Under this
final action, emissions changes and benefits from emission changes were
not quantified. Qualitatively, the changes to the temporary flaring
limitation could result in increases to emissions, while we do not
expect any emissions changes to result from the changes to the NHV
testing compliance demonstration.
Table 1 presents the estimated cost savings of this proposed action
in 2024 dollars for the baseline which includes the March 2024 Final
Rule (i.e., the primary baseline analyzed in the EIA). This table
presents the PV and EAV of these estimates discounted at three percent
and seven percent.
Table 1--Present Value and Equivalent Annualized Value of Compliance Cost Savings Estimates of the Final Action
From 2024-2038
[Millions of 2024$]
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3 Percent discount rate 7 Percent discount rate
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Present Value........................................... 2,480 1,900
Equivalent Annualized Value............................. 208 209
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B. Does this action apply to me?
The source category that is the subject of this final action is the
Crude Oil and Natural Gas Source Category regulated under Clean Air Act
(CAA) section 111 through New Source Performance Standards (NSPS) and
Emission Guidelines (EG). The 2022 North American Industry
Classification System (NAICS) codes for the source category are
summarized in Table 2. The NAICS codes serve as a guide for readers
outlining the entities that this final action is likely to affect. The
NSPS codified in 40 CFR part 60, subpart OOOOb, are directly applicable
to affected facilities that begin construction, reconstruction, or
modification after December 6, 2022. As shown in Table 1, Federal,
State, and local government entities would not be affected by the NSPS
action.
Table 2--Industrial Source Categories Affected by NSPS Action
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Examples of
Category NAICS code regulated entities
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Industry.......................... 211120 Crude Petroleum
Extraction.
211130 Natural Gas
Extraction.
221210 Natural Gas
Distribution.
486110 Pipeline
Distribution of
Crude Oil.
486210 Pipeline
Transportation of
Natural Gas.
Federal Government................ .............. Not affected.
State and Local Government........ .............. Not affected.
Tribal Government................. 921150 American Indian and
Alaska Native
Tribal Governments.
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This table is not intended to be exhaustive but rather provides a
guide for readers regarding entities likely to be affected by this
action. Other types of entities not listed in the table could also be
affected by this action. To determine whether your entity is affected
by this action, you should carefully examine the applicability criteria
found in NSPS OOOOb and EG OOOOc. If you have questions regarding the
applicability of this action to a particular entity, consult the person
listed in the FOR FURTHER INFORMATION CONTACT section, your State air
pollution control agency with delegated authority for NSPS OOOOb, or
your EPA Regional Office.
The issuance of the CAA section 111(d) EG in March of 2024 did not
impose binding requirements directly on existing sources. The EG
codified in 40 CFR part 60, subpart OOOOc, apply to States in the
development, submittal, and implementation of State plans to establish
performance standards to reduce emissions of greenhouse gas (GHG) in
the form of limitations on methane from designated facilities that
commence construction, modification, or reconstruction on or before
December 6, 2022. Under the Tribal Authority Rule (TAR), eligible
Tribes may seek approval to implement a plan under CAA section 111(d)
in a manner similar to a State. See 40 CFR part 49, subpart A. Tribes
may, but are not required to, seek approval for treatment as a State
for purposes of developing a Tribal Implementation Plan (TIP)
implementing the EG codified in 40 CFR part 60, subpart OOOOc. The TAR
authorizes Tribes to develop and implement their own air quality
programs, or portions thereof, under the CAA. However, it does not
require Tribes to develop a CAA program. Tribes may implement programs
that are most relevant to their air quality needs. If a Tribe does not
seek and obtain authority from the EPA to establish a TIP, the EPA has
authority to establish a Federal CAA section 111(d) plan for designated
facilities that are located in areas of Indian country.\15\ A Federal
plan would apply to all designated facilities located in the areas of
Indian country unless the EPA approves a TIP applicable to those
facilities.
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\15\ See the EPA's website, https://www.epa.gov/tribal/tribes-approved-treatment-state-tas, for information on those Tribes that
have treatment as a State for specific environmental regulatory
programs, administrative functions, and grant programs.
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C. Where can I get a copy of this document and other related
information?
In addition to being available in the docket, an electronic copy of
this action is available on the internet. A brief summary of this final
rule is available at https://www.regulations.gov, Docket ID No. EPA-HQ-
OAR-2024-0358. Following signature by the EPA Administrator, the EPA
will post a copy of this final action at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations. Following
publication in the Federal
[[Page 18060]]
Register, the EPA will post the Federal Register version of the final
rule and key technical documents at this same website.
A memorandum showing the edits to 40 CFR part 60 subpart OOOOb and
40 CFR part 60 subpart OOOOc finalized in this action is available in
the docket for this action (Docket ID No. EPA-HQ-OAR-2024-0358).
Following signature by the EPA Administrator, the EPA also will post a
copy of this document to https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations.
II. Statutory Background and Regulatory History
A. CAA Sections 111(b) and 111(d)
The EPA's authority for this rulemaking is CAA section 111, 42
U.S.C. 7411, which governs the establishment of standards of
performance for stationary sources. This CAA section requires the EPA
to list source categories to be regulated, establish standards of
performance for air pollutants emitted by new sources in that source
category, and promulgate EG for States to establish standards of
performance for certain pollutants emitted by existing sources in that
source category. For more information on the statutory background of
CAA sections 111(b) and 111(d), and general implementing regulations,
refer to the discussion provided in section IV.A (Statutory Background
of the CAA sections 111(b), 111(d), and General Implementing
Regulations) of the March 2024 final rule preamble. (89 FR 16846-16848;
March 8, 2024).
B. What is the regulatory history and background of NSPS and EG for the
Crude Oil and Natural Gas source category?
On November 15, 2021, the EPA published a ``proposed rule''
(``November 2021 Action'') to reduce GHG and volatile organic compound
(VOC) emissions from the oil and natural gas industry, specifically the
Crude Oil and Natural Gas source category, but did not provide proposed
regulatory text. In the November 2021 Action, the EPA discussed new
standards of performance under CAA section 111(b) for GHG and VOC
emissions from new, modified, and reconstructed sources in this source
category, as well as changes to standards of performance already
codified at 40 CFR part 60, subparts OOOO and OOOOa. The EPA also
proposed EG under CAA section 111(d) for GHG emissions from existing
sources in this source category for the first time. The EPA also
discussed a protocol under the NSPS general provisions for optical gas
imaging (OGI).
On December 6, 2022, the EPA published a supplemental proposed rule
(``December 2022 Supplemental Proposal'') that addressed two additional
issues. First, the EPA proposed to update and expand the NSPS OOOOb
standards in the November 2021 Action for GHG and VOC emissions from
new, modified, and reconstructed sources. Second, the EPA proposed to
update and expand the EG OOOOc standards in the November 2021 Action
for GHG emissions from existing sources. For purposes of EG OOOOc, the
EPA also proposed implementation requirements for State plans.
On March 8, 2024, the EPA published a final rule for the Crude Oil
and Natural Gas source category under CAA section 111(b) and (d) at 89
FR 16820 (``March 2024 Final Rule''). The EPA finalized NSPS OOOOb for
GHG and VOC emissions from new, modified, and reconstructed sources in
this source category. The EPA also finalized EG OOOOc for GHG emissions
from existing sources in this source category. The March 2024 Final
Rule became effective on May 7, 2024. The March 2024 Final Rule applies
to thousands of new sources and will apply to hundreds of thousands of
existing sources when the EG is implemented in the crude oil and
natural gas source category. Crude oil production applicability
includes the well and extends to the point of custody transfer to the
crude oil transmission pipeline or any other forms of transportation;
and natural gas production applicability includes processing,
transmission, and storage, which includes the well and extends to, but
does not include, the local distribution company custody transfer
station.
After the publication of the March 2024 Final Rule, the EPA
identified, through its own internal reassessment, as well as through
communications with stakeholders and the Office of the Federal
Register, erroneous cross-references and typographical errors within
the regulatory text. Through those same processes, the EPA also
identified the need for some minor wording changes to clarify erroneous
language (or, in some cases, erroneous omissions) in the regulatory
text, and to ensure that the regulatory text aligns with the
descriptions of the relevant provisions in the March 2024 Final Rule
preamble and other parts of the regulation(s). The EPA published an IFR
\16\ which made minor and non-substantive corrections to the identified
inadvertent errors in the March 2024 Final Rule.
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\16\ 89 FR 62872 (August 1, 2024); Document ID No. EPA-HQ-OAR-
2021-0317-4057.
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Further, after the publication of the March 2024 Final Rule, the
EPA received multiple petitions \17\ for reconsideration. On May 6,
2024, we notified certain petitioners and the public that we granted
reconsideration on two discrete aspects of the March 2024 Final Rule:
the temporary flaring provisions for associated gas in certain
situations; and the vent gas NHV continuous monitoring requirements and
alternative performance test (sampling demonstration) option for flares
and enclosed combustion devices.\18\ The American Petroleum Institute
(API) and the AXPC,19 20 the TXOGA,\21\ the GPA
Midstream,\22\ and the Environmental Integrity Project \23\ submitted
petitions for reconsideration on those issues. This action finalizes
amendments to the March 2024 Final Rule resulting from our
reconsideration of these two discrete issues.\24\
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\17\ See Docket No. EPA-HQ-OAR-2024-0358 for petitions for
reconsideration received.
\18\ See Docket No. EPA-HQ-OAR-2024-0358 for May 6, 2024, letter
granting reconsideration.
\19\ Letter to Michael S. Regan, EPA Administrator, from API and
AXPC. Re: Provisions in the EPA's Final Rule ``New Source
Performance Standards and Emission Guidelines for Crude Oil and
Natural Gas Facilities: Climate Review.'' Reconsideration of the
Final Rule. April 5, 2024. Hereinafter referred to as the ``April
2024 API and AXPC petition.''
\20\ Letter to Michael S. Regan, EPA Administrator, from API and
AXPC. Re: Request for Administrative Reconsideration of EPA's Final
Rule ``New Source Performance Standards and Emission Guidelines for
Crude Oil and Natural Gas Facilities: Climate Review'' May 6, 2024.
Hereinafter referred to as the ``May 2024 API and AXPC petition.''
\21\ Letter to Michael S. Regan, EPA Administrator, from TXOGA.
Request for Reconsideration of the EPA's Final Rule ``New Source
Performance Standards and Emission Guidelines for Crude Oil and
Natural Gas Facilities: Climate Review.'' May 7, 2024. Hereinafter
referred to as the ``May 2024 TXOGA petition.''
\22\ Letter to Michael S. Regan, EPA Administrator; Gautam
Srinivasan, Associate General Counsel, EPA; and Amy Hambrick, SPPD,
EPA; from GPA Midstream Association. GPA Midstream Association
Petition for Reconsideration and Request for Stay of Standards of
Performance for New, Reconstructed, and Modified Sources and
Emissions Guidelines for Existing Sources: Oil and Natural Gas
Sector Climate Review. May 2, 2024. Hereinafter referred to as the
``May 2024 GPA Midstream petition.''
\23\ Letter to Michael S. Regan, EPA Administrator, from Air
Alliance Houston; Clean Air Council; and Environmental Integrity
Project. Re: Petition for Reconsideration of the Standards of
Performance for New, Reconstructed, and Modified Sources and
Emissions Guidelines for Existing Sources: Oil and Natural Gas
Sector Climate Review; Final Rule, 89 FR 16,820 (March 8, 2024),
Docket No. EPA-HQ-OAR-2021-0317. May 7, 2024. Hereinafter referred
to as the ``May 2024 EIP et al. petition.''
\24\ In the May 6, 2024, letter to petitioners, the EPA also
took the opportunity to clarify the applicable timeframe for
performance testing with respect to NHV sampling.
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[[Page 18061]]
On January 20, 2025, the President issued Executive Orders 14154
(Unleashing American Energy) \25\ and 14156 (Declaring a National
Energy Emergency).\26\ Then, on January 31, 2025, the President issued
Executive Order 14192 (Unleashing Prosperity through Deregulation).\27\
On March 12, 2025, against this backdrop, the EPA announced plans for
deregulatory actions to, among other things, unleash American
energy.\28\ On that same day, and as part of the larger Agency plan,
the EPA announced plans to reconsider the regulations promulgated via
the March 2024 Final Rule ``to ensure they do not prevent America from
unleashing energy dominance.'' \29\
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\25\ 90 FR 8353 (January 29, 2025).
\26\ 90 FR 8433 (January 29, 2025).
\27\ 90 FR 9065 (February 6, 2025).
\28\ https://www.epa.gov/newsreleases/epa-launches-biggest-deregulatory-action-us-history.
\29\ https://www.epa.gov/newsreleases/trump-epa-announces-oooo-bc-reconsideration-biden-harris-rules-strangling-american.
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On July 31, 2025, the EPA promulgated an IFR which extended
deadlines for certain provisions related to control devices, equipment
leaks, storage vessels, process controllers, and covers and closed vent
systems in the NSPS OOOOb.\30\ Within that IFR, the EPA also extended
the date for future implementation of the Super Emitter Program and
extended the State plan submittal deadline in the EG OOOOc. In December
2025, the EPA promulgated a final rule which responded to comments
received on the July 2025 IFR and concluded that the regulatory
amendments made in the IFR were still appropriate after consideration
of comments.\31\ In response to comments received, the December 2025
Final Rule also provided an additional 180-day extension (from the
final rule's effective date) (until June 1, 2026) to the compliance
dates related to NHV monitoring of flares and ECD found in 40 CFR
60.5417b(d)(8)(i) through (iv) and (vi), as well as 360 days from the
effective date of the December 2025 Final Rule (November 30, 2026) for
owners or operators to submit initial annual reports pursuant to 40 CFR
60.5420(b).\32\
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\30\ 90 FR 35966 (July 31, 2025).
\31\ 90 FR 55671 (December 3, 2025).
\32\ See 90 FR at 35970-35972 (July 31, 2025), and 90 FR 55675-
55676 (December 3, 2025) for discussion of the rationale for NHV
monitoring extension.
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C. Judicial Review and Administrative Review
Under CAA section 307(b)(1), judicial review of this final
rulemaking is available only by filing a petition for review in the
United States Court of Appeals for the District of Columbia Circuit by
June 8, 2026. Under CAA section 307(b)(2), the requirements established
by this final rule may not be challenged separately in any civil or
criminal proceedings brought by the EPA to enforce the requirements. 42
U.S.C. 7607(b)(1)-(2).
CAA section 307(d)(7)(B) further provides that ``[o]nly an
objection to a rule or procedure which was raised with reasonable
specificity during the period for public comment (including any public
hearing) may be raised during judicial review.'' This section also
provides a mechanism for the EPA to convene a proceeding for
reconsideration ``[i]f the person raising an objection can demonstrate
to the EPA that it was impracticable to raise such objection within
[the period for public comment] or if the grounds for such objection
arose after the period for public comment, (but within the time
specified for judicial review) and if such objection is of central
relevance to the outcome of the rule.'' 42 U.S.C. 7607(d)(7)(B). Any
person seeking to make such a demonstration to us should submit a
Petition for Reconsideration to the Office of the Administrator, U.S.
Environmental Protection Agency, Room 3000, WJC South Building, 1200
Pennsylvania Ave. NW, Washington, DC 20460, with a copy to both the
person(s) listed in the preceding FOR FURTHER INFORMATION CONTACT
section, and the Associate General Counsel for the Air and Radiation
Law Office, Office of General Counsel (Mail Code 2344A), U.S.
Environmental Protection Agency, 1200 Pennsylvania Ave. NW, Washington,
DC 20460.
III. Summary of Final Amendments to NSPS OOOOb and EG OOOOc
The amendments in this final action relate to two aspects of the
March 2024 Final Rule: the temporary flaring provisions for associated
gas in certain situations; and the vent gas NHV continuous monitoring
requirements and alternative performance test (sampling demonstration)
option for flares and enclosed combustion devices. The two issues
addressed in this final rule are separate and distinct from each other.
Each of these two issues concern different portions of the March 2024
Final Rule that do not rely on the other. This action also finalizes a
technical correction to reinstate regulatory text for the reporting
requirements in 40 CFR 60.5420b(b)(1) through (15), which were
mistakenly deleted by the December 2025 Final Rule.\33\ Also, in this
action, the EPA is finalizing formatting changes to the regulatory text
to meet the required formatting standards of the Office of the Federal
Register.\34\
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\33\ 90 FR 55671 (December 3, 2025).
\34\ To view the final formatting changes, see the full redline
strike out (RLSO) of the regulatory text located in the public
docket at EPA-HQ-OAR-2024-0358.
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Each regulatory change included in this final action is severable
from the other. First, each of the two groups of substantive provisions
amended in this action (temporary flaring of associated gas and vent
gas NHV) is functionally independent from the other--i.e., may operate
in practice independently of the other requirements being amended here,
such that the amendment of one set of requirements does not turn on the
amendment of any other set of requirements. Put another way, the
amendments to the temporary flaring provisions in no way impact or
depend on the separate amendments to the NHV provisions. The same is
true in the opposite direction. The amendments to the NHV provisions in
no way impact or depend on the separate amendments to the temporary
flaring provisions. Second, as explained in this final rule preamble
and the preamble to the proposed rule, the reasoning for each
regulatory change is distinct and independent from the others. For
example, amendments to the NHV provisions are separately justified from
the amendments made to the temporary flaring of associated gas
provisions. Again, the same is true in the opposite direction.
Amendments to the temporary flaring of associated gas provisions are
separately justified from the amendments made to the NHV provisions.
Likewise, the formatting changes are also separate, distinct, and
severable.
A. Temporary Flaring Provisions for Associated Gas in Certain
Situations
Section XI.F.2 of the March 2024 Final Rule preamble presents a
discussion of reasons why an owner or operator would need to flare or
vent associated gas. Based on the reasons set out in that preamble, the
EPA in the March 2024 Final Rule allowed owners and operators to
temporarily route associated gas to a flare or control device for 24
hours in certain situations, including during a deviation caused by a
malfunction (including for reasons of safety) and during repair,
maintenance such as blowdowns, a bradenhead test, a packer leakage
test, a production test, or commissioning. On January 15, 2025, the EPA
proposed extending the allowable time for these situations from
[[Page 18062]]
24 hours to 48 hours (``January 2025 Proposal'').\35\ The EPA proposed
the extended temporary flaring limit based in part on data provided by
API, which showed that 85 percent of flaring events ended within 46
hours for activities such as maintenance, addressing safety issues, and
repairs.
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\35\ 90 FR 3734 (January 15, 2025).
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As discussed in section III.A.2 of the preamble to the January 2025
Proposal, industry petitioners indicated that the 24-hour limitation
for temporary routing of associated gas to a flare or control device in
the March 2024 Final Rule is not sufficient in situations where a
malfunction or an unintended incident endangers the safety of operator
personnel and the public; as well as during repairs, maintenance
(including blow downs), production tests, and commissioning.
Petitioners claimed that a 72-hour timeframe for temporarily routing
associated gas to a flare or control device for these situations is
more appropriate due to the unique characteristics of some well sites
(e.g., due to the differing location and composition/amount of gas
produced by wells), weather conditions, or a combination of both.
After consideration of comments received on the January 2025
Proposal and revisiting the data API provided to the Agency, the EPA is
finalizing two primary changes to the January 2025 Proposal related to
the temporary flaring of associated gas. First, the EPA finds that
increasing the temporary flaring provisions up to 72 hours is
appropriate. This extended timeframe gives owners and operators enough
time to travel to facilities (including geographically remote
facilities), troubleshoot, obtain necessary equipment, and complete
repairs. It also provides sufficient time to overcome many inclement
weather situations where access to a site may be temporarily limited.
Further, moving to 72 hours will reduce the number of incidents where
invoking exigent circumstances is necessary, thus reducing burden on
the industry. Lastly, the extended timeframe also reduces the need to
shut-in operations (where a well is temporarily closed off to restrict
oil and gas flow and production due to unusual or unsafe conditions) in
situations where the issue(s) cannot be addressed within 24 or 48
hours. Shutting-in operations can often result in the depressurization
of equipment, which may lead to the venting of associated gas to the
atmosphere without control. The venting of associated gas in these
scenarios may exceed the emissions that would have otherwise occurred
if the provisions allowed for an additional 24 hours of flaring thereby
defeating the environmental objectives of the rule.\36\
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\36\ See 89 FR 16843-44 (March 8, 2024), section III.B.2.
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Second, and relatedly, the EPA is requiring owners and operators to
stop temporary flaring when repairs or maintenance are completed to
avoid flaring longer than necessary during an individual incident. If
repair or maintenance is completed within 72 hours, then flaring must
stop at the time of completion. In other words, temporary flaring must
cease as early as practicable and within 72 hours unless the facility
properly invokes the procedures for a longer duration. While the 72
hours is a default maximum duration, if a situation arises that
requires an owner or operator to temporarily flare beyond those 72
hours, then the final rule's additional provisions on exigent
circumstances may apply. See section IV.A.1 of this preamble for
further discussion of exigent circumstances. Also see section IV.A.2
for further discussion on temporary flaring beyond 72 hours.
By finalizing an upper limit of temporary flaring up to 72 hours,
the final rule gives operators room to continue to develop ways to
manage delays tied to these malfunctions and failures. At the same
time, it prevents unnecessary flaring when problems are already fixed,
thereby protecting against unnecessary emissions. This balance
encourages owners and operators to keep improving how they detect and
fix problems while providing flexibility and relief. It also supports
better planning, faster repairs, and the potential for greater emission
reductions in the future.
In summary, the EPA is allowing up to 72 hours for certain types of
temporary flaring of associated gas based on information indicating
that more than 24 or 48 hours is needed in some instances. While we
acknowledge owners or operators have an economic incentive not to flare
due to product (natural gas) loss that can equate to lost revenue, we
have included a backstop requirement that owners or operators cease
flaring after resolving the incident causing the need to flare.
Collectively, the EPA is increasing the allowance of temporary flaring
to 72 hours and including a backstop requirement, so owners or
operators have both the economic incentive and a regulatory obligation
to cease flaring of associated gas after an equipment malfunction or
failure is addressed.
Petitioners raised inclement weather as a circumstance that may
deter an owner or operator from accessing an affected facility site and
as a primary cause for the need to temporarily flare (e.g., frozen gas
lines, power outages). While the API dataset classifies inclement
weather as the cause of 86 flaring events, the dataset classifies the
primary cause of over 600 flaring events as ``[u]nknown'' and these
events exhibited the highest average flaring durations and standard
deviations. While we do not know the exact cause of the over 600
``unknown'' flaring events in API's data set, maintaining a 24-hour
flaring timeframe as promulgated in the March 2024 Final Rule based on
the percentage of reported inclement weather-impacted events only
presents a narrow reading of the data and does not reflect the unknown
flaring events that exhibited the highest flaring durations and
standard deviations. The EPA recognizes that the API data show that
many temporary flaring events are resolved within 24 hours, and even
more within 48 hours. Specifically, 83 percent of the instances were
resolved within 24 hours and 85 percent within 48 hours. The EPA
considered establishing cutoffs at 24 hours or 48 hours. However, the
data indicate that 15 percent of instances could not be resolved within
48 hours. Industry noted that weather is a factor, but not the only
factor, impacting temporary flaring events longer than 24 hours, and
geographically dispersed sites, such as the Willison Basin which
contained the majority (78%) of the >24 hour flaring events, add
additional challenge when responding to flaring events. Other causes of
temporary flaring include non-scheduled maintenance or malfunction,
planned maintenance, repair, or tests, and other issues such as weather
or power outages. We determined based on the data and comments received
on the proposal that establishing a cutoff at 24 hours or 48 hours is
not supported because it necessarily fails to include a portion of the
industry that is meaningful in this context. As such, we are finalizing
an allowance to flare up to 72 hours for most situations, and are
providing a mechanism to go beyond 72 hours to allow owners and
operators the time they need to resolve equipment malfunction incidents
and to include a backstop measure to ensure that temporary flaring does
not continue after a malfunction incident is resolved.
In section III.A.3 of the January 2025 Proposal, the EPA
acknowledged that rare instances may occur in which an owner or
operator encounters a
[[Page 18063]]
malfunction, safety, repair, or maintenance event that requires routing
to a flare or control device beyond the proposed 48-hour duration. To
address such instances, the EPA solicited comments on specific
situations that would be considered ``exigent circumstances.'' Based on
comments received and a re-assessment of data provided to the EPA, we
are finalizing an allowance to flare for greater than 72 hours if an
exigent circumstance persists and there is a need to extend the
temporary flaring duration for maintenance, safety issues, or repairs.
While we expect that the vast majority of temporary flaring situations
to be addressed within the 72-hour timeframe, we recognize that there
may be equipment malfunction incidents that require more than 72 hours
to resolve due to circumstances beyond an owner's or operator's
control. However, to ensure flaring does not continue beyond the time
that is necessary to resolve a malfunction incident, we are including a
backstop to this extended timeframe of flaring until such equipment
malfunctions during these exigent circumstances are resolved or no
longer present, whichever is sooner.
After considering input from commenters, the EPA is finalizing that
an ``exigent circumstance'' must be a situation that restricts an
owner's or operator's ability to reasonably access a site with the
necessary equipment and personnel to address and resolve equipment
malfunction incidents that cause the need to temporarily flare
associated gas for more than 72 hours. Reasonable site access is the
ability of an owner or operator to safely transport the necessary
personnel and equipment to a site experiencing an incident. Examples of
possible situations that could limit site access include, but are not
limited to, road washout from flooding; roads obstructed by snow,
debris, or trees; and unsafe travel conditions from extreme weather,
wildfires, and hazmat emergencies. Impediments to resolving equipment
malfunctions also include when an owner or operator is unable to secure
the required equipment to resolve an equipment malfunction incident due
to reasons beyond an owner's or operator's control (i.e., supply chain
issues), or where there is a temporary shortage of personnel due to
reasons beyond an owner's or operator's control (e.g., a national
pandemic). Examples of possible situations that could limit an owner's
or operator's ability to secure required equipment to resolve an
unexpected malfunction due to reasons beyond an owner's or operator's
control include equipment transportation disruptions, trade disputes,
equipment demand competition or national supply chain issues that cause
major delays in securing parts or even render them unavailable for
extended periods of time.
Not all situations that result in the need for temporary flaring
qualify as exigent circumstances. Put another way, not all situations
that result in the need to temporary flare will qualify as exigent
circumstances. For example, inclement weather that results in equipment
failures at a site, such as gas line freezing and power outages, would
generally not constitute an exigent circumstance weather event if
access to the site is not disrupted and equipment and personnel to
resolve equipment malfunctions or failures are available.
Once the site is accessible and necessary equipment and personnel
are available to resolve an equipment malfunction, flaring can continue
until the malfunction is resolved. However, this must be no longer than
72 hours after the site is accessible, and the necessary equipment and
personnel are available to resolve an equipment malfunction. The
exigent circumstances provisions in the final rule are intended to
accommodate rare instances where an owner or operator needs more than
72 hours to return the site to normal operations due to legitimate
unforeseen circumstances outside of their control. The EPA does not
expect that owners and operators will utilize these provisions often,
and these provisions are not intended to allow for indefinite or long-
term flaring. As always, the EPA may bring an enforcement action
against an owner or operator whose actions do not comport with
applicable regulatory provisions.
Lastly, the EPA is finalizing recordkeeping and reporting
requirements when exigent circumstances are invoked. The EPA
anticipates that exigent circumstances will be invoked only in limited
cases, and that these additional recordkeeping and reporting
requirements will not add undue burden to owners and operators. If an
owner or operator claims that an exigent circumstance occurred and
utilizes the extended temporary flaring timeframe, the owner or
operator must maintain records that include: a written description of
the ``exigent circumstance'' requiring the need to flare or route to a
control device beyond 72 hours; a description of steps taken to resolve
the need for temporary flaring/routing to a control device; the dates
and times an identified ``exigent circumstance'' started and ended
(e.g., when owners or operators are able to access site, when personnel
and/or equipment are available) and the total duration of each
``exigent circumstance''; and the dates and times temporary flaring/
routing to a control device started and ended and the total duration of
temporary flaring/routing to a control device due to the identified
``exigent circumstance.'' We require owners and operators to report
this information in their annual report. Owners and operators are
already required to complete recordkeeping and reporting for temporary
flaring events and the additional recordkeeping and reporting
requirements that would result from the extension of flaring duration
beyond the temporary flaring limit for exigent circumstances should not
impose any additional undue burden on the industry.
B. Vent Gas NHV Continuous Monitoring Requirements and Alternative
Performance Test (Sampling Demonstration) Option for Flares and
Enclosed Combustion Devices
The EPA finalized compliance requirements for continuous monitoring
and initial and periodic performance testing for flares and enclosed
combustion device(s) (ECDs) in the March 2024 Final Rule. Of relevance
here are the requirements for those two control devices regarding the
NHV monitoring requirements and alternative performance test (sampling
demonstration) option. In the March 2024 Final Rule, with exceptions
for catalytic vapor incinerators, boilers and process heaters, and
enclosed combustors where temperature is an indicator of destruction
efficiency, all flares and ECD must maintain the NHV of the gas sent to
it above a minimum NHV if the control device is pressure-assisted or
uses no assist gas.37 38 If an
[[Page 18064]]
owner or operator uses a steam- or air-assisted flare or flare, the
owner or operator must maintain the combustion zone NHV
(NHVcz) above a minimum level. If the owner or operator uses
a perimeter assist air ECD or flare, the owner or operator must
maintain the NHV dilution parameter (NHVdil) above a minimum
level. The NHVcz and NHVdil parameter terms
account for the reduction in heating value caused by the introduction
of air and/or steam. These terms were intended to ensure that the
assist gas does not overwhelm the heating value provided by the vent
gas to the point where proper combustion does not occur. Owners or
operators also have the option to apply an alternative test method that
either demonstrates continuous compliance with the combustion
efficiency limit or directly demonstrates continuous compliance with
the NHVcz operating limit and, if applicable, the
NHVdil operating limit.
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\37\ NHV is the potential energy available in a fuel sample,
which is an indicator of flare performance and combustion
efficiency. More specifically, it is the total energy released when
a substance undergoes complete combustion with oxygen under standard
conditions (i.e., the amount of heat released when gas is burned).
See https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/frequently-asked-questions-control-devices#nhv.
\38\ In NSPS OOOOb and EG OOOOc, NHV is typically expressed in
units of Btus per standard cubic feet (scf). In the March 2024 Final
Rule, NHV monitoring is used to determine the Btu content of a gas
stream which indicates whether a control device (i.e., a flare or an
ECD) is reaching the required efficiency by combusting at least 95
percent of the pollutants of concern (i.e., methane and/or VOC). The
March 2024 Final Rule requires that an NHV value must be at or above
a certain Btu/scf threshold, depending on the design of the flare or
ECD. An NHV value below the prescribed applicable minimum NHV value
can be an indicator of reduced control device performance and
efficiency at less than an acceptable level.
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Associated gas from a well site affected facility was exempt from
NHV monitoring (i.e., assumed to always have high NHV) under the March
2024 Final Rule. Also under the March 2024 Final Rule, for each flare
and ECD used to control gases other than associated gas from a well
site affected facility, the owner or operator must conduct continuous
monitoring using a calorimeter, gas chromatograph (GC), or mass
spectrometer (MS) in order to determine the NHV of the vent stream.\39\
As an alternative to continuous monitoring of NHV, the March 2024 Final
Rule allows the owner or operator to conduct a performance test to
demonstrate the NHV of the vent stream that consistently exceeds the
applicable NHV operating limit in one of two ways: continuous sampling
for 14 consecutive days plus ongoing (three samples every five years),
or manual sampling (twice daily for 14 consecutive days) plus ongoing
(three samples every five years) sampling.\40\ The March 2024 Final
Rule requires a minimum collection time of at least one hour for each
individual manually collected sample. If inlet gas flow is intermittent
such that collecting 28 samples in 14 days is infeasible, an owner or
operator must continue to collect samples beyond 14 days in order to
collect a minimum of 28 samples.
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\39\ 89 FR 16820 (March 8, 2024).
\40\ See 40 CFR 60.5417b(d)(8)(iii)(A) and 40 CFR
60.5417b(d)(8)(iii)(G) for NSPS OOOOb sources and 40 CFR
60.5417c(d)(8)(iii)(A) and 40 CFR 60.5417c(d)(8)(iii)(G) for EG
OOOOc sources.
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Owners or operators also have the option to use an alternative test
method that demonstrates continuous compliance with the combustion
efficiency limit.41 42 If there are no values of the
combustion efficiency measured by the alternative test method over the
14-day period that are less than 95 percent, the gas stream is
considered to consistently exceed the applicable NHV operating limit
and the owner or operator is not required to continuously monitor or
conduct sampling of the NHV of the inlet gas to the flare or ECD.\43\
Under the March 2024 Final Rule, owners or operators of steam- and air-
assisted flares and ECD also must monitor the vent gas and assist gas
flow rates and calculate NHVcz and NHVdil in
accordance with the provisions in 40 CFR 63.670 (i.e., the refinery
maximum achievable control technology (MACT) rule, or ``Refinery MACT''
as codified in 40 CFR 63, National Emission Standards for Hazardous Air
Pollutants (NESHAP) subpart CC). Alternatively, owners or operators of
air-assisted flares may provide a one-time demonstration based on
maximum air assist rates, minimum waste gas flow rates (based on
backpressure regulator setting), and minimum NHV from the most recent
sampling rather than continuously monitor vent gas and assist gas flow
rates.\44\
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\41\ Under the provisions outlined in 40 CFR 60.5412b(d) and
60.5415b(f)(1)(xi), sources can request to use an ``equivalent
method'' pursuant to 40 CFR 60.8(b)(2), or ``an alternative method
the results of which [the Administrator] has determined to be
adequate for indicating whether a specific source is in compliance''
pursuant to 40 CFR 60.8(b)(3). The EPA is currently accepting and
reviewing applications for alternative (ALT) test methods for NHV
monitoring in the oil and natural gas sector. See https://
www.epa.gov/emc/oil-and-gas-alternative-test-
methods#:~:text=The%20application%20portal%20can%20be,Air%20Emission%
20Measurement%20Center%20webpage. Since the March 2024 Final Rule's
publication, two alternative test method requests have been approved
by the EPA for use under NSPS subpart OOOOb: (1) ALT-156 Alternative
Test Method to monitor the NHV of the flare combustion zone at
facilities subject to NSPS OOOOb and (2) ALT-157 Alternative Test
Method for determining NHV from gas sent to an ECD or Flare subject
to NSPS OOOOb. A list of the EPA's approved alternative test methods
can be found at https://www.epa.gov/emc/broadly-applicable-approved-alternative-test-methods.
\42\ Per 40 CFR 60.8(b)(5), the EPA has more general authority
to approve alternative test methods involving ``shorter sampling
times and smaller sample volumes when necessitated by process
variables or other factors.''
\43\ See 40 CFR 60.5417b(d)(8)(iii)(D) and 40 CFR
60.5417c(d)(8)(iii)(D).
\44\ See 40 CFR 63.670(j)(6).
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In this Final Rule, the EPA is revising numerous aspects of the NHV
monitoring and testing provisions in the March 2024 Final Rule. The EPA
presented the rationale for these revisions in section III.B of the
preamble of the January 2025 Proposal, with additional details provided
in section IV.B of this preamble.
The EPA is expanding the gas streams that are exempt from
monitoring due to high NHV content to include all flare and ECD for
both new and existing sources. However, the EPA is also requiring that
NHV monitoring be performed (via either continuous monitoring or the
alternative performance test (sampling demonstration) option currently
prescribed in the NSPS OOOOb and EG OOOOc regulations) in cases where
inert gases are added and for other miscellaneous scenarios which
decrease the NHV content of the inlet stream gas to all flare and ECD
for both new and existing sources.\45\ Examples of these known
operational scenarios include combining acid gas removal (AGR) system
amine regenerator still column vent gas with affected facility vent
gas, combining glycol dehydration unit reboiler vent gas with affected
facility vent gas streams without water removal, high water content in
vent streams from certain storage vessels, and enhanced oil recovery
(EOR) sites in fields using water or carbon dioxide (CO2)
flooding. The EPA is finalizing recordkeeping and reporting
requirements to specifically indicate whether the flare or ECD receives
(or does not receive) inert gases (inerts) or other streams which may
lower the NHV of the combined stream, and, if so, a description of the
operating scenario(s) which may lower the NHV of the combined stream
through the introduction of those inert gases or other streams.
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\45\ For the purposes of the NHV compliance provisions, inert
gases (or ``inerts'') are gases that do not readily undergo
combustion. Inert gases consist of or contain high concentrations of
nitrogen, CO2, water, or other compounds that have a net
heating value of zero. See 90 FR 3742 (January 15, 2025).
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The EPA is also finalizing, as proposed, to replace the general
exemption from NHV monitoring for associated gas for any control device
used at ``well site affected facilities'' with NHV monitoring that is
more reflective of industry operations, in order to be consistent with
the overall NHV monitoring requirements for all affected OOOOb and
OOOOc sources.\46\
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\46\ 90 FR 3746 (January 15, 2025).
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In addition, when an owner or operator chooses to meet the NHV
compliance demonstration by conducting the alternative performance test
via the NHV grab sampling option, the EPA is finalizing, as proposed, a
clarification that sampling may be conducted upstream of the inlet to
the control device, provided that the sample is representative of the
gas inlet to the
[[Page 18065]]
control device. For example, sampling may be conducted from a location
on the control device piping header, provided the sampling location is
downstream of all waste gas inlets into the header.
The EPA is finalizing, as proposed, a clarification that the NHV of
the vent stream must be determined in British thermal units per
standard cubic feet (Btu/scf), where standard conditions are 20 degrees
Celsius ([deg]C), not British thermal units per pound (Btu/lb). If the
composition is determined in weight percent, those concentrations can
be used, but they will need to be converted to volume percent
(equivalent to mole percent) based on the molecular weight of the
constituents.
The EPA is also finalizing, as proposed, that the 14-day period for
the performance test (sampling demonstration) option must be
consecutive operating days, while also allowing for breaks in
performance testing over weekends and holidays which may occur during
the 14-day sampling period, provided that no sampling day is spaced
more than 3 operating days apart from the previous sampling
day.47 48
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\47\ In this context, an ``operating day'' is considered a
normal business day of operation (i.e., Monday-Friday), and weekends
and holidays are considered calendar days, but not ``operating
days.''
\48\ However, if the affected source is operating during a given
weekend or holiday, the facility may elect to either sample or not
sample during the weekend or holiday.
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In addition, the EPA is specifying that for the purposes of
determining the hourly average for continuous samples, the average
shall be a block hourly average.\49\ The EPA is not amending the
sampling frequency (i.e., two samples per day for 14 days with an
ongoing demonstration of three samples every five years) for the
performance test (sampling demonstration) option for either NSPS OOOOb
or EG OOOOc.
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\49\ Each block average value for each 1-hour period (or shorter
periods) are to be calculated from all measured data during each
period. If the inlet stream is continuously sampled for 14 days, the
hourly block average will be determined on a noon to 1 p.m., 1 p.m.
to 2 p.m., etc. basis.
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The EPA is also retaining the one-hour minimum sampling time for
the twice daily samples, except in cases where low or intermittent flow
makes one-hour sampling infeasible for both NSPS OOOOb and EG OOOOc
sources. In such a case, the EPA is allowing less than one-hour
sampling times, provided that the sampling time used and the reason for
the reduced sampling time is documented and reported.
The EPA is finalizing, as proposed, a clarification in both NSPS
OOOOb and EG OOOOc to more clearly allow the use of the sampling
methodology alternative to the continuous monitoring in 40 CFR
60.5417b(d)(8)(iii) for all types of air- and steam-assisted flares or
ECD.
Finally, for NSPS OOOOb, the EPA is retaining the NHVcz
and NHVdil monitoring requirements but more clearly
including the provisions at 40 CFR 60.5417b(d)(8)(vi) to allow for the
use of approved alternative test methods as provided in 40 CFR
60.5412b(d)(1)(i) and (ii) for continuous monitoring of
NHVcz and, if applicable, NHVdil. We are also
finalizing, as proposed, a clarification in 40 CFR 60.5417b(d)(8)(iv)
regarding when flare flow or assist rates are not required to be
monitored. In addition, as proposed, for EG OOOOc, the EPA is removing
the requirement to comply with and conduct monitoring for
NHVcz and NHVdil for air- and steam-assisted
flares and ECD used for existing sources. This series of revisions in
EG OOOOc includes changes in the initial compliance requirements for
air- or steam-assisted flares or ECD in 40 CFR 60.5412c, the continuous
compliance requirements for these control devices in 40 CFR 60.5415c,
and the continuous monitoring requirements for these control devices in
40 CFR 60.5417c. We are also finalizing, under EG OOOOc, that air- or
steam-assisted or flares or ECD must meet an increase in the minimum
NHV in the vent gas from 270 to 300 Btu/scf.
C. Correction of Inadvertent Deletion of Regulatory Text
As discussed above, in the July 2025 IFR, the EPA amended certain
compliance deadlines and timeframes for implementation in response to
information received after promulgation of the 2024 Final Rule to
address significant concerns that certain regulatory provisions in the
March 2024 Final Rule were not workable or contained problematic
regulatory language that prevented compliance. On December 3, 2025, the
EPA published a final rule that included discrete changes to specific
regulatory text within 40 CFR part 60 subpart OOOOb (December 2025
Final Rule).\50\ Specifically, the EPA finalized amendments to the
compliance deadline for NHV monitoring and provided additional time for
the submission of initial annual reports at 40 CFR 60.5420b(b). The
amendatory instructions for the final rule inadvertently amended all of
40 CFR 60.5420b(b) paragraph (b) in lieu of just the introductory text
for paragraph (b), as intended. This resulted in the erroneous deletion
of paragraphs 40 CFR 60.5420b(b)(1) through (15), which was neither
intended nor proposed.
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\50\ 90 FR 55671 (December 3, 2025).
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To correct this inadvertent error, the EPA is finalizing a
technical correction to reinstate regulatory text for the reporting
requirements in 40 CFR 60.5420b(b)(1) through (15). The substance of
the December 2025 Final Rule remains unchanged by reinstating this
erroneously-deleted regulatory text. Section 553(b)(B) of the
Administrative Procedure Act, 5 U.S.C. 553(b)(B), provides that, when
an agency for good cause finds that public notice and comment
procedures are impracticable, unnecessary, or contrary to the public
interest, the agency may issue a rule without providing notice and an
opportunity for public comment. The EPA has determined that there is
good cause for making this technical correction final without prior
proposal. Such notice and opportunity for comment is unnecessary, as
this technical correction restores the unintentional deletion of
regulatory text made by the regulatory revisions associated with the
December 2025 Final Rule.
The application of the APA's ``good cause'' exemption in this final
rule is limited to correcting the inadvertent deletion of 40 CFR
60.5420b(b)(1) through (15) and does not extend to any other portion of
this final rule. Further, by correcting this unintentional error, EPA
is not reopening any issues from the December 2025 Final Rule or the
associated IFR from July of 2025.
IV. Significant Comments and Changes Since Proposal for NSPS OOOOb and
EG OOOOc (January 2025 Proposal)
This section of the preamble presents in each subsection a detailed
summary of the significant comments received on, and changes made,
since the January 2025 Proposal for the topic addressed in that
subsection. This final action does not address or take any position on
the best system of emission reduction (BSER) analysis included in the
March 2024 Final Rule record which the EPA used to support promulgation
of the standards included in NSPS OOOOb and the presumptive standards
included in EG OOOOc.
[[Page 18066]]
The EPA's full response to comments on the January 2025 Proposal,
including any comments not discussed in this preamble, is available in
the EPA's Response to Comment (RTC) document for this final rule.\51\
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\51\ Reconsideration of Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review:
Response to Public Comments on the January 2025 Proposed Rule (90 FR
3734; January 15, 2025). Included in Docket ID EPA-HQ-OAR-2024-0358.
---------------------------------------------------------------------------
A. Temporary Flaring Provisions for Associated Gas in Certain
Situations
For oil wells that are not routinely flaring (i.e., wells that
route associated gas to sales lines or an equivalent alternative), the
March 2024 Final Rule allowed owners and operators to route associated
gas to a flare or control device in certain situations for 24 hours.
These situations include times when there is a need to flare due to
malfunctions, including for safety reasons. Further, these situations
may include repair, maintenance (including blowdowns), bradenhead test,
packer leakage test, production test, or commissioning. As stated in
the January 2025 Proposal, industry petitioners seeking reconsideration
claimed that the 24-hour limitation for temporary flaring is not
sufficient for malfunctions, including for reasons of safety, and/or
for repair and maintenance. Additionally, they claimed well sites may
not be accessible during weather events (i.e., winter storms), which
are a significant factor for temporary flaring that lasts for more than
24 hours. Industry petitioners maintained that a 72-hour timeframe is
more appropriate for temporary flaring due to the unique
characteristics of each wellsite, weather conditions, or a combination
of both. In the January 2025 Proposal, the EPA proposed to allow 48
hours for temporary flaring based on submitted industry data. The EPA
agreed that the data showed that 24 hours was insufficient to resolve
all malfunction, maintenance, and repair events. In the January 2025
proposal, the EPA also solicited comments on allowing owners and
operators of associated gas affected facilities to route to a flare or
control device for up to 72 hours if exigent circumstances exist, since
the industry indicated that some events last for more than 48 hours. In
particular, the EPA solicited comments on whether there are other
specific exigent circumstances for which the EPA should consider
allowing an owner or operator to route to a flare or control device
beyond the proposed 48-hour allowance for repairs and malfunctions.
Furthermore, the EPA solicited comments on recordkeeping and reporting
requirements if the EPA were to include an allowance for owners or
operators of associated gas affected facilities to route to a flare or
control device for up to 72 hours for exigent circumstances.
The EPA received several comments on this aspect of the January
2025 Proposal. The EPA received comments on exigent circumstances, the
temporary flaring timeframe, and recordkeeping and reporting
requirements. These comments and the EPA's responses are provided in
sections IV.A.1 through 4 of this preamble. The EPA also received
comments requesting alternative exemptions and cutoffs to limit
temporary flaring. These comments and the EPA's responses are provided
in section IV.A.5 of this preamble. The EPA's full response to comments
on the January 2025 Proposal, including any comments not discussed in
this preamble, is available in the EPA's RTC document for the final
rule.
1. Exigent Circumstances
In the January 2025 Proposal, the EPA solicited comment on allowing
owners or operators of associated gas affected facilities to
temporarily route the associated gas to a flare or control device for
up to 72 hours in certain situations if exigent circumstances exist.
Such exigent circumstances would include situations where an owner or
operator cannot physically access a site due to weather or other
conditions (e.g., road closures). In addition to extreme weather events
and road closures, the EPA solicited comment on whether there are other
specific exigent circumstances for which the EPA should consider
allowing an owner or operator to route to a flare or control device
beyond the proposed 48-hour allowance for repairs and malfunctions. The
EPA received several comments on this aspect of the January 2025
Proposal. These comments and the EPA responses are provided in this
section of the preamble.
Comment: Several commenters requested that the EPA include other
exigent circumstances in addition to those proposed. One commenter
requested that the EPA clarify that exigent circumstances include, but
are not limited to, flooding, road washouts, fires and explosions,
personnel shortages due to illness or labor disputes, wildfires,
earthquakes, hazmat emergencies, evacuation orders, war or civil
unrest, and equipment supply chain issues.\52\
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\52\ Document ID No. EPA-HQ-OAR-2024-0358-0082.
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Another commenter \53\ noted that, as stated in previous comments
they submitted on the December 2022 Supplemental Proposal,\54\ it is
often necessary to temporarily route gas to control devices for safety
and/or operational purposes in situations when associated gas could not
be routed to a sales line or used for other beneficial purposes. The
commenter requested that the EPA provide additional flexibility to
allow temporary routing of gas to control devices when other exigent
circumstances exist, including, but not limited to, interruption in
service, extreme weather events, and road closures that prevent access
to sites. The commenter stated that the January 2025 Proposal cites an
API survey that concluded the average duration for temporary flaring
was 46 hours per event. While the changes in the January 2025 Proposal
to allow temporary flaring from 24 to 48 hours might accommodate the
average temporary flaring event determined in the study, the commenter
urged the EPA to consider allowing temporary flaring of 72 hours or
more to account for the varying configurations of well sites and
exigent circumstances.
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\53\ Document ID No. EPA-HQ-OAR-2024-0358-0085.
\54\ Docket ID No. EPA-HQ-OAR-2021-0317.
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Consistent with the previous comment, another commenter noted that
the EPA requested input on other exigent circumstances that warrant
flaring beyond 48 hours.\55\ The commenter listed inclement weather,
site access, operations outside normal business hours, availability of
service providers and equipment, safety of operator personnel or the
public, and repair, maintenance, production testing, or commissioning
as exigent circumstances warranting longer flaring times. However, the
commenter recommended that the EPA allow other scenarios when 72 hours
of flaring would result in lower emissions than the alternative, e.g.,
shutting down a facility requiring blowdowns that vent emissions to the
atmosphere resulting in greater emissions as compared to those from
flaring. As such, the commenter requested that the EPA consider all
exigent circumstances to include situations where the alternative
operation would result in more emissions, rather than allowing flaring
for 72 hours.
---------------------------------------------------------------------------
\55\ Document ID No. EPA-HQ-OAR-2024-0358-0095.
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Response: As noted in section III.A.4 of the January 2025 Proposal
(Basis for Proposed Changes), the EPA acknowledges that there are
special
[[Page 18067]]
situations where a longer timeframe than proposed may be needed and
such circumstances may be beyond the owner's and operator's control.
While the EPA agrees with some commenters that other exigent
circumstances should be included in addition to extreme weather events
and road closures, not every situation suggested by commenters
qualifies as an exigent circumstance. As explained in section III.A of
this preamble, the events that qualify for the exigent circumstances
extension should be severe in nature and have a direct impact on the
owner's or operator's ability to physically access the site with the
necessary equipment and personnel to address the equipment malfunction
incident which caused the need to temporarily flare. For instances
where there is a need to flare beyond 72 hours due to an unexpected
malfunction event and equipment and/or personnel are not readily
available due to supply chain issues and/or temporary personnel
shortages due to reasons beyond an owner's or operator's control, the
EPA agrees that allowing an owner or operator to flare beyond 72 hours
meets EPA's intent of what is considered an ``exigent circumstance''
and we revised the final rule to specifically allow flaring beyond 72
hours for such instances. While the EPA acknowledges that there may be
instances when extraordinary circumstances, such as a national pandemic
which is beyond an owner's or operator's control, could result in a
temporary shortage of personnel being available to resolve an
unexpected malfunction or to access a facility within 72 hours of an
event, we do not consider personnel shortages due to illness or labor
disputes to qualify as exigent circumstances. Personnel shortages due
to illness or labor disputes are best characterized as an internal
operational matter for which the owner or operator holds primary
responsibility and is expected to manage through appropriate
contingency planning.
To address commenters' concerns, the final rule defines an
``exigent circumstance'' to be a situation that results in the
inability to reasonably access a site with the necessary equipment and
personnel to address and resolve incidents that cause the need to
temporarily flare associated gas for more than 72 hours. This includes
circumstances where there is a need to flare beyond 72 hours due to an
unexpected malfunction event and equipment needed to resolve an
incident are not readily available due to an owner's or operator's
inability to secure the required equipment for reasons beyond an
owner's or operator's control (i.e., supply chain issues); or there is
a temporary shortage of personnel needed to resolve an incident due to
a circumstance such as a declared national pandemic that is beyond an
owner's or operator's control.
To address a commenter's request that we allow flaring for exigent
circumstances to include situations where an alternative operation
would result in more emissions rather than allowing flaring for 72
hours, we revised the final rule to allow flaring for up to 72 hours
and beyond 72 hours for exigent circumstances, reducing the need for
well shut ins.
In this final action, we are revising the March 2024 Final Rule to
allow temporary flaring of associated gas for up to 72 hours for
situations where the owner or operator cannot comply with the standard
due to malfunctions, including reasons for safety, repairs, and
maintenance. For exigent circumstances, an owner or operator can
temporarily route to a flare or control device for durations over 72
hours until an exigent circumstance is no longer present. Following the
new temporary flaring timeframe extension and clarification of what
constitutes an exigent circumstance as stated in section III.A of this
preamble, we disagree that some of the events listed by commenters
(operations outside normal business hours, availability of service or
equipment, safety of the operator or the public, and activities like
repair, maintenance, production testing, or commissioning) on their own
qualify as exigent circumstances. In these instances, an owner or
operator will have up to 72 hours to resolve equipment malfunctions,
which is in line with what the commenter requested. However, we also
acknowledge that some of these situations may fall under an exigent
circumstance if the necessary equipment and personnel are not available
to resolve a malfunction incident within a 72 hour timeframe due to
circumstances that are beyond an owner's or operator's control, or
access to a site is restricted due to worker safety (e.g., if traveling
to the site is unreasonably dangerous due to a wildfire). After
invoking exigent circumstances, flaring can continue until the
equipment malfunction incident is resolved. However, this must be no
longer than 72 hours after the site can be accessed, and the necessary
equipment and personnel are obtained (72 hours after the exigent
circumstances which prevented access and equipment malfunction repair
are no longer present).
2. Allowance for Temporary Flaring of 72 Hours or More
In the January 2025 Proposal, the EPA proposed extending the
allowable time for temporary flaring of associated gas during
malfunctions, including for reasons of safety and during repair and
maintenance. The proposed allowable timeframe was 48 hours, an increase
from 24 hours in the March 2024 Final Rule. In response, several
commenters requested that the EPA further extend the temporary flaring
allowance to 72 hours. These commenters argued that a longer duration
would better reflect field conditions, particularly in areas where
access to equipment or personnel is delayed due to weather, geography,
or other logistical barriers. They stated that even with proactive
planning, certain malfunctions or maintenance activities may require
more than 48 hours to resolve. The commenters also noted that forcing
operators to end flaring before the issue is resolved could create
safety risks or lead to unnecessary equipment shutdowns.
Other commenters disagreed and urged the EPA to retain the original
24-hour limit or allow for extensions only when operators clearly
justify the need based on specific facts. They expressed concern that a
blanket 72-hour window could weaken enforcement and lead to longer
periods of uncontrolled emissions. They emphasized the need for clear
limits to ensure that temporary flaring remains a last resort and is
used only when necessary. The API data submitted to the EPA along with
information from other stakeholders \56\ show a range of flaring
durations, with a notable percentage of events exceeding both 24 and 72
hours. These data suggest that while an extended flaring duration is
not the norm, it does occur with some regularity, especially in cases
involving equipment failure, inclement weather conditions and/or
limited site access. Several comments were received on this aspect of
the January 2025 Proposal. These comments and EPA's responses are
provided in this section of the preamble.
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\56\ Docket ID No. EPA-HQ-OAR-2024-0358.
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Comment: One commenter \57\ appreciated the EPA's acknowledgment
that a 24-hour limit on temporary flaring during situations they
describe as ``Critical Circumstances'' (e.g., due to a malfunction or
incident that endangers the safety of operator personnel or the public
or during repair and maintenance
[[Page 18068]]
activities) is often infeasible and warrants additional time,
particularly for remote, unmanned sites in areas prone to extreme
weather events and poor road conditions.\58\ However, they expressed
that they do not believe that the proposed 48-hour allowance will allow
sufficient time to fix the problem and return the site to normal
operations such that temporary flaring can stop during many ``critical
circumstances.'' The commenter suggested that a 72-hour temporary
flaring duration would provide sufficient time to respond to,
troubleshoot, and repair equipment during most, but not all, ``critical
circumstances'' in areas where extreme weather and road conditions are
frequent, such as during the winter months in North Dakota.\59\
Further, the commenter added that these repairs are often dangerous to
undertake due to the extreme weather in, for example, North Dakota's
Williston Basin. For instance, the commenter reported that on February
10th, 2025, the National Weather Service issued an Extreme Cold Warning
in the majority of counties in North Dakota, advising that ``life
threatening wind chills as low as 55 below zero could cause frostbite
on exposed skin in as little as 5 minutes.'' \60\ The National Weather
Service also advised to take precautions ``if you must go outside.''
\61\ The commenter stated that requiring operators to undertake
immediate repair work in these conditions can unnecessarily put them in
harm's way. For those ``critical circumstances'' that would otherwise
require longer than 72 hours, the commenter noted that operators ``must
innovate and improve their maintenance, response, and repair practices
to meet what would remain a challenging deadline in many instances.''
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\57\ Document ID No. EPA-HQ-OAR-2024-0358-0092.
\58\ The EPA notes that while the commenter uses the term
``Critical Circumstances,'' we interpret this to mean ``exigent
circumstances.''
\59\ To date, Hess (the commenter) has provided the EPA with
extensive documentation of circumstances affecting its Williston
Basin production operations that necessitate up to 72-hours for
temporary flaring in these circumstances. See November Hess
Presentation; Hess Corporation, Hess Briefing for EPA: Oil and
Natural Gas Final Methane Rule NSPS OOOOb and EG OOOOc, EPA-HQ-OAR-
2024-0358-0020 (Feb. 29, 2024) (``February Hess Presentation'');
Hess Corporation, Hess Briefing for EPA: NSPS OOOOb Safety,
Malfunction & Repair Temporary Flaring Allowance, EPA-HQ-OAR-2024-
0358-0031 (June 3, 2024) (``June Hess Presentation''); Hess
Corporation, McKenzie County Frost Restrictions, EPA-HQ-OAR-2024-
0358-0037 (July 19, 2024); Hess Corporation, Examples of North
Dakota Road Closures and Restrictions, EPA-HQ-OAR-2024-0358-0037
(July 19, 2024); Hess Corporation, Hess E.O. 12866 Meeting with OMB/
OIRA: Oil and Natural Gas NSPS OOOOb and EG OOOOc Reconsideration
Proposal, 13, EPA-HQ-OAR-2024-0358-0038-0046 (Nov. 7, 2024)
(``November Hess Presentation'').
\60\ National Weather Service, NWS Alerts, https://alerts.weather.gov/search?history=1&zone=NDZ009 (last visited Feb.
28, 2025).
\61\ Id.
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The same commenter provided that, in the January 2025 Proposal, the
EPA cited survey data provided by API (the ``Temporary Flaring
Survey'') to support extending the temporary flaring allowance up to 48
hours.\62\ The EPA proposed extending the temporary flaring allowance
from 24 to 48 hours in the January 2025 Proposal based on the Temporary
Flaring Survey's average flaring duration time of 46 hours. In doing
so, the commenter asserted that the EPA ignored that the data shows the
average flaring duration is not uniform across basins. According to the
commenter, both the Temporary Flaring Survey and the commenter's own
data \63\ demonstrate that the widely dispersed facilities and extreme
winter weather conditions in the Williston Basin (North Dakota and
Montana) can necessitate longer temporary flaring for responding to
``Critical Circumstances'' other than warmer and more easily accessed
basins, like the Permian Basin (Texas and New Mexico). They highlighted
that the Temporary Flaring Survey data shows that Williston Basin
flaring incidents exceeded 72 hours in 78 percent of the reported data,
compared to just 11 percent in the Permian Basin.\64\ For the Permian
Basin, they highlighted that 12 percent of flaring events exceeded 24
hours, claiming that where flaring exceeded 24 hours, it is extremely
probable the flaring continued beyond 72 hours. The commenter reported
that its extensive temporary flaring data (e.g., Temporary Flaring
Survey) shows that an average of approximately 72 hours of temporary
flaring is necessary during their ``Critical Circumstances.'' The
commenter asserted that the data and information provided by both API
and Hess suggest that a 72-hour temporary flaring duration allowance is
an appropriate default for a nationwide rule.\65\
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\62\ See American Petroleum Institute, Operator Survey:
Temporary Flaring, 4, EPA-HQ-OAR-2024-0358-0038 (July 2024)
(``Temporary Flaring Survey'').
\63\ Hess's operations in the Bakken formation span roughly
7,200 square miles and include many unmanned sites. Hess provided
information demonstrating that it often cannot physically access a
site within 48 hours, and seasonal conditions and extreme weather
events may delay accessibility for days and up to over a week until
access roads to a wellsite are passable. See November Hess
Presentation at 10.
\64\ Temporary Flaring Survey at 6.
\65\ See Hess Corporation, Hess E.O. 12866 Meeting with OMB/
OIRA: Oil and Natural Gas NSPS OOOOb and EG OOOOc Reconsideration
Proposal, 13, EPA-HQ-OAR-2024-0358-0046 (Nov. 7, 2024) (``November
Hess Presentation'').
---------------------------------------------------------------------------
The commenter added that it provided temporary flaring data that
reflected events that it had identified internally as the highest
priority of work (``break-in work'').\66\ The commenter explained that
this is the priority given to ``Critical Circumstance'' responses. The
commenter added that its sites are often not accessible within 24 hours
due to difficult terrain, long travel distances between facilities, and
extreme weather. These conditions are an impediment to the first step
in response: travelling to the facility to investigate the cause of the
``Critical Circumstance.'' The commenter added that its data show the
average response time from notification creation to resolution was
slightly more than 72 hours; however, as an average implies, many
events lasted longer than 72 hours. The commenter contended that its
data demonstrate that 48 hours is often not long enough to travel to
the facility, troubleshoot, obtain necessary equipment, and complete
repair, even with normal business processes that incorporate
efficiencies.\67\ The commenter asserted that the EPA's proposed 48-
hour limit inappropriately relied on a summary report from New Mexico
and from a Colorado regulation to assert that a 48-hour period is
sufficient for temporary flaring for malfunction/safety and repair/
maintenance situations. However, the commenter noted that areas such as
North Dakota are subject to more frequent and more extreme weather
events than those areas.
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\66\ Hess's ``highest priority notifications'' response system
prioritizes repair work that can result in temporary flaring above
previously scheduled work. Hess provided the EPA with data showing
that the average notification creation to resolution cycle times
between 2020 and 2024 averaged 3.2 days. See June Hess Presentation
at 12.
\67\ Under Hess's ``highest priority notifications'' response
system, it can still sometimes take up to 21 hours for an operator
to access the facility and identify the problem necessitating the
temporary flaring. If a maintenance crew is required for repair, it
can take multiple days even with equipment available. See June Hess
Presentation at 12.
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In addition, the commenter explained that oil and gas facilities in
North Dakota are spread across expansive and geographically remote
locations.\68\ The commenter expressed that it does not believe it is
appropriate to finalize a one-size-fits-all approach based on these two
unique States (i.e., Colorado and New Mexico). Moreover, the commenter
reiterated that the Permian Basin data in the Temporary Flaring Survey
shows that where flaring exceeded 24 hours, it
[[Page 18069]]
is extremely probable that flaring exceeded 72 hours. In conclusion,
the commenter argued that a blanket 72-hour temporary flaring allowance
for ``Critical Circumstances'' provides a more reasonable timeframe and
will force operator innovation.
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\68\ See Hess Corporation, Hess' Bakken Operating Area, EPA-HQ-
OAR-2024-0358-0038-0037_attachment 1 (July 19, 2024).
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Conversely, another commenter urged the EPA not to allow operators
to temporarily route associated gas to a flare or control device for up
to 72 hours for weather-related delays.\69\ The commenter did not
support any additional allowances for temporary flaring for up to 72
hours. In the commenter's opinion, the Temporary Flaring Survey does
not support the need for a 72-hour allowance for weather-related
delays. The commenter reported that only three percent of the total
data demonstrated that inclement weather was the cause of needing time
to mitigate flaring with an average duration of 21 hours of temporary
flaring per event.
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\69\ Document ID No. EPA-HQ-OAR-2024-0358-0096.
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The commenter also pointed to the Temporary Flaring Survey data on
reportable emission events from the 2021 winter storm Uri that impacted
Texas.\70\ The data includes all reportable emission events the Texas
Commission on Environmental Quality (TCEQ) received from all industry
sectors in the State. The commenter expressed that it is vital that the
EPA examines this data in more detail before moving forward with any
extension of temporary flaring duration based on weather. The commenter
highlighted that the TCEQ dataset includes 328 emission events, but 78
percent of those events occurred at facilities that are not upstream
oil and gas facilities and argued that those events are therefore not
relevant to any decision to allow for extended flaring due to inclement
weather.
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\70\ See API, Document ID No. EPA-HQ-OAR-2024-0358-0038,
attachment 6.
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Response: The EPA appreciates the information and insights provided
by commenters and agrees overall with the recommendations for extending
the temporary flaring allowance to 72 hours. We agree with the
commenters that the proposed 48-hour temporary flaring limit, while
directionally helpful, does not adequately address the logistical
complexities present in the widely dispersed locations in the oil and
gas industry. Allowing for up to 72 hours promotes administrability and
equitable treatment among sites for the vast majority of flaring
incidents discussed in this preamble, while also providing for
emissions reductions in tandem with the requirement that sources stop
flaring as soon as the qualifying incident is resolved. Compliance with
these requirements will be reported to the EPA and enforced through a
combination of new (finalized in this rule) and preexisting (from the
2024 rule) emissions-reporting obligations, and many facilities have an
independent economic incentive to cease unnecessary flaring where the
gas could otherwise be captured and sold.
The Temporary Flaring Survey indicates that more than 17 percent of
flaring events required more than 24 hours of temporary flaring of
associated gas per event, and more than 15 percent of flaring events
required more than 72 hours of temporary flaring per event. The causes
of these extended flaring durations were multifaceted and included
inclement weather, primarily in the Williston Basin which routinely
faces harsh winter weather conditions, and other factors such as the
unique characteristics of each wellsite (unmanned, remote, and
dispersed).
Critically, weather is not the only contributor to extended flaring
events, as demonstrated in the dataset and comments provided by
petitioners. Information gathered from industry meetings and the
Temporary Flaring Survey indicate that these logistical challenges
exist regardless of weather and are often intensified by routine
operational hurdles such as scheduling contractor support, transporting
heavy equipment, and adhering to internal safety procedures. Further
analysis reveals the Temporary Flaring Survey reported 86 flaring
events as weather-impacted events, and the survey classified over 600
flaring events as ``[u]nknown.'' While we do not know the cause of the
need to flare for the over 600 flaring events in the Temporary Flaring
Survey, maintaining a 24-hour, or even 48-hour, flaring timeframe based
on the percentage of reported inclement weather-impacted events
presents a narrow reading of the data and does not reflect the
``[u]nknown'' flaring events that exhibited the highest flaring
durations and standard deviations. The commenter's argument centers on
a narrow interpretation of weather-related flaring events that
indicates that only three percent of total incidents in the Temporary
Flaring Survey cite weather as the cause for the need to flare and that
those averaged 21 hours per event.\71\ While it is true that the
Temporary Flaring Survey indicates that flaring events often can be
resolved quickly, the data and information provided by industry also
indicate that other factors can impact an owner's or operator's ability
to limit the duration of flaring that are beyond their control. In
instances where an owner or operator is able to limit the duration of
flaring by addressing the cause of the need for flaring in a timely
manner, an owner or operator is encouraged to limit the flaring
duration to the maximum extent possible. The EPA is extending the
flaring allowance based on the ability of an owner or operator to
access their flaring event site and resolve the cause of the need to
flare. As noted previously, while weather can be a contributing factor
affecting access to a site, it is not the only potential reason
limiting access to a site. As such, the EPA has extended the allowance
to flare up to 72 hours in absence of an exigent circumstance and
allows more than 72 hours in instances where an owner or operator makes
a legitimate exigent circumstance claim that limits their ability to
access and resolve the cause for a flaring event within 72 hours. This
extended timeframe gives owners and operators enough time to travel to
facilities (including geographically remote facilities), troubleshoot,
obtain necessary equipment, and complete repairs. It also provides
sufficient time to overcome many inclement weather situations. This
extended timeframe, coupled with the ability to claim exigent
circumstances for even more time, should limit or eliminate the need to
shut-in operations in situations of temporary flaring for malfunction,
safety, or maintenance.
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\71\ Document ID No. EPA-HQ-OAR-2024-0358-0096.
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Additionally, the Temporary Flaring Survey shows regional variation
in flaring durations, as a commenter notes. For instance, 78 percent of
flaring incidents in the Williston Basin exceeded 72 hours, compared to
just 11 percent in the Permian Basin. This variation highlights that a
rigid one-size-fits-all approach based exclusively on national
averages, and which does not allow for any flexibility, does not
account for critical differences in field conditions, wellsite
uniqueness, or operational complexity. The data confirm that events
where flaring exceeds 24 hours often continue well beyond 72 hours. As
such, setting the upper limit at 72 hours with the possibility of
additional time for exigent circumstances better aligns with field
data, while still placing expectations on owners and operators to
promptly resolve issues.
As explained in sections IV.A.4 (Support for a 24-hour Allowance
for Temporary Flaring) and IV.A.5 (Consideration of Additional
[[Page 18070]]
Limitations and Targeted Exceptions to Temporary Flaring) of this
preamble, the EPA considered but did not adopt several approaches
raised by petitioners and public comments on the proposal, including a
24-hour or 48-hour flaring allowance and additional temporary flaring
limits or targeted geographical exceptions.
3. Recordkeeping and Reporting
In the proposed rule, the EPA also solicited comment on the
recordkeeping and reporting requirements if the Agency were to include
an allowance for owners or operators of associated gas affected
facilities to route to a flare or control device for up to 72 hours for
``exigent circumstances.'' \72\ The topics of exigent circumstances and
temporary flaring duration are discussed more in section IV.A.1 and
IV.A.2 of this preamble respectively. Specifically, we solicited
comment on requiring an owner or operator who must make use of the
extended timeframe to maintain records that include a written
description of the exigent circumstance, the rationale for the need to
route to a flare or control device beyond the default allowable
timeline, a description of the measures taken to minimize temporary
flaring/routing to a control device, and the duration of temporary
flaring/routing to a control device due to the identified exigent
circumstance. Lastly, we solicited comment on requiring an owner or
operator to include a summary of their exigent circumstance recorded
events in their annual report.
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\72\ 90 FR 3740-41 (January 15, 2025).
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The EPA received two groups of comments about recordkeeping and
reporting requirements for exigent circumstances. Support for
recordkeeping and reporting came from environmental groups, who argued
that these requirements are important for accountability, ensuring the
flaring event was an appropriate action, and encouraging owners and
operators to limit flare durations. Industry commenters opposed this
proposed requirement. They argued that extending recordkeeping and
reporting requirements for exigent circumstances would not provide any
environmental benefit and would not expedite the repair or maintenance
process. Industry commenters further asserted that having additional
recordkeeping and reporting provisions would add unnecessary burden to
owners and operators at a time when they should prioritize resources to
address the emergency or maintenance event.
Based on comments received and EPA's decision to broaden what
constitutes an ``exigent circumstance'' to include instances where the
necessary equipment and/or personnel are not available to conduct the
necessary repairs for reasons beyond an owner's or operator's control,
the EPA is finalizing the following recordkeeping and reporting
requirements when an exigent circumstance is invoked: a written
description of the ``exigent circumstance'' requiring the need to flare
or route to a control device beyond 72 hours; a description of the
steps taken to resolve the need for temporary flaring/routing to a
control device; the dates and times an identified ``exigent
circumstance'' started and ended (e.g., when owners or operators are
able to access site, when personnel and/or equipment are available) and
the total duration of each ``exigent circumstance''; and the dates and
times temporary flaring/routing to a control device started and ended
and the total duration of temporary flaring/routing to a control device
due to the identified ``exigent circumstance.'' We require owners and
operators to report this information in their annual report. See
section IV.A.1 of this preamble for comments received on exigent
circumstances and EPA's response to those comments.
As mentioned above, we received several comments on this aspect of
the January 2025 Proposal. These comments and the EPA responses are
provided in this section of the preamble.
Comment: Several industry commenters did not support the EPA
requiring records and reporting (in annual reports) of information
regarding exigent circumstances necessitating temporary flaring beyond
the default time allowance. One commenter \73\ stated that operators
should focus on resolving emergencies and/or maintenance issues that
arise to reduce and/or remove the need to flare, instead of
recordkeeping and reporting requirements that provide no environmental
benefit.\74\ Additionally, according to the commenter, such
recordkeeping and reporting causes burden for the operator and the EPA.
The commenter requested that the EPA implement a blanket timeframe of
at least 72 hours for temporary flaring without the need for
recordkeeping and reporting such events.
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\74\ Document ID No. EPA-HQ-OAR-2024-0358-0095.
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Similarly, one commenter \75\ noted that the additional
administrative recordkeeping and reporting burden to conduct, document,
and report an exigent circumstance would not provide a corresponding
environmental benefit.\76\ The commenter stated that the NSPS OOOOb and
EG OOOOc rules already require recordkeeping and reporting for
temporary flaring events that are sufficient to provide transparency
into operators' temporary associated gas flaring activities.
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\76\ Document ID No. EPA-HQ-OAR-2024-0358-0092.
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Another commenter expressed concern about the documentation
required for exigent circumstances, stating that it is unnecessary and
unduly burdensome as a blanket 72-hour allowance is warranted.\77\
---------------------------------------------------------------------------
\77\ Document ID No. EPA-HQ-OAR-2024-0358-0088.
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Conversely, another commenter expressed that if the EPA finalizes a
nationwide exception for exigent circumstances, then the EPA must add
specific recordkeeping and reporting requirements to the rule.\78\ The
commenter supported the recordkeeping and reporting that the EPA listed
in the proposal as a minimum requirement to document and justify any
temporary flaring or routing to control devices that goes beyond the
baseline limit. The commenter asked that this documentation include a
description of the circumstance requiring extended flaring, the
rationale for routing to a flare or control device beyond the allowed
limit, documentation from public information that supports the claim
that extended flaring was necessary (e.g., traffic information showing
road closures), a description of the measures taken to minimize
temporary flaring, and the duration of temporary flaring. Also, the
commenter requested that the annual report require a summary of the
number, cause, and duration of extended flaring events.
---------------------------------------------------------------------------
\78\ Document ID No. EPA-HQ-OAR-2024-0358-0096.
---------------------------------------------------------------------------
Response: The EPA agrees that the near-term focus of owners and
operators in these situations should be on the immediate need of
resolving emergencies and/or maintenance issues as quickly as possible
to mitigate the need to flare. However, we disagree that recordkeeping
and reporting is unnecessary and that any such requirements will cause
undue burden to the owners and operators. First, base-level
recordkeeping and reporting requirements already exist for owners and
operators in the regulations (40 CFR 60.5420b(b)(4)(i) and (2) and
(c)(3) (i) and (ii); and 40 CFR 60.5420c(b)(3)(i) and (ii) and
(c)(2)(i) and (ii)) for all temporary flaring that are not at issue in
this rulemaking. Including exigent circumstance recordkeeping and
[[Page 18071]]
reporting only adds additional requirements when an exigent
circumstance occurs. Thus, if the exigent circumstance provision is not
invoked, owners and operators are not required to complete any
additional recordkeeping and reporting beyond the base-level
requirements for all temporary flaring situations. The additional
information that we will collect for exigent circumstances does not
duplicate the base-level recordkeeping requirements included in the
March 2024 Final Rule and is not time-consuming or resource intensive.
Second, requiring additional recordkeeping and reporting for
exigent circumstances documents compliance with the allowance for
temporary flaring beyond 72 hours for exigent circumstances.
Specifically, the additional recordkeeping and reporting requirements
only apply when an owner or operator invokes an extension of flaring
duration due to an exigent circumstance and only includes minimal
documentation to ensure that owners and operators are properly invoking
and implementing the flaring extension.
Lastly, in response to comments that claim that owners and
operators should first focus on returning the site to normal
operations, the EPA agrees. The recordkeeping requirements included in
the final amendments can be completed after the owner or operator
addresses the underlying issue that gave rise to the need for temporary
flaring. None of the recordkeeping requirements mandate action
contemporaneous with conducting repair or maintenance. The
recordkeeping can occur after repair or maintenance but should happen
relatively close in time so that the owner or operator can record
accurate information.
4. Support for a 24-Hour Allowance for Temporary Flaring
Following the January 2025 Proposal, several industry
representatives and State agency commenters recommended extending the
temporary flaring allowance to 72 hours. In contrast, other commenters,
including environmental organizations and private citizens, urged the
EPA to retain the original 24-hour limit from the March 2024 Final
Rule, with limited allowances for extensions up to 48 hours in exigent
circumstances or until the event is resolved. As part of the proposed
rule, the EPA requested data and feedback on whether the revised
flaring duration could potentially increase primary or secondary
emissions and invited additional information to either substantiate the
proposed 48-hour allowance or justify maintaining the 24-hour duration
in the March 2024 Final Rule.
The EPA received several comments on this aspect of the January
2025 Proposal. These comments and the EPA's responses are provided in
this section of the preamble.
Comment: Two commenters requested that the EPA retain the 24-hour
allowance for temporary flaring.\79\ One commenter disagreed with the
EPA's determination that the information provided in the Temporary
Flaring Survey supports allowing temporary flaring for up to 48 hours
during malfunctions but believes the information provided in the
Temporary Flaring Survey supports retaining the 24-hour allowance,
potentially with limited exceptions.\80\ The commenter agreed with the
EPA's statement that the Temporary Flaring Survey supports an
expectation ``that owners and operators can feasibly limit temporary
flaring to less than 24 hours in a large majority of situations.'' \81\
The commenter stated that the Temporary Flaring Survey had 2,804
instances of temporary flaring of associated gas at sites in the San
Joaquin, Permian, and Williston Basins.\82\ According to the U.S.
Energy Information Administration (EIA), the primary producers of
associated gas in the U.S. are the Permian, Bakken, Eagle Ford,
Anadarko, and Niobrara Basins.\83\ The commenter observed that the
Temporary Flaring Survey did not include any information on temporary
flaring in the other three basins identified by the EIA. For the EPA to
justify a nationwide change, the commenter contended that the agency
should examine data from all basins where associated gas is primarily
produced (and thus has the greatest potential for a need to temporarily
route to a flare or control device) to determine whether the current
allowance of 24 hours is appropriate. According to the commenter, the
Temporary Flaring Survey does not support the EPA's proposed change to
allow up to 48 hours for temporary flaring of associated gas, and data
from other basins may also further demonstrate this change is not
justified. The commenter asserted that the Temporary Flaring Survey
therefore is not complete enough to justify an alteration of the
standard for the entire country.
---------------------------------------------------------------------------
\79\ Document ID Nos. EPA-HQ-OAR-2024-0358-0080, EPA-HQ-OAR-
2024-0358-0096.
\80\ Document ID No. EPA-HQ-OAR-2024-0358-0096.
\81\ 90 FR at 3740 (January 15, 2025).
\82\ See API, Document ID. No. EPA-HQ-OAR-2024-0358-003,
attachment 3.
\83\ U.S. EIA, ``U.S. associated gas production increased nearly
8% in 2023.'' November 13, 2024. https://www.eia.gov/todayinenergy/detail.php?id=63704#.
---------------------------------------------------------------------------
Additionally, the commenter stated that an analysis of the
Temporary Flaring Survey shows the average duration of temporary
flaring of associated gas is 46 hours, which the EPA used as the basis
for its proposal. However, they reported that a detailed examination of
this data does not support a blanket allowance of 48 hours.\84\ The
commenter noted that most of the data come from the Permian Basin
(2,581, or 92 percent) and show that the average duration of temporary
flaring was 26 hours, with 318 instances requiring greater than 24
hours (12 percent of the total instances for this basin). Nearly 75
percent of the instances (1,930) are labeled as ``high priority,'' and
the average duration of temporary flaring for these events was five
hours, with only 14 instances greater than 24 hours (0.7 percent). In
the commenter's opinion, this demonstrates that operators can address
issues, such as maintenance and safety concerns, leading to temporary
flaring well within the currently allowed 24-hour duration for sites in
the Permian Basin.
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\84\ See Attachments A and B of the commenter's letter.
---------------------------------------------------------------------------
The commenter further observed that the 46-hour average duration in
the Temporary Flaring Survey is skewed by data from the Williston
Basin, representing only 166 total instances, or just six percent, of
the Temporary Flaring Survey data. The commenter reported that the
average duration of temporary flaring for these instances is 378 hours.
Additional details provided by Hess, and within the Temporary Flaring
Survey data, show that separator backpressure valve issues dominate as
the cause of temporary flaring (89 percent of instances for the
Williston Basin), and inclement weather is only listed as an issue for
10 instances, which have an average duration of 125 hours for temporary
flaring. The commenter provided that additional information from Hess
specifies these backpressure valve issues are unscheduled maintenance
or malfunctions due to separator backpressure valve issues, but it is
not clear whether these issues are preventable. The commenter asserted
that this outlier data for the Willison Basin does not justify a
blanket 48-hour nationwide allowance.
The commenter also noted that the Temporary Flaring Survey includes
a total of 57 instances from the San Joaquin Basin, which is not one of
the
[[Page 18072]]
primary producers of associated gas. Moreover, the commenter indicated
that the data for this basin demonstrate an ability to return to normal
operations (i.e., stop flaring of associated gas) after eight hours on
average, with only four instances requiring more than 24 hours. The
commenter pointed out that of those four instances exceeding 24 hours,
three are labeled as ``high priority'' and the cause is listed as power
failure (two instances), compressor failure (one instance), and valve
failure (one instance). While these limited exceptions do exist, the
commenter suggested that the overall data from the San Joaquin Basin
further support the position that the EPA should retain the 24-hour
allowance.
Also, the commenter evaluated data from New Mexico exploration and
production operators, which the commenter claimed demonstrate that
operators can comply with a 24-hour limit on temporary flaring during
malfunctions or incidents that endanger the safety of operator
personnel or the public, as well as during repair and maintenance
activities.
The commenter argued that New Mexico requires exploration and
production operators (``upstream operators'') to report flaring or
venting of natural gas on form C-129 ``that exceeds 50 thousand cubic
feet (MCF) in volume and either results from an emergency or
malfunction, or lasts eight hours or more cumulatively within any 24-
hour period from a single event.'' \85\ The report must include the
time of venting or flaring and the nature and cause of the venting or
flaring.\86\
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\85\ N.M. Admin. Code Section 19.15.27.8.G.(1)(a).
\86\ Id. at Section 19.15.27.8.G.(1)(b).
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The commenter evaluated all C-129 reports filed with the New Mexico
Oil Conservation Commission (OCC) between 2021 and 2025.\87\ The
commenter reported that the database contains reports filed by upstream
and midstream operators. According to the commenter, of all the causes
listed, 13 were identified that could be classified as a malfunction or
incident that could endanger the safety of operator personnel or the
public or as occurring during a repair or maintenance activities. The
commenter listed in their comment letter the various causes for these
events, including corrosion, downhole well maintenance, equipment
failure, freeze, human error, lightning, liquids unloading, overflow-
tank, pit, packer leakage test, power failure, repair and maintenance,
production test, and commissioning to purge.
---------------------------------------------------------------------------
\87\ See Attachments C and D of the commenter's letter for the
Excel workbooks that include their analysis.
---------------------------------------------------------------------------
In its analysis of the New Mexico OCC dataset, the commenter stated
that 99.7 percent of the total reported flaring incidents lasted 24
hours or less. According to the commenter, this data demonstrates that
operators can comply with a 24-hour limit on flaring during
malfunctions or incidents that endanger the safety of operator
personnel or the public and also during repair and maintenance
activities.\88\
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\88\ See Attachments C and D of the commenter's letter for the
Excel workbooks that include their analysis.
---------------------------------------------------------------------------
Another commenter contended that the EPA's proposal to extend the
temporary flaring allowance from 24 to 48 hours and include exigent
circumstances to allow flaring up to 72 hours is a massive step in the
wrong direction. The commenter contended that this policy, while trying
to meet the demands of a changing industry, critically ignores the
health and environmental implications that the commenter attributed to
flaring. The commenter stated that instead of responding to concerns
raised by oil and gas companies, thereby allowing what the commenter
described as further damage to health and safety, there should be more
focus on stricter regulations that veer toward alternative modes of
energy production.
Response: For the reasons explained here, the EPA found comments
suggesting that the EPA should retain the 24-hour allowance for
temporary flaring of associated gas for malfunction, including for
reasons of safety, and during all repairs and maintenance finalized in
the March 2024 Final Rule to be unpersuasive.\89\
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\89\ With respect to the portion of the comments suggesting that
the EPA should ``veer toward alternative modes of energy
production,'' the Agency first notes that such comments are out of
scope for this action which concerns limited technical amendments to
the temporary flaring provisions for associated gas and to NHV.
Moreover, basing a regulation under Clean Air Act section 111 on a
shift to ``alternative modes of energy production'' does not comport
with caselaw. See West Virginia v. EPA, 597 U.S. 697 (2022).
---------------------------------------------------------------------------
In finalizing the required timeframe for this provision, the EPA
considered additional factors beyond the average flaring duration
proposed in the January 2025 Proposal due to variabilities that exist
in the industry at large.
Some commenters appear to suggest that a strict 24-hour limit on
temporary flaring is warranted based on the claim that most events in
the Temporary Flaring Survey, particularly in the Permian Basin, are
resolved within that timeframe. However, this narrow interpretation of
the data, when considered in the context of setting a national
standard, ignores critical realities demonstrated across the full
dataset and operational field conditions. First, while the Permian
Basin represents a large portion of the data, flaring behavior and
operational challenges do not appear to be uniform across the
representative basins. Other regions, particularly the Williston Basin,
face significantly harsher environmental conditions and logistical
barriers that are not captured by simply focusing on Permian Basin
averages. Commenters argue that because one region generally operates
under favorable conditions, all other regions should be held to the
same standard, an approach that is neither practical nor technically
sound.
Additionally, commenters rely on averages without giving proper
weight to variability. The same dataset across all responses shows that
17 percent of flaring events lasted longer than 24 hours, and 15
percent lasted longer than 72 hours--a meaningful minority that cannot
simply be ignored. Averages can hide important outliers that matter
operationally. For instance, the high standard deviation of 156 hours
across the full dataset demonstrates that flaring durations vary
dramatically and treating all events as if they should conform to an
average disregards the complex, often unpredictable nature of these
unique situations that may result in routing associated gas.
Emergencies, severe weather, and mechanical failures in remote,
unmanned sites frequently require more than 24 hours to troubleshoot,
repair, and safely restore operations.
The EPA also disagrees with the claim that the datasets and other
information available to the Agency are too limited to support a
nationwide 72-hour flaring allowance. While the Temporary Flaring
Survey does not include every basin, it contains 2,804 flaring events
from several major oil and natural gas producing regions, providing a
meaningful sample of real-world operations. Events exceeding both 24
and 72 hours occurred across different categories. For example, in the
``Other--specify'' category of the Temporary Flaring Survey, gas sales
line freezing led o flaring durations as high as 117 hours, power
outages resulted in delays up to 48 hours, and high hydrogen sulfide
(H2S) levels forced compressor shutdowns lasting 29 hours.
In the C-129 reports filed with the New Mexico OCC that the commenter
evaluated, while these events represent a small portion of the more
than 28,000 total upstream incidents examined, there were still 127
flaring incidents lasting more than 24 hours and 103 incidents
[[Page 18073]]
lasting more than 72 hours during repair and maintenance activities.
So, even the data from New Mexico shows that 24, or even 48, hours is
not sufficient time in some instances. These examples show that
extended flaring durations can result from malfunction or safety
related issues that are not tied to any single region.
A national default limit of 72 hours is straightforward in terms of
compliance, especially for operators who work in more than one basin.
It gives enough time to fix most issues without needing to claim an
exigent circumstance. It also avoids subjecting sources across
different regions to unequal treatment, as well as avoiding situations
where sources are subject to the conditions discussed above that may
contribute to longer flaring incidents but are captured in the existing
record or analysis. Such sources could be existing sources or new
sources, and a nationwide standard for new sources obviated the need to
continually analyze and adjust regional-based considerations. For rare
cases that go beyond 72 hours, the rule allows limited flexibility as
addressed in section IV.A.1 of this preamble. And, as discussed
previously, the EPA is also requiring flaring to cease when the
incident triggering flaring has been resolved, which serves as a
protective backstop to reduce emissions notwithstanding the 72 hour
allowance. We expect that incidents that previously have been resolved
within 24 or 48 hours would continue to be resolved as quickly as
practicable and that flaring would cease when the issue is resolved.
The EPA does not dispute the general idea that the data available
to the Agency in this rulemaking docket demonstrate that many instances
of temporary flaring of associated gas are resolved, with the site
returning to normal operations, within 24 hours. However, we view this
information within the context that these instances mostly occurred at
sites that were not subject to 2024 final rule NSPS 24-hour limit at
the time of the data collection. As such, owner and operators were
already responding quickly to address repair, maintenance, and safety
issues and returning their sites to normal operations (ceasing flaring)
due to considerations outside the NSPS and EG. We have no reason to
believe that those other considerations, whatever they may be (e.g.,
State or local laws/regulations economic incentives to restore flow to
sales lines), would vanish upon finalizing the amendments to increase
the NSPS and EG timeline to 72 hours. We also have no reason to predict
that allowing up to 72 hours, or more with exigent circumstances, in
the NSPS and EG will result in owners and operators always taking up to
72 hours to return their sites to normal operations. It is reasonable
to assume that if owners and operators were addressing these issues
quickly before the NSPS, they will continue to do so after these
amendments. Seventy-two hours is a limit, not a minimum. The EPA's
regulations in no way interfere with the efforts of owners and
operators to address problems as quickly as possible. In fact, the
final regulations clarify that temporary flaring must stop when the
issue giving rise to the need to flare has been resolved. The
requirement only allows flaring for the duration of time necessary to
return the site to normal operations. If that is accomplished in eight
hours instead of 72, then the rule does not allow, let alone require,
flaring for 72 hours.
The EPA finds that certain commenters overestimate the potential
environmental consequences of revising the 24-hour requirement to a 72-
hour requirement. If the regulations provide owners and operators with
no options aside from shutting-in operations if repairs are incomplete
after 24-hours, these circumstances may lead to depressurizing
equipment directly to the atmosphere (i.e., venting). A shut-in occurs
when an owner or operator temporarily closes the valves on an oil or
gas well to stop the flow of hydrocarbons, often for maintenance,
safety, equipment issues, or economic issues. The act of restarting the
well after a shut-in can result in significant emissions due to
pressure buildup while the well was shut-in, as owners and operators
perform blowdown operations to release pressure from the well, often
resulting in significant releases of methane and other harmful
emissions.
Venting in these situations may release far more harmful emissions
than controlled flaring would over an additional 24 to 48 hours. Thus,
a rigid 24-hour limit, when compared to what is being finalized, could
result in marginally greater pollution, not less, undermining the EPA's
emission reduction goals. Further, in accordance with 40 CFR
60.5377b(d), emissions from flares and ECD are to be controlled at 95
percent reduction efficiency (see also 40 CFR 60.5391c(b) within the
model rule for the EG). While the change from 24 hours to 72 hours for
flaring in these situations, and longer for exigent circumstances, can
theoretically allow more flaring by total duration, the natural gas
being routed to a flare during this time is still being controlled at a
95 percent reduction efficiency. And as noted above, any increase in
emissions from flaring is speculative given the backstop requirement
that flaring must cease as soon as the underlying issue is resolved.
Finally, while one commenter dismissed data from the Williston
Basin as ``outliers,'' this overlooks the fact that the data from the
Williston Basin represent real operating conditions faced by numerous
facilities.\90\ The fact that the sample size from the Williston Basin
is smaller does not mean that the issues operators face there are less
legitimate. The EPA believes that utilizing a regulatory framework that
fails to accommodate areas with severe climates and operational
challenges would penalize responsible owners and operators working in
these difficult environments. The information presented to the EPA
clearly indicates that in some instances--and more than just a few
outliers--owners and operators credibly require more than 24 hours to
temporarily flare before they can resolve the problem and return the
site to normal operations. It is not appropriate for the EPA to
establish a rigid and universal, nation-wide, requirement that the
Agency has credible reason to believe cannot be met. Allowing up to 72
hours for most situations, and providing a mechanism to go beyond 72
hours, will allow owners and operators the time they need while also
ensuring that temporary flaring does not continue indefinitely or
unchecked. To use an example from one commenter, flaring for 378 hours
due to a separator backpressure valve issue where the site is
accessible would not be in compliance with the finalized amendments. We
believe that a fair and reasonable standard should reflect the full
diversity of U.S. oil and natural gas operations. A flexible allowance
permitting up to 72 hours of flaring under these circumstances is both
more practical and environmentally responsible.
---------------------------------------------------------------------------
\90\ Document ID No. EPA-HQ-OAR-2024-0358-0096.
---------------------------------------------------------------------------
5. Consideration of Additional Limitations and Targeted Exceptions to
Temporary Flaring
In response to the January 2025 Proposal to extend the allowable
duration for flaring associated gas from 24 to 48 hours under certain
situations, commenters also raised two distinct but related issues. The
first is whether there should be a clear cutoff for flaring within the
48-hour period. Some commenters advocated for a more restrictive
application of the proposed 48-hour allowance by recommending that the
EPA adopt an additional cutoff
[[Page 18074]]
mechanism. They requested that the EPA require owners and operators to
stop flaring as soon as the repair, maintenance, or safety issue is
resolved, even if that happens before the end of the 48-hour period.
They argued that this was needed to avoid extra flaring that serves no
technical purpose. For example, if a repair is done after 8 hours, the
commenter asserts flaring should not continue for the full allowed
temporary flaring duration. The commenter requested that the EPA
clearly state that flaring must stop when the cause of the disruption
is resolved.
Second, a separate set of comments urged the EPA to consider
geographical targeted exemptions (i.e., to explore whether exemptions
to the flaring limit should apply only in certain geographic areas such
as specific basins). These commenters argued that the EPA should not
apply the proposed 48-hour flaring allowance across the country.
Instead, they suggested that the Agency consider basin-specific
exemptions where data shows they are needed. The commenters pointed to
past EPA rules that have allowed for regional differences. For example,
the EPA has given exemptions for Alaska North Slope facilities due to
cold weather conditions. In this case, the commenter referred to the
Temporary Flaring Survey data from the Williston Basin and said it does
not support a nationwide change to the flaring limit. They further
asserted that any extended flaring allowance based on that data should
apply only in the Williston Basin.
These comments suggest that a blanket 48-hour allowance may not be
the best fit for all situations. These comments and the EPA's responses
are provided in sections IV.A.5.a and IV.A.5.b of this preamble.
a. Additional Cutoff To Limit Temporary Flaring
Comment: One commenter requested that, if the EPA finalizes the 48-
hour allowance as proposed, the EPA explicitly include an additional
cutoff for the stated allowed duration to ensure the temporary flaring
or routing to control devices ceases as soon as the malfunction is
resolved, including for reasons of safety, repair, or maintenance.\91\
The commenter contended that it is necessary for the EPA to
specifically put restrictions on the duration to require operators to
stop temporary flaring when repairs or maintenance are completed, thus
avoiding continued flaring longer than necessary during each incident.
For example, the commenter stated that if a repair or maintenance is
completed within eight hours of the need to temporarily flare
associated gas, then the flaring of associated gas should be limited to
eight hours, not a full 24 hours as allowed in the March 2024 Final
Rule. The commenter recommended regulatory text changes to 40 CFR
60.5377b(d)(1) and (2) and 40 CFR 60.5391c(c)(1) and (2) placing a
cutoff for temporary flaring to end as soon as the malfunction, safety
concern, or maintenance repair is resolved, if it did not require the
full 24 hours allowed in the March 2024 Final Rule.
---------------------------------------------------------------------------
\91\ Document ID No. EPA-HQ-OAR-2024-0358-0096.
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Additionally, the commenter stated that their recommendations are
consistent with other requirements in NSPS OOOOb and EG OOOOc, which
place an upper limit on how long provisions for certain extenuating
circumstances may apply before the baseline requirements once again
take effect, including the allowance of temporary flaring until gas
composition meets specifications or up to 72 hours, whichever is less
(40 CFR 60.5377b(d)(4)); delayed repair of centrifugal compressors (40
CFR 60.5380b(a)(8)(i)), reciprocating compressors (40 CFR
60.5385b(a)(3)(i)), fugitive emissions components until the next
scheduled shutdown or up to two years (40 CFR 60.5397b(h)(3)(i)),
whichever is earliest; repairs of pressure relief devices at gas plants
the next time monitoring personnel are onsite or within 30 days,
whichever is sooner (40 CFR 60.5400b(d)(2)). The commenter supported
this additional cutoff to ensure that temporary flaring is limited as
much as possible.
Response: The EPA agrees with the commenter's recommendation that
the finalized time for temporary flaring allowance of associated gas
should operate as a maximum timeframe. Temporary flaring or routing of
associated gas to control devices should end as soon as the
malfunction, maintenance, or safety issue is resolved. The EPA's intent
with the provisions for temporary flaring of associated gas is to allow
necessary flexibility to manage equipment issues or emergencies, while
limiting emissions to those which are associated with actions that are
required to fix the problem. This approach will encourage owners and
operators to limit flaring to the time necessary.
The EPA agrees that there is clear precedent for this type of
backstop. The March 2024 Final Rule already includes a maximum time
limit of 24 hours for temporary flaring to prevent avoidable emissions
during operational disruptions.\92\ Adding a requirement that flaring
must cease when the issue is resolved builds on this principle.
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\92\ (Docket ID: EPA-HQ-OAR-2021-0317) Preamble, Table 17--
Situations and Durations Where Associated Gas May Temporarily be
Routed to a Flare or Control Device.
---------------------------------------------------------------------------
The monthly and annual datasets provided by industry stakeholders
show wide variation in flaring durations. The average flaring duration
across all responses was 46 hours, but the median was four hours. This
gap suggests that while some events last longer, most can be resolved
much sooner. In particular, several months showed high percentages of
events exceeding 24 and even 72 hours--up to 34 percent and 32 percent,
respectively, in January. But in other months, most events were short,
with medians below five hours. These numbers support the idea that many
events can be resolved well before the maximum time is reached and that
a cutoff based on when the issue is fixed would reduce emissions
without affecting needed flexibility. Further, in the Temporary Flaring
Survey, the Williston Basin data shows that the causes of temporary
flaring vary, including equipment failures like compressor shutdowns,
frozen gas lines, and power outages. We believe these events do not all
require the same response time. Some events can be resolved in under 10
hours. Implementing requirements to end flaring once the cause is
addressed will limit emissions to what is necessary for safe and
reliable operations. Industry stakeholders have repeatedly stated that
owners and operators are already taking steps to reduce flaring times
and that a 72-hour allowance would promote planning and operational
changes to further reduce emissions.\93\ The EPA concludes that a
backstop limit and a requirement to stop flaring when the issue is
resolved can work together to maintain the Agency's objectives while
allowing industry to respond to operational needs in an efficient and
timely manner.
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\93\ Document ID No. EPA-HQ-OAR-2024-0358-0044.
---------------------------------------------------------------------------
b. Alternative Exemptions (e.g., Basin-Specific)
Comment: One commenter suggested that the EPA consider adopting
basin-specific exemptions from the temporary flaring provisions rather
than extending the temporary flaring allowance beyond 24 hours for all
wells nationwide.\94\ The commenter acknowledged, however, that the
current record does not support basin-specific exemptions. In
particular,
[[Page 18075]]
the commenter recommended that the EPA consider which limited
exceptions to the 24-hour duration allowance are warranted and specify
an appropriate allowance for temporary flaring or routing to control
based on data that supports that exception. According to the commenter,
the EPA has historically provided location-specific exceptions in its
oil and gas standards that account for the unique circumstances those
owners and operators face. The commenter referred to a statement the
EPA made: ``the information provided by petitioners is persuasive in
demonstrating that a blanket 24-hour limit on temporary flaring can
pose compliance challenges for certain owners and operators.'' \95\
---------------------------------------------------------------------------
\94\ Document ID No. EPA-HQ-OAR-2024-0358-0096.
\95\ 90 FR 3740 (January 5, 2025).
---------------------------------------------------------------------------
The commenter summarized key observations from the 166 instances
that the Temporary Flaring Survey API provided for temporary flaring of
associated gas in the Williston Basin (see page nine of commenter's
letter) and concluded that the Williston Basin data provides
insufficient evidence to provide a blanket nationwide exemption. The
commenter further expressed that though their position is that the data
are insufficiently clear to warrant adjusting the March 2024 Final Rule
at this time, any change in the duration of the temporary flaring
allowance based on the Williston Basin data should be limited to that
basin. The commenter noted that the EPA took similar actions on limited
exceptions for fugitive emissions monitoring requirements and process
controllers on the Alaska North Slope, citing concerns about the
technical feasibility of conducting monitoring when temperatures are
below the operating envelope of the monitoring technologies, and the
EPA noted ``there is no assurance that the initial and semiannual
monitoring that must occur during that period of time are technically
feasible.'' \96\
---------------------------------------------------------------------------
\96\ 83 FR 10628, 10632 (March 12, 2018).
---------------------------------------------------------------------------
Regarding process controllers, the commenter highlighted that the
EPA provided two standards for sites in Alaska in the March 2024 Final
Rule: zero emissions for all process controllers at sites with access
to electrical power, and the use of process controllers with low
emission rates at sites with no access to electrical power (40 CFR
60.5390b(b)). Instead of the blanket move to allow 48 hours for
temporary flaring as proposed nationwide, the commenter reiterated that
any changes to the duration allowance for temporary flaring based on
the Williston Basin data should be limited to the Williston Basin and
based on a demonstrated need in the basin.
Response: Regarding the comment requesting that the EPA consider
adopting basin-specific exemptions from the temporary flaring
provisions rather than extending the temporary flaring allowance beyond
24 hours for all wells nationwide, the EPA acknowledges that we have
historically allowed some location-specific variations in oil and gas
standards to reflect operational challenges that are unique to certain
geographic regions. However, we do not find that such an approach is
necessary or supported by the current data for this rule. In the March
2024 Final Rule, the Alaska-specific provisions cited by the commenter
were granted because of distinct technical challenges related to that
region (i.e., controllers without electric power and uniqueness of
large compressors different from those in the lower 48 States \97\).
For example, we took a different approach for process controllers in
Alaska at sites without reliable access to power.\98\ This was in part
due to Alaska's northern latitude, where long periods of darkness
during winter reduce the ability of solar panels to generate
electricity. That situation presented a clear, location-specific
operational barrier that justified a different standard for certain
sources. The examples presented by the commenter both involve
subcategorization that resulted in different standards for different
sources. The differences there were meaningful enough to justify
different treatment. However, here, the differences are not as
pronounced or meaningful, and the different treatment that commenters
advocate for is only in regard to a limited variation provision that
comprises one piece of the larger applicable standard (these amendments
are not changing the substance of the NSPS standards or the EG
presumptive standards for associated gas).
---------------------------------------------------------------------------
\97\ The ``lower 48'' consists of the 48 adjoining U.S. States
and the District of Columbia of the U.S. The term excludes the only
two noncontiguous States, which are Alaska and Hawaii, and all other
offshore insular areas, such as the U.S. territories of American
Samoa, Guam, the Northern Mariana Islands, Puerto Rico, and the U.S.
Virgin Islands.
\98\ Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------
The circumstances described by the commenter and the data for the
Williston Basin and other regions do not meet the same threshold as the
examples that commenters cite and do not warrant the same outcome of
creating subcategories. The Temporary Flaring Survey shows that 17
percent of temporary flaring events across all reported basins lasted
longer than 24 hours, and 15 percent exceeded 72 hours. While these
numbers suggest some operational challenges, the data also show
significant variation across both the durations and underlying causes
of these flaring events. For instance, the monthly flaring dataset
shows that in many months, the median flaring duration was just four to
six hours, even though averages were higher due to outlier events. In
June and July, for example, the average flaring durations were 11 and
19 hours, respectively, with medians of four hours. This pattern
suggests that while extended events do occur, many are resolved within
a short timeframe, even in colder months. In the Williston Basin
dataset of the Temporary Flaring Survey, temporary flaring causes range
from compressor shutdowns and frozen gas lines to facility restarts and
power outages. These are operational issues that may occur across
multiple basins. The possibility of inclement weather as a contributing
factor to site inaccessibility is not unique to any one location. The
Temporary Flaring Survey shows that events flagged as ``[u]nknown''
accounted for a much higher average flaring duration (86 hours)
compared to events where the impact of weather was known to be present
(21 hours) or absent (36 hours). This inconsistency indicates that
factors beyond location such as the nature of the malfunction, site
accessibility, and access to equipment play a large role in extended
flaring durations.
Accordingly, we find that a single, flexible nationwide approach
with clear, uniform provisions for additional time is more appropriate,
equitable, and easier to implement than finalizing different maximum
flaring times for different geographic regions of the country. As some
commenters suggested, basin-specific timelines would likely introduce
unnecessary complexity into an already complex regulatory scheme, which
could result in enforcement and compliance inconsistencies. The
standards for associated gas are already subcategorized in the NSPS
based on when a new well commenced construction. (See Table 16 in the
March 2024 Final Rule).\99\ These amendments only address two of the
four scenarios for temporary flaring (see id. at Table 17). Further,
the presumptive standards in the EG model rule are also already
subcategorized on different terms than the NSPS (see id. at Table 4).
These temporary flaring provisions are only one piece of the regulatory
scheme for associated gas, and they do not relate to
[[Page 18076]]
the standards directly. Layering basin-specific variations on top of
this scheme for certain instances of temporary flaring, which generally
should not occur often, is too complex for little to no benefit when
considered in conjunction with the requirement that flaring must cease
when the issue giving rise to the need to temporary flare is resolved.
---------------------------------------------------------------------------
\99\ 89 FR 16887 (March 8, 2024).
---------------------------------------------------------------------------
Lastly, the record does not support the conclusion that any one
basin faces persistent technical barriers that would justify a regional
variation to the originally proposed 48-hour or finalized 72-hour
temporary flaring limit. Instead, we support an approach that allows
limited extensions under exigent circumstances, as discussed in section
IV.A.1 of this preamble, but maintains a consistent framework across
all basins. This ensures fairness, limits emissions, and encourages
continued operational innovation in the oil and gas industry.
B. Vent Gas NHV Continuous Monitoring Requirements and Alternative
Performance Test (Sampling Demonstration) Option for Flares and
Enclosed Combustion Devices
The March 2024 Final Rule requires owners and operators to perform
NHV sampling for flares and ECD through continuous monitoring of NHV or
through periodic testing with sampling demonstrations. As stated in the
January 2025 Proposal, industry petitioners stated in their
reconsideration petitions that the compliance demonstrations are
unnecessary, technically infeasible, and provide a limited timeline for
compliance. The petitioners argued that over 99 percent of historical
Btu stream data already complies with the prescribed minimum NHV
content values (depending on flare type) outlined in the March 2024
Final Rule. Industry petitioners asserted that NHV content is usually a
concern when inert gases are added to the process streams, which
typically occurs during scheduled situations and is known to the
operator of the affected source.
Based on information from these petitions, as well as further
information provided by industry, in the January 2025 Proposal the EPA
proposed changes to the continuous monitoring requirements and
alternative performance test options (sampling demonstration) of NHV
for flares and ECD. First, for the continuous monitoring requirement,
we proposed to expand the streams that are exempt from monitoring NHV
to include unassisted flares and ECD at new sources, and unassisted,
air-assisted, and steam-assisted flares and ECD at existing sources. We
also proposed to replace the general exemption from NHV monitoring for
associated gas for any control device used at ``well site affected
facilities'' with NHV monitoring that is more reflective of industry
operations. Additionally, we proposed to require NHV monitoring for
streams where inert gases were added and for operational scenarios
where NHV is known to decrease (e.g., nitrogen and acid gas removal,
glycol dehydration, etc.) in flares and ECD that are subject to the 200
or 300 Btu/scf minimum requirements. The EPA relied on data provided by
industry, which showed reduced NHV from the dilution of inlet streams
by effluent streams with known high content of inerts, such as those
from amine units or produced water tank streams. In the event of stream
dilution (for any reason), owners and operators would need to satisfy
more robust recordkeeping and reporting requirements. Second, for the
alternative performance test (sampling demonstration) requirements, we
proposed to allow breaks during weekends and holidays for the March
2024 Final Rule's consecutive 14-day sampling demonstration
requirements to account for reasonable operational pauses. We also
addressed ambiguity regarding the location of NHV grab sampling methods
by specifying in the January 2025 Proposal that samples should be taken
upstream of the control device, provided that the sample is
representative of the gas being introduced to the control device.
Finally, in the January 2025 Proposal the EPA clarified NHV testing
must be reported in volumetric units (Btu/scf) instead of specific
units (Btu/lb) in order to facilitate consistency in reporting.
The EPA received several comments on the proposed amendments
regarding the NHV continuous monitoring requirements and alternative
performance test (sampling demonstration) option for flares and ECD in
the January 2025 Proposal. Highlights of these comments and the EPA's
responses are provided, as well as discussion of changes from the
January 2025 Proposal as applicable. This preamble does not discuss the
EPA's response to any of those comments. The agency's responses are
available in the EPA's RTC document (Chapter 4) for the final
rule.\100\
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\100\ Reconsideration of Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review:
Response to Public Comments on the January 2025 Proposed Rule (90 FR
3734; January 15, 2025). See Docket No. EPA-HQ-OAR-2024-0358.
---------------------------------------------------------------------------
1. 60-Day Deadline
In the January 2025 Proposal, the EPA proposed to allow 60 days for
owners and operators to conduct the continuous NHV monitoring required
by one of the options in 40 CFR 60.5417b(d)(8)(ii)(A) through (D), if
the results of the periodic sampling (i.e., three samples every five
years) indicate that the NHV is less than 1.2 times the applicable
threshold NHV level in the rule. The EPA considers it necessary to
specify a timeframe to install and operate the required continuous
monitors to provide owners and operators with regulatory certainty for
when this must occur. We consider 60 days to be an expedited time
schedule for the installation of continuous monitoring systems, but we
also consider it a reasonable timeframe for installing the necessary
grab sampling systems to automatically collect samples at least once
every eight hours as provided in 40 CFR 60.5417b(d)(8)(ii)(D). The
proposal would require facilities to collect grab samples every eight
hours until such time that a continuous monitor can be installed, and
installation of such a system may require more than 60 days. We
requested comment on the proposed 60-day compliance provision when a
five-year sampling event indicates the vent stream is not sufficiently
above the required NHV.
Comment: One commenter supported the EPA's proposed 60-day deadline
to require continuous NHV monitoring after either a periodic sample or
a post-process change re-evaluation demonstrates the flare or ECD inlet
gas is below the applicable NHV limit.\101\ The commenter stated that
more deadlines are necessary to provide clear compliance obligations.
The commenter also suggested that where a post-NHV demonstration
periodic sample is below the applicable NHV limit, the operator must
commence continuous NHV monitoring or recomplete the NHV demonstration
within 60 days of receiving the analytical results. The commenter
suggested that the opportunity to recomplete the NHV demonstration
would account for the possibility of errors in sampling or analysis.
---------------------------------------------------------------------------
\101\ Document ID No. EPA-HQ-OAR-2024-0358-0088.
---------------------------------------------------------------------------
Response: The EPA received only supportive comments regarding the
proposed clarification of allowing 60 days for implementing the
continuous NHV monitoring required by one of the options in 40 CFR
60.5417b(d)(8)(ii)(A) through (D) if the results of the periodic
sampling (i.e., three samples every five years) indicate that the NHV
is less than
[[Page 18077]]
1.2 times the applicable threshold NHV level in the rule. Hence, we are
finalizing this particular provision as proposed. Owners and operators
could resolve any potential error in sampling or analysis by
implementing a continuous NHV monitor within the newly clarified 60-day
window.
Moreover, 40 CFR 60.5417b(d)(8)(iii)(E) and 40 CFR
60.5417c(d)(8)(iii)(E) requires that if process operations are revised
that could impact (i.e., lower) the NHV of the gas sent to the enclosed
combustion device or flare, such as the removal or addition of process
equipment, owners and operators must perform a re-evaluation of the NHV
of the gas stream. The EPA is clarifying that this re-evaluation must
be performed within 60 days of the process operations being revised, on
those enclosed combustion devices and flares subject to NHV testing.
2. Revisions to Inlet Gas Streams Exempt From Monitoring
Based on information provided by petitioners after the publication
of the March 2024 Final Rule regarding NHV characteristics of sample
streams, in the January 2025 Proposal the EPA proposed changes to the
March 2024 Final Rule that would expand the scope of the exclusion for
the NHV continuous monitoring requirements and alternative performance
test (sampling demonstration) option so that the following control
devices would not be required to make any such demonstration:
unassisted flares or ECDs at new sources; and unassisted, air-assisted,
or steam-assisted flares or ECDs at existing sources. New data
submitted in API and AXPC's joint petition for reconsideration dated
April 2024 demonstrated that, for over 22,000 NHV low-pressure (LP)
data points, 99.5 percent of those data points showed that the NHV was
at least 800 Btu/scf and more than 99.9 percent of those data points
showed that the NHV was at least 300 Btu/scf. Notably, these data were
consistent across different basins.\102\ Data supplied by GPA Midstream
in its July 2024 letter supported its prior petition submittals that
gas streams in the midstream consist of natural gas and field gas with
NHVs greater than 1,000 Btu/scf, with the exception of certain streams
in which inert gases or other known low-NHV streams were added.\103\
Because these new data further demonstrate that the NHV of the vent gas
is consistently well above the 200 or 300 Btu/scf vent gas requirements
for these control devices when inerts are not present, and because
there are no combustion zone or dilution parameters for these control
devices, the EPA proposed to determine that an expanded exclusion from
the monitoring requirements is appropriate.
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\102\ 99 percent of the data were from five basins: Permian,
Anadarko, Gulf Coast (Eagleford), Williston (Bakken), and Powder
River. See March 18, 2024, API/AXPC Slides in Docket ID No. EPA-HQ-
OAR-2024-0358.
\103\ Document ID No. EPA-HQ-OAR-2024-0358-0094.
---------------------------------------------------------------------------
In the January 2025 Proposal, the EPA did not propose to exclude
pressure-, steam-, or air-assisted flares or ECD from the NHV
compliance demonstration requirements for new sources. After the
January 2025 Proposal, based upon the EPA's solicitation for comment
for the sampling requirements for pressure-assisted flares and ECDs at
new and existing sources and for air- and steam-assisted flares or ECDs
at new sources,\104\ in April 2025 API supplemented its comment letter
with new high-pressure (HP) stream data (39,000 samples) from 11 basins
with over 99.5 percent of these data greater than 800 Btu/scf, which
was comparable to that of the LP NHVs previously analyzed in 2024.
Again, these were consistent across different basins.\105\ For the
combined data sets from April 2024 and April 2025, which consisted of
over 60,000 data points from both LP and HP gas streams, over 99.5
percent of the data showed NHV contents of at least 800 Btu/scf and
over 99.9 percent of the data showed NHV contents of at least 300 Btu/
scf.\106\ In this combined data set, over 99 percent of the data
samples from LP gas streams resulted in a NHV content of greater than
900 Btu/scf and over 95 percent of the data samples from HP gas streams
resulted in a NHV content of greater than 900 Btu/scf. Of particular
note, while less than 0.5 percent of the total samples yielded NHV
contents of 800 Btu/scf or less, these instances were from known
scenarios where inerts were added, namely vent gas streams from
nitrogen removal units (NRU), acid gas removal (AGR) system amine
regenerator still columns, glycol dehydrator unit reboilers without
water removal, compressors in acid gas service, or vent streams
containing water or CO2 used for EOR.
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\104\ 90 FR 3748 (January 15, 2025).
\105\ 97 percent of the data were from eight basins: Permian,
Anadarko, Gulf Coast (Eagleford), Williston (Bakken), Powder River,
East Texas, Appalachian, and Arkla (Haynsville). See April 2, 2025,
API Slides in Docket ID No. EPA-HQ-OAR-2024-0358.
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As demonstrated by the July 2024 GPA Midstream data set, the
addition of inert gases or streams from amine units or produced water
tanks can decrease the NHV content of the gas stream to the point that
the NHV thresholds for non-pressure-assisted flares or ECD may not be
achieved. In addition to sources of inert streams previously identified
in the March 2024 Final Rule (i.e., streams from compressors in acid
gas service and streams from EOR facilities), the July 2024 GPA
Midstream letter explained that other operating scenarios can result in
the addition of low-Btu streams into the vent gas stream, which lowers
the overall NHV for the vent stream.
Based upon the information and data provided after the publication
of both the March 2024 Final Rule and January 2025 Proposal, which
demonstrated that over 99.5 percent of the data (consisting of both LP
and HP sources) showed NHV contents of 800 Btu/scf or greater and over
99.9 percent of the data showed NHV contents of 300 Btu/scf or greater,
the EPA is expanding the streams that are exempt from monitoring due to
high NHV content to include all flare and ECD for both new and existing
sources.
We are finalizing that NHV sampling is only required for any new or
existing flare or ECD in cases where there are contributions from
inerts, and for other miscellaneous scenarios which decrease the NHV
content, using the continuous monitoring requirements and alternative
performance test (sampling demonstration) options currently prescribed
in the NSPS OOOOb and EG OOOOc rules and summarized in section III.B of
this preamble.\107\ The EPA expects that the operational scenarios
described in section IV.B.2.c. of this preamble can be easily validated
and documented through the physical presence (or absence) of process
equipment, process piping, engineering analysis, or process flow
diagrams in order to determine when the owner or operator should
monitor the NHV of the stream.
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\107\ See 40 CFR 60.5417b(d)(8) and 40 CFR 60.5417c(d)(8).
---------------------------------------------------------------------------
For example, in the case of the acid gas removal (AGR) system amine
regenerator still column vent gas, it would be easy to trace process
piping to determine whether the vent stream was routed to a dedicated
control device or was combined with affected facility vent gas streams.
Similarly, for the glycol dehydration unit reboiler vent gas, the lack
of a process condenser would indicate that higher water content (and
lower Btu) reboiler vent gas streams were combined with affected
facility vent gas streams. The use of nitrogen as
[[Page 18078]]
a blanket gas can be readily determined through the presence of
nitrogen storage, supply systems, and process piping. Finally, we
expect that storage tanks with water content high enough to depress
overall NHVs typically would not meet the applicability thresholds of
the rule and would not be combined with other vent streams routed to a
flare or ECD. However, when gas streams from produced water tanks are
vented to controls, vent lines from these tanks can be traced to
identify sources that require monitoring or sampling.
Since we proposed to remove the general monitoring exemption for
when the only inlet gas stream to the flare or ECD is associated gas
from a well affected facility, we also directly resolved one of the
issues raised in the May 2024 EIP et al. petition. We consider the data
submitted by the industry petitioners to support the proposed exclusion
from monitoring for flares and ECD subject to a vent gas NHV
requirement of 200 or 300 Btu/scf (and not subject to NHVcz
and NHVdil requirement) when no inerts are present because
the results were consistently much higher than these levels. The May
2024 EIP et al. petition also contended that the EPA did not support
its conclusion in the March 2024 Final Rule that initial assessments of
flares and other control devices, in lieu of continuous monitoring, can
capture the variability of NHV in the oil and gas sector. The EPA has
concluded that the data submitted by the industry petitioners supports
the conclusion that the NHV demonstrations required for pressure-, air-
, and steam-assisted control devices are adequate to show that the NHV
from those demonstrations is above the required thresholds specified by
the rule and that continuous monitoring is not needed. When inerts are
added intermittently or process operations change in ways that that may
lower the NHV, the proposed standards require a re-demonstration with a
new 14-day sampling effort.\108\ The re-demonstration would consider
the variability associated with these operations and determine a
reasonable lower-range value to use in compliance assessments. As such,
we proposed that the sampling requirements, with the revisions proposed
and now being finalized, are robust and sufficient to demonstrate that
continuous monitoring is not needed when the NHV of the gas stream
being controlled is sufficiently high, when considering the range of
vent gas and assist gas flow rates, to meet the required standards.
---------------------------------------------------------------------------
\108\ 800 Btu/scf for pressure-assisted flares and 270 Btu/scf
for steam- and air-assisted flares.
---------------------------------------------------------------------------
While we previously excluded monitoring for associated gas from the
NHV compliance demonstration requirements, some petitioners have
identified instances where the NHV for associated gas streams could be
compromised. Specifically, the use of water or CO2 flooding
for EOR could introduce significant inerts as part of the associated
gas produced and thereby lower the NHV of the associated gas. We found
the information presented by the petitioners compelling and therefore
proposed to conclude that the March 2024 Final Rule's exclusion of
associated gas from the NHV compliance demonstration requirements is
overly broad. Because the definition of associated gas in the March
2024 Final Rule specifically excludes these inert gases that may be
released with the natural gas during the initial stage of separation
after the wellhead, there are cases where associated gas can have high
levels of inerts and low NHV. Therefore, the EPA proposed to remove
this exclusion for associated gas in its entirety and also requested
comment on the proposed removal of the associated gas monitoring
exemption, as well as any additional miscellaneous operating scenarios
that can compromise the NHV for associated gas streams as well as all
flare types and ECD.
a. Exemptions From NHV Monitoring
Comment: Several commenters requested exemptions from all NHV
monitoring. One commenter stated that the EPA's proposal to reconsider
the streams that are exempt from monitoring due to high NHV content for
flares or ECD at new and existing sources would allow for additional
flexibility and compliance options for regulated entities.\109\ The
same commenter asserted that extending the exemption from NHV sampling/
monitoring requirements for affected facilities under NSPS OOOOb and EG
OOOOc to streams other than associated gas to include other equipment
with consistently high NHV vent streams would allow for many upstream
facilities to demonstrate effective control of VOCs and methane while
providing flexibility and reducing the compliance burden associated
with continuous monitoring. The commenter suggested that the EPA
consider expanding the streams exempt from monitoring for unassisted
flares or ECD at new sources, and unassisted, air-assisted, and steam-
assisted flares or ECD at existing sources to create consistency
between requirements for new sources and existing sources. The
commenter added that this would provide flexibility and lessen the
compliance burden associated with applying the monitoring standards to
affected facilities under NSPS OOOOb and EG OOOOc.
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\109\ Document ID No. EPA-HQ-OAR-2024-0358-0085.
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Another commenter urged the EPA to remove all NHV monitoring
requirements for all upstream sector flares and ECD in both the NSPS
OOOOb and EG OOOOc, regardless of whether inert gas is added, and to
remove the NHV standards which prompt such monitoring.\110\ The
commenter stated that operators in the Williston Basin already collect
and analyze data throughout the well's lifecycle for permitting,
compliance, and reporting purposes and that midstream companies sample
associated gas routinely (often monthly, including composition and NHV)
to handle custody transfer payments. The commenter stated that these
operators sample and analyze using established standards and that
therefore the March 2024 Final Rule NHV monitoring requirements are
redundant.
---------------------------------------------------------------------------
\110\ Document ID No. EPA-HQ-OAR-2024-0358-0091.
---------------------------------------------------------------------------
The same commenter added that the manufacturer of control devices
specifies the minimum or required range of the NHV for the inlet gas
which is necessary to operate the control device effectively. Regarding
lower-Btu gas, the commenter stated that flare and ECD technology
exists (and continues to evolve) which can ensure stable combustion at
lower heating values and that imposing rigid NHV monitoring
requirements can limit innovation. The commenter stated that upstream
sector flares and ECD have consistently been designed and tested to
ensure high combustion efficiency (destruction removal efficiency (DRE)
exceeding 99 percent) without the need for complex NHV monitoring
typically required for petroleum refinery flares. The commenter pointed
to comments in the May 2024 API and AXPC petition which highlighted
fundamental differences between upstream sector flares and petroleum
refinery flares regarding NHV requirements. The commenter explained
that upstream flares are not designed with NHV requirements because
they operate under non-steady state conditions, with a more consistent
gas composition, including NHV. In contrast, the commenter noted that
the Refinery MACT includes NHV requirements and operates under steady
state conditions with varying gas
[[Page 18079]]
composition (which can include different NHV contents). The commenter
stated that upstream flares are specifically designed to maintain high
combustion efficiency even in non-steady state conditions due to the
limited variability of the vent gas composition and relatively few gas
streams routed to the control device.
Several commenters requested that NHV continuous monitoring only
apply in situations where inert gases are introduced into the vent gas
stream.\111\ Two of the commenters \112\ referred to data \113\
previously provided to the EPA which they state demonstrates that oil
and gas facilities consistently exceed the minimum NHV limits, except
for known scenarios.
---------------------------------------------------------------------------
\111\ Document ID No. EPA-HQ-OAR-2024-0358-0083, -0088, -0090, -
0092, -0093, -0094, -0095.
\112\ Document ID No. EPA-HQ-OAR-2024-0358-0092, -0095.
\113\ See, e.g., Letter from American Petroleum Institute and
American Exploration & Production Council, to Michael S. Regan, US
EPA Administrator, Provisions Creating Immediate Compliance and
Implementation Issues EPA's Final Rule ``Proposed Standards of
Performance for New, Reconstructed, and Modified Sources and
Emissions Guidelines for Existing Sources: Oil and Natural Gas
Sector Climate Review,'' 5, EPA-HQ-OAR-2024-0358-0009 (April 5,
2024).
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One commenter requested that the EPA not require NHV monitoring
unless inert gases are added or for other miscellaneous scenarios which
decrease vent gas NHV regardless of type of control device.\114\ The
commenter stated that, in previous comments submitted to the EPA, they
provided data that shows the vent gas NHV is typically well above 900
Btu/scf, and therefore the NHV monitoring requirements are unnecessary
except in specific operations which introduce inert gases into the vent
gas stream. The commenter provided that the previous data set
represented LP vent gas streams and included over 22,000 data points
from 18 operators covering approximately 4,200 sites, including well
sites, central production facilities, and compressor stations. A second
data set for HP vent gas streams, collected in the same operator survey
in coordination with AXPC, is included in the commenter's letter and
represents an additional 39,000 data points from 12 operators covering
approximately 22,100 sites, primarily from well sites and central
production facilities. The commenter concluded that NHV monitoring
should only be required when inert gases are added or for other
miscellaneous scenarios which decrease vent gas NHV regardless of type
of control device.
---------------------------------------------------------------------------
\114\ Document ID No. EPA-HQ-OAR-2024-0358-0083.
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Another commenter also urged the EPA to exempt NHV monitoring for
flares and ECD that control associated gas from any oil well (not just
well affected facilities under NSPS OOOOb or well designated facilities
under EG OOOOc).\115\ The commenter explained that the composition of
associated gas does not change due to regulatory applicability, and the
current associated gas exemption arbitrarily limits the scope of the
exemption.
---------------------------------------------------------------------------
\115\ Document ID No. EPA-HQ-OAR-2024-0358-0088.
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Lastly, a commenter recommended that the EPA allow the NHV
monitoring exemption to apply to pressure-assisted control
devices.\116\ The commenter referenced the January 2025 Proposal in
which the EPA states that because the NHV of methane (896 Btu/scf) is
not significantly higher than the required minimum NHV of 800 Btu/scf
for pressure-assisted flares and ECD, the Agency will continue to
require either continuous monitoring or alternative performance testing
(14-day NHV test) for these devices. The commenter urged the EPA to
reconsider this approach, which they say is not supported by the record
and is contrary to common sense. The commenter further provided that
the EPA further stated in the January 2025 Proposal that `` . . . we
find that it is much easier for the NHV in the vent gas samples from
these control devices to decrease and approach the 800 Btu/scf NHV
threshold. . .'' According to the commenter, this reason does not
support costly continuous monitoring.
---------------------------------------------------------------------------
\116\ Document ID No. EPA-HQ-OAR-2024-0358-0094.
---------------------------------------------------------------------------
Conversely, two commenters opposed the EPA's proposal to exempt
flares and ECD from NHV monitoring. One of the commenters agreed with
the EPA's proposal to require certain flares and other control devices
controlling emissions from associated gas to monitor or sample for NHV.
According to the commenter, the EPA must do so given that some
petitioners have identified instances where the NHV for associated gas
streams could be compromised, such as in water or CO2
flooding which can introduce a large amount of inerts as part of the
associated gas produced. However, the commenter disagreed with the
EPA's proposal to require this monitoring or sampling only for
pressure-assisted flares and other controls at new and existing sources
and air- and steam-assisted flares and other controls at new sources.
The commenter stated that the EPA must also require NHV monitoring or
sampling for unassisted flares at new and existing sources and air- and
steam-assisted flares at existing sources. The commenter stated that
the EPA has failed to establish that the NHV of gases sent to flares
and other controls, including those where no inert gases are added and
nothing else decreases the NHV content of the inlet stream gas, will
always be above the March 2024 Final Rule's NHV limits. According to
the commenter, this means that the EPA cannot rationally justify a
complete exemption from NHV monitoring and sampling.
The other commenter strongly opposed the EPA's proposal to remove
NHV monitoring requirements for all new unassisted flares and ECD (with
limited exceptions due to inerts) and for existing air-assisted and
steam-assisted flares and ECD and asserted that the EPA has changed its
position without adequate justification.\117\ The commenter urged the
EPA to maintain NHV monitoring requirements for all unassisted flares
and ECD.
---------------------------------------------------------------------------
\117\ Document ID No. EPA-HQ-OAR-2024-0358-0096.
---------------------------------------------------------------------------
The same commenter referenced the EPA's justification for its
proposed exemption from all NHV monitoring for unassisted flares and
ECD, which cited new data \118\ provided by API, AXPC, and GPA
Midstream that the EPA claims ``appear to demonstrate that the NHV of
the vent gas is consistently well above the 200 or 300 Btu/scf vent gas
requirements for these control devices when inerts are not present, and
because there are no combustion zone or dilution parameters for these
control devices.'' \119\ The commenter suggested that several
deficiencies in the data cut strongly against the EPA's decision to
exempt all unassisted flares and ECD from the monitoring requirements.
The commenter disagreed that the Temporary Flaring Survey contains
enough information to ensure the NHV figures represent the entire vent
gas stream going to the flare or ECD. The commenter contended that
because the data sets do not specify that all samples were taken after
all vent streams were combined, it is inappropriate for the EPA to make
a sweeping exemption based solely on the data presented.
---------------------------------------------------------------------------
\118\ See API-AXPC NHV Survey Results v1.0 at https://www.regulations.gov/document/EPA-HQ-OAR-2024-0358-0044; July 31,
2024 Email from GPA (Response for additional information) at https://www.regulations.gov/document/EPA-HQ-OAR-2024-0358-0039.
\119\ See 90 FR 3747 (January 15, 2025).
---------------------------------------------------------------------------
The same commenter also supported the proposed removal of the
exemption for associated gas waste streams, which they state is
supported by the record. The commenter agreed with the EPA's assessment
of information, provided that the NHV of associated gas does not always
exceed the minimum limits as
[[Page 18080]]
the EPA expected it would when it finalized the exemption in the March
2024 Final Rule. Further, the commenter agreed that the information
provided demonstrates that associated gas can be combined with inerts,
which in turn may reduce the NHV below the required minimum thresholds.
The commenter urged the EPA to expand the inclusion of NHV monitoring
for unassisted flares and ECD where the only vent stream is associated
gas for these reasons and for the reasons discussed in other remarks by
the commenter which address the EPA's proposed exemption of unassisted
flares and ECD from all NHV monitoring.
Response: The EPA received numerous comments regarding the vent gas
NHV continuous monitoring requirements and alternative performance test
(sampling demonstration) option for flares and ECD discussed in the
January 2025 Proposal.
In general, most commenters were in favor of the EPA's proposal to
expand the streams to include unassisted flares or ECD at new sources
and to include unassisted, air-assisted, and steam-assisted flares or
ECD at existing sources, and to only require NHV monitoring for streams
where inert gases were added or in the event of operational scenarios
where NHV is known to decrease. However, most commenters disagreed with
the EPA's proposal to continue to require the NHV monitoring that is
currently required for all pressure-, air-, and steam-assisted flares
or ECD at new sources and for pressure-assisted flares or ECD at
existing sources.
To support this argument, as discussed in section IV.B.2 of this
preamble, in April 2025 API provided new HP stream data (39,000
samples) from 11 basins with over 99.5 percent of these data greater
than 800 Btu/scf, which was comparable to that of the LP NHV previously
analyzed in 2024. For the combined data sets from April 2024 and April
2025, which consisted of over 60,000 total combined data points from
both LP and HP gas streams, over 99.5 percent of the data showed NHV
contents of at least 800 Btu/scf and over 99.9 percent of the data
showed NHV contents of at least 300 Btu/scf. In this combined data set,
over 99 percent of the data samples from LP gas streams resulted in an
NHV content of greater than 900 Btu/scf and over 95 percent of the data
samples from HP gas streams resulted in an NHV content of greater than
900 Btu/scf. The EPA reviewed the ``Sample Description/Source'' field
in both the LP and HP data sets and concluded that the sources for
which NHVs were determined are representative of gases that may be
controlled by a flare or ECD. In turn, the EPA found this additional
data form a robust, reliable, and representative data set to support a
compelling argument to include both the LP and HP data (which comprises
data from unassisted, air-assisted, and steam-assisted flares and ECD)
as its justification to expand the streams that are exempt from
monitoring (due to typically high NHV contents, on average) to include
all flare and ECD for both new and existing sources.\120\
---------------------------------------------------------------------------
\120\ As summarized in footnotes 106 and 108, 99 percent of the
LP data were from five basins and 97 percent of the HP data were
from eight basins, which geographically represent the primary basins
located throughout the United States.
---------------------------------------------------------------------------
While the EPA recognizes that in some instances sources may not
achieve the applicable and prescribed NHV content values in NSPS OOOOb
and EG OOOOc, industry commenters have presented sufficient information
to conclude that these instances occur where inert gases are added or
under other miscellaneous scenarios that decrease the NHV content of
the inlet stream gas to all flare and ECD for both new and existing
sources. As such, and as proposed, the EPA is requiring an NHV
demonstration where inert gases are added, or for other miscellaneous
scenarios that decrease the NHV content of the inlet stream gas for all
flare and ECD for both new and existing sources. The EPA is also
finalizing recordkeeping and reporting requirements to indicate whether
the flare or ECD receives (or does not receive) inert gases or other
streams that may lower the NHV of the combined stream, and, if so, a
description of the operating scenario(s) that may lower the NHV of the
combined stream through the introduction of those inert gases or other
streams. Moreover, the EPA is also clarifying that when a required NHV
demonstration is performed, the samples must be taken during the period
with the lowest expected NHV (i.e., the period with the highest
percentage of inerts).
Regarding the comments opposing the January 2025 Proposal in this
respect, one commenter \121\ asserted that the EPA changed its position
without adequate justification and lacked sufficient evidence to
support such an exemption. The EPA disagrees. The combined data set
described earlier in this response presented tens of thousands of data
points (i.e., fuel analysis samples for NHV content) for consideration
and analysis. Moreover, as the EPA has already discussed in this
preamble, it will not completely exempt flares and ECD as a whole from
all NHV monitoring. That is, the EPA will still require an NHV
demonstration where inert gases are added, and for other miscellaneous
scenarios that decrease the NHV content of the inlet stream gas for all
flare and ECDs for both new and existing sources. Given the EPA
received over 60,000 data points for consideration and analysis, which
were spread over the primary basins that geographically represent the
oil and gas industry, with over 99.5 percent of the results being above
the NHV thresholds currently prescribed by the NSPS OOOOb and EG OOOOc
rules, the EPA considers the data submitted to be sufficiently reliable
and persuasive to finalize the NHV exemptions included in this action.
Moreover, by providing these NHV exemptions, the EPA believes that the
industry will be in a better position to redirect and focus its cost
expenditures, manpower, and emissions reduction efforts on the issues
of most concern, such as equipment inspections, maintenance, and leak
prevention measures.
---------------------------------------------------------------------------
\121\ Document ID No. EPA-HQ-OAR-2024-0358-0096.
---------------------------------------------------------------------------
Finally, the EPA is finalizing its proposal to replace the general
exemption from NHV monitoring for associated gas for any control device
used at ``well site affected facilities'' with NHV monitoring that is
more reflective of industry operations. However, consistent with the
finalized rule requirements for all flare and ECDs, associated gas
streams will still be subject to NHV monitoring where inert gases are
added, or in the event of operational scenarios where NHV is known to
decrease.
b. Distinction of ``New'' and ``Existing'' Flares and Enclosed
Combustion Devices
Comment: One commenter expressed disagreement with the EPA's
distinction between ``new'' and ``existing'' flares and ECD, especially
as it relates to proposed exemptions from NHV monitoring because, in
practice, this effectively exempts all flares and ECD from NHV
monitoring unless the flare or ECD is brand new.\122\ According to the
commenter, that means that only new affected facilities using new
flares and ECD would be required to comply with the NHV monitoring
requirements, and any modified or reconstructed affected facilities
(and existing designated facilities) would be exempt from these
provisions. The commenter believed that the EPA has not explained or
[[Page 18081]]
justified this type of distinction related to flares and ECD nor how
these exemptions for ``existing'' flares address the concerns about
``pervasive issues with combustion sources.'' \123\
---------------------------------------------------------------------------
\122\ Document ID No. EPA-HQ-OAR-2024-0358-0096.
\123\ 87 FR 74793 (December 6, 2022).
---------------------------------------------------------------------------
The commenter further asserted that control devices, including
flares and ECD, are not by themselves ``new'' or ``existing'' sources
under the NSPS or EG. Instead, these control devices are used to meet
certain emission reduction standards for ``new'' affected facilities or
``existing'' designated facilities. Therefore, the commenter contended
that the EPA must clearly define how it distinguishes the terms ``new''
and ``existing'' for purposes of the exemptions proposed if it moves
forward with finalizing any exemptions from NHV monitoring.
Response: For the purposes of this final rule, ``new'' sources are
designated as NSPS OOOOb sources, which are crude oil and natural gas
facilities for which construction, modification, or reconstruction
commenced after December 6, 2022, and ``existing'' sources are
designated as EG OOOOc sources, which are crude oil and natural gas
facilities for which construction, modification, or reconstruction
commenced on or before December 6, 2022.
Based on the revisions to both NSPS OOOOb (i.e., new, modified, and
reconstructed sources) and EG OOOOc (i.e., existing sources) as a
result of this final rule, NSPS OOOOb sources and EG OOOOc sources will
now have identical NHV sampling requirements and exemption qualifiers,
with the exception of the NHVcz and NHVdil
requirements that will only apply to NSPS OOOOb sources, as described
in section IV.B.5 of this preamble. Hence, any distinction between
``new'' and ``existing'' sources would no longer apply in this context
as it relates to the exemptions from NHV monitoring, since both ``new''
and ``existing'' sources will now have the same NHV sampling
requirements and categorical exemptions with the finalization of this
rulemaking.
c. Inert Gas and Other Vent Gas Stream Example Scenarios
Comment: Numerous commenters provided recommendations,
clarifications, and suggestions ``where inert gas or other vent gas
streams which may lower the NHV of the combined stream are added.'' One
commenter cited the proposed regulatory text at 40 CFR
60.5417b(d)(8)(ii) to describe the inert gas added scenarios under
which NHV continuous monitoring or alternative sampling demonstration
would be required, noting that the corresponding language was proposed
for EG OOOOc.\124\ The commenter provided the following recommendations
and supporting rationale for both subparts (NSPS OOOOb and EG OOOOc):
(1) remove ``vent streams from storage vessel with high water
content,'' (2) ``vent streams from glycol dehydrator unit reboilers''
should be revised to ``vent streams from glycol dehydrator unit
reboilers without water removal'' and (3) ``vent streams from enhanced
oil recovery facilities'' should be revised to ``vent stream containing
water or CO2 used for enhanced oil recovery.''
---------------------------------------------------------------------------
\124\ Document ID No. EPA-HQ-OAR-2024-0358-0083.
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The commenter stated that the EPA's intent was to require NHV
monitoring when the higher water content from a storage vessel could
lower the vent gas NHV below the applicable minimum, but the proposed
regulatory language could be interpreted as any produced water tank.
The commenter noted that the EPA cites GPA Midstream's comment letter
as the basis for this example, though GPA Midstream's letter states
that even in these cases, the NHV remained above the applicable
limit.\125\ The commenter contended that the LP NHV dataset also
supports removing ``storage vessel with high water content'' since all
data points from produced water tanks were greater than 300 Btu/scf,
which meets the minimum vent gas NHV requirement for unassisted, steam-
assisted, and air-assisted control devices. While vent streams from
produced water tanks can be lower than 900 Btu/scf in certain
scenarios, the commenter stated that they are not typically routed to
pressure-assisted control devices (minimum vent gas NHV of 800 Btu/
scf), since produced water tanks operate at near atmospheric pressure.
---------------------------------------------------------------------------
\125\ GPA Midstream--EPA 06/24/24 Meeting Follow-Up. Re:
Response to EPA Request for Additional Information Regarding OOOOb
GPA Midstream Net Heating Value Case Scenarios and Data. (Attachment
Summarizing NHV Data Included).
---------------------------------------------------------------------------
The commenter also requested that ``[v]ent streams from glycol
dehydrator unit reboilers'' be revised to ``vent streams from glycol
dehydrator unit reboilers without water removal'', to be consistent
with the preamble. The commenter explained that vent streams from
glycol dehydrator unit reboilers have higher water content which lowers
the NHV, but they are typically routed through a condenser or other
similar equipment to remove water before being routed to combustion
control. According to the commenter, the Agency should only require NHV
monitoring in cases where the glycol dehydrator unit reboiler does not
have water removal.
Finally, the commenter requested that ``[v]ent streams from
enhanced oil recovery facilities'' be revised to ``vent stream
containing water or CO2 used for enhanced oil recovery'' to
clarify that only vent streams that contain the inert gas involved in
EOR, not any vent stream at an EOR site, should require NHV monitoring.
According to the commenter, based on process knowledge, operators are
able to identify which vents streams at an EOR site contain the inert
gas used in EOR and therefore have lower NHV and should be subject to
NHV monitoring.
Another commenter agreed that the universe of low-NHV streams
identified in the proposal encompasses the scenarios of which they are
aware, except the commenter is unclear what the EPA means by ``vent
streams from storage vessels with high water content.'' \126\ The
commenter explained that the proposed language may include crude oil or
condensate tanks that share a closed vent system and control device
with produced water tanks. The commenter stated that the data they
provided includes such tanks systems and shows that low-NHV is not an
issue in these systems, given the relatively high NHV of the
hydrocarbon components of storage tank vapors. The commenter requested
that the EPA not include these storage tank systems in the list of low-
NHV scenarios.
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\126\ Document ID No. EPA-HQ-OAR-2024-0358-0088.
---------------------------------------------------------------------------
Moreover, the commenter asserted that methane, the lightest
hydrocarbon organic molecule in process streams at oil and gas
facilities, is already above the minimum NHV required for these
pressure-assisted devices. Therefore, when a process stream includes
any quantities of heavier hydrocarbons, the stream will have a higher
heat content and be even further above the minimum NHV requirement. The
commenter contended that the EPA's assertion that ``it is easier'' for
the streams going to these devices to experience a decrease in NHV is
not based on direct or empirical evidence in the rulemaking record.
According to the commenter, if inert gases are not added to the
hydrocarbon process stream sent to the control device, the NHV will
meet the requirements at all times. As with the proposed requirements
for non-assisted flares and ECD, the commenter stated that pressure-
assisted devices should be assumed to meet minimum NHV requirements. As
such, the commenter
[[Page 18082]]
suggested that the EPA treat pressure-assisted devices in the same
manner as non-assisted flares and ECD and ``require NHV monitoring only
in cases where inert gases are added, or for other miscellaneous
scenarios which decrease the NHV content of the inlet stream gas to the
enclosed combustion device or flare.''
The same commenter also stated that infrequent nitrogen purges
should not prevent a flare from qualifying for the NHV testing
exemption. The commenter explained that many gas processing facilities
within the industry use nitrogen purging during maintenance procedures
to displace air or other gases within a system and create an inert
environment by removing oxygen and other potentially reactive
components which is crucial for safety, preventing unwanted chemical
reactions within pipelines and equipment, and reducing emissions by
avoiding potential leaks. The commenter also explained that facilities
typically perform nitrogen purging no more than one to three times a
year and these purges are small in volume relative to the overall flow
going to a flare or ECD. Thus, the commenter reported that they do not
expect nitrogen purging to have an impact significant enough to lower
the NHV to levels below the compliance limits.
The same commenter additionally suggested that the EPA allow the
NHV monitoring exemption when intermittent nitrogen purging occurs in
volumes that will not significantly impact the NHV of the total gas
stream going to the flare. The commenter stated that the EPA should
include an option to demonstrate compliance using site-specific data
and process knowledge, such as nitrogen purge volumes and total volume
sent to the control device, in the rule language to allow the owner/
operator to continue using the NHV monitoring exemption by documenting
that intermittent nitrogen purging did not result in the NHV of the
total gas stream going to the control device decreasing below the
compliance limits.
Conversely, a commenter agreed with the EPA's proposal to not
exclude pressure-assisted flares and ECD from NHV demonstration
requirements.\127\ The commenter asserted that this is the only lawful
and rational approach given the Agency's prior findings that the
required minimum NHV of 800 Btu/scf for pressure-assisted control
devices is not significantly higher than the NHV of methane, that
sources that contain primarily methane would not require much dilution
from inert components to be below the 800 Btu/scf NHV threshold, and
that, while data provided by petitioners indicated that the majority of
samples had NHVs above 800 Btu/scf, it is much easier for the NHV in
the vent gas samples from these control devices to decrease and
approach the 800 Btu/scf NHV threshold.
---------------------------------------------------------------------------
\127\ Document ID No. EPA-HQ-OAR-2024-0358-0086.
---------------------------------------------------------------------------
Response: The EPA appreciates the suggestions and clarifications
from the commenters to further expand upon the particular
``miscellaneous scenarios'' that could decrease the NHV content of the
of the inlet stream gas to all flare and ECDs for both new and existing
sources. Based upon the received comments, as well as those scenarios
already included in the January 2025 Proposal, the EPA considers the
following miscellaneous operating scenarios as those that could
potentially decrease the NHV content of a given inlet stream, and which
therefore will not be exempted from the NHV sampling requirements under
NSPS OOOOb and EG OOOOc for all flare and ECDs for both new and
existing sources, where applicable:
1. Combining AGR system amine regenerator still column vent gas
with affected facility vent gas streams--AGR amine regenerator still
column vent gases typically are routed to an individual control device
due to the low flow rate, low pressure, and corrosive nature of the
vent stream, and that the low NHV of the stream typically requires
supplemental gas for proper control device operation. However, it is
possible to combine the still column vent gas with other vent gas
streams, which would lower the NHV of the combined stream, primarily
due to the high CO2 content of the still column vent gas.
2. Combining glycol dehydration unit reboiler vent gas with
affected facility vent gas streams without water removal--typically,
glycol dehydration unit reboiler vent gas is routed through a condenser
to remove liquids (including VOC and water vapor) and then routed to a
process or control device. However, it is possible to combine the
glycol dehydration unit reboiler gas, without routing through a
condenser, with other vent gases routed to common control. The high
water content of the reboiler vent gas stream could lower the NHV of
the combined vent gas streams.
3. Use of inert gases and entrainment in affected facility vent gas
streams--midstream operations usually do not employ the use of inert
gases such as nitrogen because if a blanket gas is needed, its
midstream operations use natural gas as it is readily available and
compatible with control devices due to the high NHV. In instances where
an inert gas such as nitrogen is used as a blanket gas, this could
cause lower NHV of the vent gas stream.
4. High water content in vent gas streams from storage vessels--
midstream operations employ the use of storage vessels for storing
hydrocarbons and produced water (i.e., produced water tanks), which
typically have NHVs well above the minimum thresholds required by the
March 2024 Final Rule. However, it is possible that some production
areas could have higher water content in the vent stream coming from
the storage vessels, which would lower the NHV. In these cases, the
high water content would increase the probability that the storage
vessel emissions thresholds for applicability would not be exceeded.
The EPA also clarifies that this scenario pertains to a higher water
content from a storage vessel that could lower the NHV below the
applicable minimum value, and not ``any produced water tank.'' It is
the EPA's understanding that operators have various means of making
this determination on an operating history, best engineering judgement,
or manufacturer's recommendation basis as a response to known operating
scenarios that could lower the NHV below the applicable minimum value.
5. Compressors in acid gas service--also known as sour gas service,
these compressors are used to compress gases containing H2S
and CO2 for various applications, including injection into
underground disposal wells, which are in turn used for natural gas
processing and the disposal of acid gas components.
6. Sites in fields with vent streams containing water or
CO2 flooding used for EOR.
7. Flares at gas plants that receive acid gas from sweetening
units.
8. NRUs--NRUs in the oil and gas industry are used for separating
nitrogen from natural gas streams, improving the heating value and
marketability of the gas, and meeting pipeline specifications. This is
often achieved using cryogenic distillation. However, during the NRU
process, nitrogen dilutes the NHV content of the natural gas, making it
less efficient.
d. Flare Tip Maximum Velocity Limits
In the January 2025 Proposal, the EPA proposed revisions to 40 CFR
60.5417b(d)(8)(iv), which includes requirements for the usage of one-
time assessments in lieu of installing vent gas flow monitors and, in
the case of assisted flares, assist gas flow monitors if certain
provisions are met. In the March 2024 Final Rule, while we
[[Page 18083]]
finalized provisions requiring owners and operators of unassisted
flares to conduct an initial determination to ensure the flare tip
velocity falls within limits under worst-case flow provisions, we did
not finalize similar ``initial determination'' requirements for air-
assisted flares, even though the velocity limits apply. Therefore, we
proposed to add this maximum velocity assessment to the existing
provisions in 40 CFR 60.5417b(d)(8)(iv)(D) and (E) for air-assisted
flares. This provision is not applicable to ECD. In reviewing these
provisions, we also noted that there was no corresponding provision for
steam-assisted flares or ECD. This was an oversight in the March 2024
Final Rule, and we proposed new provisions at 40 CFR
60.5417b(d)(8)(iv)(F) similar to those for air-assisted devices that
are specific to steam-assisted flares or ECD. These revisions are not
needed in EG OOOOc because these provisions are specific to evaluations
for flares complying with an NHVcz or NHVdil
parameter. The EPA solicited comment on these proposed provisions to
ensure compliance with the velocity operating limit and whether, for
those devices that have conducted NHV demonstrations, the velocity
limit used in the assessment should be based on the allowable velocity
at the lowest NHV result from the demonstration rather than being based
on the default of 18.3 meters/second (60 feet/second).
Comment: For air-assisted flares, several commenters believed that
the proposed text for alternatives to inlet flow monitoring at 40 CFR
60.5417(d)(8)(iv) references incorrect flare tip maximum exit velocity
limits. One commenter \128\ asserted that the maximum flare tip
velocity limit should be based on the methodology in 40 CFR 60.18
rather than a default limit of 60 feet/second for alternative flow
monitoring demonstrations. The commenter stated that NSPS OOOOb at 40
CFR 60.5412b(a)(3)(v) states that flares (except for pressure-assisted
flares) must comply with the maximum flare tip velocity limits in 40
CFR 60.18. The commenter stated that the rule, however, then uses a
default maximum tip velocity of 18.3 meters/second (60 feet/second) for
the alternative flow monitoring demonstration requirements at 40 CFR
60.5417b(d)(8)(iv)(B)(1) for unassisted devices. The commenter stated
that the EPA is proposing to add similar regulatory text for air- and
steam-assisted flares at 40 CFR 60.5417b(d)(8)(iv)(D)(3), (E)(3), and
(F)(3) in this rulemaking. The commenter indicated that most gas
streams in upstream and midstream operations have sufficient minimum
NHV to allow maximum tip velocities greater than 60 feet/second in
accordance with 40 CFR 60.18.
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\128\ Document ID No. EPA-HQ-OAR-2024-0358-0083.
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The commenter further added that they do not believe it was the
EPA's intent that when the backpressure regulator is used in lieu of
(i.e., as an alternate to) flow monitoring, the flare tip velocity must
be maintained below 60 feet/second, as 40 CFR 60.18 allows for higher
tip velocities based on NHV. The commenter suggested that the EPA
should therefore update the alternative flow monitoring demonstrations
requirements to reference the applicable 40 CFR 60.18 requirements for
maximum tip velocity rather than use a default of 60 feet/second.
Two commenters explained that while the proposed text requires that
the maximum flow rate to the flare should not exceed 18.3 meter/second,
this is not the 40 CFR 60.18 standard that applies to air-assisted
flares.\129\ Instead, the commenter stated, 40 CFR 60.18(c)(5) requires
that air-assisted flares ``be designed and operated with an exit
velocity less than the velocity, Vmax, as determined by the
methods specified in [40 CFR 60.18(f)(6)].'' According to the
commenter, using Vmax provides a much larger acceptable
flare operating range without compromising flare performance. The
commenter stated that if the EPA does not make this change, the scope
of flares subject to this alternative could be significantly reduced,
and, in turn, the EPA's assumption that ``few facilities will have to
install continuous monitoring systems'' would be incorrect. Another
commenter also explained that the NSPS OOOOb proposal text and the
March 2024 Final Rule both apply the same maximum exit velocity of 18.3
meter/second to steam-assisted and unassisted flares.\130\ The
commenter assumed that the EPA derived this limit from 40 CFR
60.18(c)(4)(i), but explained that while they agree that this limit
does apply to certain steam-assisted and unassisted flares, multiple
limits could apply, depending on the operating conditions. Similarly,
another commenter noted that the January 2025 Proposal did not
reference or incorporate all of the applicable 40 CFR 60.18(c)
provisions for unassisted flares.\131\ The commenter requested that,
for unassisted flares, the EPA allow operators to demonstrate
compliance with any of the options in 40 CFR 60.18(c)(3)(i) or (4). For
these reasons, commenters requested that the EPA provide the full suite
of options under 40 CFR 60.18 for flare tip exit velocity limits.
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\129\ Document ID Nos. EPA-HQ-OAR-2024-0358-0088, -0092.
\130\ Document ID No. EPA-HQ-OAR-2024-0358-0088.
\131\ Document ID No. EPA-HQ-OAR-2024-0358-0092.
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One commenter also stated that the corresponding edits should also
be made to the EG OOOOc alternative flow monitoring demonstration
requirements in 40 CFR 60.5417c(d)(8)(iv)(B)(1).\132\
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\132\ Document ID No. EPA-HQ-OAR-2024-0358-0083.
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Conversely, one commenter agreed with the EPA's previous
recognition that 40 CFR 60.18(d) mandates the Agency to establish
monitoring for 40 CFR 60.18(c)(3)(ii)'s NHV limits, which the March
2024 Final Rule adopted for unassisted flares.\133\ \134\ The commenter
contended that the EPA's proposed exemption from NHV monitoring
violates 40 CFR 60.18(d), which requires each applicable subpart to
include provisions stating how owners or operators using flares will
monitor them.
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\133\ Document ID No. EPA-HQ-OAR-2024-0358-0086.
\134\ 87 FR 74702 and 74792-93 (December 6, 2022).
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Response: We agree with the commenters that 40 CFR 60.18(c) and (f)
provide alternative values for the maximum flare tip velocity,
Vmax. We included the 18.3 meters/second (60 feet/second)
value for Vmax because it was the lowest Vmax
value for the 40 CFR 60.18 alternatives and because there were
exemptions from NHV monitoring, so data may not be available to assess
Vmax using the alternatives in 40 CFR 60.18. However, the
exemptions from NHV monitoring are based on data supplied by
petitioners and commenters, which show that NHV of gases generated at
oil and gas facilities are consistently above 800 Btu/scf, provided no
inert gases are added. At these high NHV vent gas values,
Vmax values of up to 122 meters/second (400 feet/second) are
allowed. As such, we agree with the commenters that the proposed 18.3
meters/second (60 feet/second) Vmax limits unnecessarily
impose more stringent limitations when the engineering assessment is
used to demonstrate compliance. We agree that this could require the
installation of flow meters on many flares where, if more accurate
estimates of NHV were allowed, the flare could have demonstrated
continuous compliance with the Vmax limit based on the
engineering calculations.
We also note that we allow the use of ``. . . the minimum expected
value of the NHV of the inlet gas to the enclosed
[[Page 18084]]
combustion device or flare based on previous sampling results or
process knowledge of the streams sent to the enclosed combustion device
or flare . . .'' when conducting engineering assessments used to
demonstrate compliance with the NHVcz or NHVdil
requirements (see 40 CFR 60.5417b(d)(8)(iv)(D)(2) and (E)(2)). Because
we allow the use of previous sampling results or process knowledge for
determining minimum NHV in these engineering assessments, we find it is
more consistent and reasonable to allow these same provisions in the
Vmax engineering calculations. Therefore, we are revising
the engineering assessments related to maximum flare tip velocities to
determine Vmax as specified in the applicable provisions in
40 CFR 60.18(c) and (f) of this chapter using the minimum expected
value of the NHV of the inlet gas to the flare or ECD based on previous
sampling results or process knowledge of the streams sent to the flare
or ECD.
Regarding the 40 CFR 60.18(d) requirement that each applicable
subpart include provisions stating how owners or operators using flares
will monitor these control devices, the EPA disagrees that these
finalized exemptions from the NHV requirements violate 40 CFR 60.18(d),
since this final rule is only revising and clarifying the monitoring
alternatives in the existing NSPS OOOOb and EG OOOOc rules, rather than
removing the monitoring provisions altogether, which will continue to
be prescribed and required by 40 CFR 60.5417b and 40 CFR 60.5417c,
respectively.
3. Sampling Location and Duration of Alternative Performance Test
In the January 2025 Proposal, the EPA reconsidered the requirements
in the March 2024 Final Rule regarding the sampling duration for the
alternative performance test (sampling demonstration) option for the
NHV compliance demonstration and proposed to allow for shorter sampling
times when it is technically infeasible to collect a grab sample for a
minimum of one hour. While the March 2024 Final Rule included
provisions for sampling periods of longer than 14 days (where needed)
to collect a total of 28 samples, and the general provisions in 40 CFR
60.8(b)(5) also allow for ``shorter sampling times and smaller sample
volumes when necessitated by process variables or other factors,'' we
found compelling the petitioner's arguments and newly presented
supporting information regarding the potential instances of
intermittent flow of gas streams, which makes sampling for one hour
technically infeasible in those cases (e.g., intermittent flow from
sources with low pressure). As such, we found it appropriate to propose
additional flexibility in the January 2025 Proposal to fully address
these intermittent flow situations. Therefore, we proposed that
sampling must be conducted for a minimum of one hour, when technically
feasible. When it is not technically feasible to collect the sample for
a minimum of one hour, the owner or operator should collect the sample
for as long as possible, up to one hour. For samples taken during low
or intermittent flow events, the owner or operator must document and
report the collection time and the reason for not obtaining a full one-
hour sample with the NHV sampling results. We requested comment on the
actual duration of flow that is achievable in practice for those cases
where sampling for one-hour is technically infeasible on low pressure
and intermittent gas streams, and why a one-hour sample would be
technically infeasible for those cases.
Regarding the location for sampling, we noted that the March 2024
Final Rule required taking a sample of the inlet gas to the control
device but did not require that the gas sample be taken directly at the
inlet of the control device. We consider an ``inlet gas sample'' to be
a sample taken within the control device header system in a location
after all vent stream sources have been added to the control device
header. While the EPA recognizes petitioners' concerns with installing
sampling ports or ``taps'' on these source types, the March 2024 Final
Rule does not specify a physical location where the sampling must
occur. We therefore do not believe it is necessary to specify that
sampling may occur at another ``representative'' location or specify
such ``representative'' locations. The EPA also notes that the General
Provisions in 40 CFR part 60 include procedures for alternatives to
monitoring, including alternative locations for monitoring ``when the
owner or operator can demonstrate that installation at alternate
locations will enable accurate and representative measurements''--these
provisions already address site-specific issues with conducting the
alternative performance test (sampling demonstration) option.\135\
Accordingly, we did not propose to change the current provisions in the
March 2024 Final Rule regarding sampling location for the NHV grab
sample option.
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\135\ See footnotes 48 and 49.
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a. Sampling Frequency
Comment: One commenter stated that while the EPA proposed revisions
to the performance testing requirements, the EPA did not propose
amendments to some of the most burdensome requirements (e.g., the
sampling frequency of two samples per day for 14 days with an ongoing
demonstration of three samples every five years) for the sampling
demonstration option for NSPS OOOOb or EG OOOOc, and the one-hour
minimum sampling time for the twice daily samples, except in cases
where low or intermittent flow makes one-hour sampling infeasible.\136\
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\136\ Document ID No. EPA-HQ-OAR-2024-0358-0095.
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Another commenter suggested that sampling using grab samples across
multiple days adds useful flexibility and is a sound approach.\137\ The
commenter appreciated the additional flexibility that the EPA provided
in the 14-day sampling process for control devices using grab samples
for compliance purposes. The commenter stated that there would not be
an expected change in control device vent gas compositions on days when
samples could not be taken. As such, they stated that allowing breaks
in the 14-day periods for sites that do not use continuous sampling
systems would provide representative results at a reduced cost and
burden.
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\137\ Document ID No. EPA-HQ-OAR-2024-0358-0094.
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One commenter requested that the EPA require only one daily sample
for manual grab sampling since two daily samples unnecessarily
increases costs and emissions from travel.\138\ This commenter asserted
that two daily samples are unnecessary, and that the EPA should reduce
the requirement to a single daily sample since the vent gas NHV is not
expected to vary much between the two samples. The commenter asked the
EPA to reduce this unnecessary sampling burden and revise the
requirement to one daily sample for a total of 14 total samples.
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\138\ Document ID No. EPA-HQ-OAR-2024-0358-0083.
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One commenter stated that if the EPA retains continuous vent gas
monitoring requirements for air- and steam-assisted control devices,
the commenter supports the EPA's proposal to broaden the use of the 14-
day alternative sampling methodology in 40 CFR 60.5417b(d)(8)(iii) to
include steam-assisted and premix air-assisted flares and ECD.\139\
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\139\ Document ID No. EPA-HQ-OAR-2024-0358-0094.
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Response: The EPA is finalizing the rule to only require a 14-day
NHV
[[Page 18085]]
sampling demonstration for certain operating scenarios as summarized in
section IV.B.2 of this preamble for all flare and ECDs. These
exemptions will significantly reduce the sampling burden of acquiring
two samples per day for 14 days. The EPA disagrees that the potential
reduced vent gas NHV content for these operating scenarios will not
vary much between the two daily samples and is maintaining the two
samples per day requirement over a period of 14 days, as currently
prescribed by the NSPS OOOOb and EG OOOOc rules.
However, as previously explained in sections III.B and IV.B of this
preamble, the EPA is allowing breaks for weekends and holidays which
may occur during the 14-day sampling period, such that the 14 days do
not have to be consecutive. Consecutive operating days are reasonable
for continuous monitoring because these systems are present
continuously. However, manual grab sample collection requires someone
to be present at the site to collect samples each day, which, if
required to be done on consecutive days, would require collection on
weekends and potentially on holidays. The March 2024 Final Rule already
allows for sampling beyond the 14 days if 28 samples cannot be
collected during that timeframe. Allowing additional flexibility for
non-consecutive operating day sampling can lengthen the time needed to
collect samples and delay the conclusion of the NHV determination, but
it does not reduce the number of samples required nor the
representativeness of those samples. As such, we consider it reasonable
to provide some flexibility in the grab sampling approach to allow
twice daily sampling to determine the average NHV of the gas stream for
14 operating days, with no sampling day spaced more than 3 operating
days apart from the previous sampling day.
b. Sampling Location and Duration
Comment: Several commenters expressed support for the EPA's
proposed revision to allow NHV sampling at a representative location.
Specifically, one of the commenters supported the proposed revisions to
clarify that NHV sampling may be conducted ``on the inlet gas which is
routed to the enclosed combustion device or flare'' to allow NHV
sampling to occur at a representative location.\140\
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\140\ Document ID No. EPA-HQ-OAR-2024-0358-0083.
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Another commenter stated that the EPA's January 2025 Proposal would
require that operators conduct the initial NHV demonstration sampling
on ``the inlet gas which is routed to the enclosed combustion device or
flare.'' \141\ The commenter noted that this may not address their
concerns. Specifically, the commenter expressed concern that control
devices receiving intermittent flow would require flaring solely for
the purpose of collecting samples for NHV analysis. Instead, the
commenter suggested the EPA should allow the option to collect samples
from the process that can be diverted to a control device, in addition
to collecting samples from the piping to the control device. For
example, for associated gas control devices, the commenter stated that
the operator could collect a sample from the on-pad sales gas system
before entering the sales pipeline, rather than having to divert sales
gas to a control device to collect a sample from the piping to the
control device. In addition, the commenter urged the EPA to allow the
collection of NHV samples from representative facilities, and they
contended that operators should be allowed to collect representative
samples if the sample originates from a representative well site or
centralized production facility.
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\141\ Document ID No. EPA-HQ-OAR-2024-0358-0092.
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Several commenters stated that the NHV demonstration should allow
for ``representative'' grab sampling and that the proposal may not go
far enough in allowing this flexibility. One commenter explained that
the proposed requirement to conduct sampling at ``the inlet gas which
is routed to enclosed combustor or flare'' is unclear, given the EPA's
statement that the change ``will clarify that sampling upstream of the
inlet to the control device is allowed, provided that the sample is
representative of the gas inlet to the control device.'' \142\ The
commenter stated their concern that ``upstream of the inlet of the
control device'' is limiting and that the EPA should allow sampling
from anywhere in the process that is representative of the gas that
would be routed to the flare. As an example, the commenter described an
associated gas process stream that can route to a sales line or a
control device and stated that the rule should allow the operator to
collect a sample from a location in the process going to the sales
line, rather than along the piping or at the inlet to the control
device. The commenter explained that, if required to collect the sample
from the latter, the operator must divert gas to the flare that would
otherwise go to sales, resulting in unnecessary emissions. Further, the
commenter stated that if multiple streams route to the control device,
it should be necessary only to sample the stream which the operator
expects to have the lowest NHV. The commenter stated that the EPA
proposed that ``sampling may be conducted from a location on the
control device piping header, provided the sampling location is
downstream of all waste gas inlets into the header.'' The commenter
stated their concern that this suggests that the operator must route
all process streams to the control device to collect a sample,
downstream of the comingling point; this could require diverting
streams to the control device which normally routed to a non-emitting
process and would result in additional emissions. The commenter
provided as a solution that the EPA allow the operator to sample the
process stream with the lowest expected NHV and if that stream is above
the applicable NHV limit, it is unnecessary to sample the other, higher
NHV streams. Finally, the commenter requested that the final rule allow
operators to use samples from nearby, representative facilities that
produce from the same reservoir/formation and have similar operating
conditions and equipment. The commenter concluded that it is reasonable
to expect these facilities to have very similar gas compositions and
NHV.
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\142\ Document ID No. EPA-HQ-OAR-2024-0358-0088.
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Regarding the minimum one-hour sampling times for collecting NHV
samples, several commenters contended that it is unnecessary to conduct
one-hour sampling. One of the commenters \143\ indicated that the EPA
proposes that the collection time for an individual NHV sample may be
less than one hour when it is not technically feasible (e.g., low or
intermittent), but the collection time must be as long as possible up
to one hour. The commenter stated that while the proposed revision
partially alleviates their concerns with sampling duration, it does not
recognize that a one-hour sample collection time is unnecessary and
should be removed. The commenter explained that typical sampling
techniques require only a few minutes to collect a valid sample for NHV
analysis, regardless of the flow conditions. According to the
commenter, collecting or trying to collect a sample for an entire hour
is unnecessary to demonstrate compliance with the minimum vent gas NHV
requirement since the vent gas NHV of a stream is not expected to vary
much within that hour.
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\143\ Document ID No. EPA-HQ-OAR-2024-0358-0083.
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[[Page 18086]]
Other commenters stated that one-hour sampling is contrary to the
norms of sampling.\144\ One commenter noted that while the proposal
allows for reduced sampling where it is technically infeasible to
conduct a one-hour sample due to LP or intermittent gas flow, which
addresses technical infeasibility issues they raised in prior comments,
it remains unnecessary to require the collection of a one-hour sample
in any event.\145\ The commenter requested that the EPA finalize the
representative grab sampling revisions that they provided for NSPS
OOOOb and include the same revisions in EG OOOOc.
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\144\ See SPL, Inc., SPL Letter to EPA, 1-2, EPA-HQ-OAR-2024-
0358-0038-0032 (March 19, 2024) (``March SPL Letter'').
\145\ Document ID No. EPA-HQ-OAR-2024-0358-0088.
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Another commenter stated that for the NHV demonstration in 40 CFR
60.5417b(d)(8)(iii)(A) and (F), the EPA proposes to retain the one-hour
minimum sampling time for twice-daily samples, except in cases where
sampling for one hour is technically infeasible on LP or intermittent
gas streams.\146\ The commenter supported allowing an offramp for the
one-hour minimum sampling time, and they suggested that the EPA go
further and allow the use of representative grab samples for the
initial compliance demonstrations requirements, rather than requiring a
one-hour sample period.
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\146\ Document ID No. EPA-HQ-OAR-2024-0358-0092.
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Conversely, two commenters expressed that they do not support
shorter sampling times. More specifically, a sample collected over a
specified period of time (e.g., one hour) is considered a composite
sample because the sample collected is a ``composite'' of the gases
which flowed through the source location over that specified time
period, but a grab sample is considered a moment in time.\147\
According to one commenter, there is a significant risk that the
combination of the allowance for the use of Tedlar bags and the use of
the term ``grab sample'' will replace the needed one-hour composite
sample with a short duration sample. The commenter reported that over
the past year, many samples collected to comply with NSPS OOOOb did not
meet the minimum one-hour collection period. The commenter stated that
early testing, which attempted to comply more with the one-hour
collection periods, resulted in high test failure rates. The commenter
asserted that in order to resolve these high test failure rates,
without implementing the evacuated containers, heated lines, and other
needed sampling system items, industry simply shortened the duration of
collection. The commenter stated that industry has shown the
compositions and the associated calculated NHVs of the flare/ECD gas
will highly vary over the one-hour collection period. Accordingly, the
commenter stated, a short duration sample will not be representative of
combustion gases. According to the commenter, this issue is further
complicated by the EPA's proposal to allow for shorter duration testing
as stated in the January 2025 Proposal.
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\147\ Document ID No. EPA-HQ-OAR-2024-0358-0084, -0096.
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According to the commenter, the industry collected one-hour samples
at thousands of flares over the past year, in compliance with NSPS
OOOOb and throughout the prior NSPS OOOOa testing. The commenter noted
that tests show that the collection of gases has been technically
feasible. In cases where the industry has struggled to produce
compliant results as a result of collection practices, facility
constraints, cost, and existing testing infrastructure the industry has
claimed the testing itself is not feasible, cautioned the commenter.
Response: As noted in the January 2025 Proposal, the EPA does not
believe it is necessary to specify that sampling may occur at another
``representative'' location or to specify such ``representative''
locations, and we assert that our clarification in the January 2025
Proposal that sampling may be conducted upstream of the inlet to the
control device, provided that the sample is representative of the gas
inlet to the control device, is sufficient. This is imperative
considering that the finalized NHV sampling requirements will entail
miscellaneous operating scenarios, where sampling further upstream of
the control device (or at ``representative facilities'') would not
provide a representative NHV sample. We recognize that some case-by-
case determinations may be necessary due to the number of potentially
affected sources, and potential operating design configurations. As
previously noted in section IV.B.3 of this preamble, the General
Provisions in 40 CFR part 60 include procedures for alternatives to
monitoring, including alternative locations for monitoring ``when the
owner or operator can demonstrate that installation at alternate
locations will enable accurate and representative measurements.'' \148\
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\148\ See footnotes 48 and 49.
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Regarding the proposed provision to allow sampling times of less
than one hour, the EPA notes that it will still require a minimum one-
hour sample duration, except in cases where low or intermittent flow
makes one-hour sampling infeasible for both NSPS OOOOb and EG OOOOc
sources. The EPA recognizes that NHV content can vary over a given
sampling period. However, the EPA also recognizes that industry has
demonstrated that there can be some cases where sampling for a minimum
period of one-hour may not be physically possible in certain
situations. Accordingly, the EPA is allowing less than one-hour
sampling times for cases where low or intermittent flow is present,
provided that the sampling time used and the reason for the reduced
sampling time is documented and reported and that the samples were
taken during the period with the lowest expected NHV (i.e., the period
with the highest percentage of inerts). While sampling for a period of
less than one hour is not considered ideal, the EPA believes that the
NHV content during this shorter sampling period should be
representative of the NHV content for that particular period of
operation, which should also be indicative of the NHV content for that
source had a one-hour sample been obtained. In turn, if there is any
variance in the NHV content, it would then be reflected in the multiple
samples taken over the course of the entire sampling program.
4. Methodologies for Compositional Analysis of the Gas Stream
The EPA reconsidered the requirements in the March 2024 Final Rule
that limited the test method for determining the compositional analysis
of the gas stream to American Society for Testing and Materials (ASTM)
D1945-14 (R2019). The EPA recognizes that other rules in which vent
gases are analyzed, such as 40 CFR part 63, NESHAP subpart CC (Refinery
MACT)), allow the use of other test methods. In the January 2025
Proposal, the EPA solicited comment to expand the use of similar
consensus-based standards (e.g., GPA Midstream 2166 and GPA Midstream
2261) to consider if these additional available methods would alleviate
petitioners' concerns that ASTM D1945-14 is not widely available and
that testing laboratories do not have the capacity currently to enable
its use.
In the January 2025 Proposal, the EPA also proposed to clarify that
Tedlar bags may be used to satisfy the grab sampling requirements,
provided that the Tedlar bag qualifies as an ``evacuated container'' as
prescribed by section
[[Page 18087]]
8.2.1.1 of EPA Method 18. We requested comment on the need to clarify
that Tedlar bags can be used and the limitation proposed on when Tedlar
bags can be used.
Comment: Several commenters suggested that the EPA expand the use
of consensus-based standards to those commonly and readily used by the
oil and gas industry. These include, but are not limited to, the
following:
Combined Standards API MPMS 14.1 (8th ed.)/GPA 2166 (22)--
Collecting and Handling of Natural Gas Samples for Analysis by Gas
Chromatography
GPA 2261--Analysis for Natural Gas and Similar Gaseous
Mixtures by Gas Chromatography
One commenter stated that this will allow the operators to use the
same service providers and laboratories retained for their other
operations and ensure adequate capacity.\149\ Additionally, these
service providers and laboratories have typically been thoroughly
vetted and audited by the operators and have been proven to provide
accurate and defensible data.
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\149\ Document ID No. EPA-HQ-OAR-2024-0358-0084.
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Another commenter remarked that including these consensus-based
standards will alleviate concerns that ASTM D1945-14 is not widely
available and that testing laboratories do not currently have the
capacity to support its use.\150\ Furthermore, this commenter contended
that ASTM D1945-14 is inappropriate for well sites, centralized
production facilities, compressor stations, and gas plants since it
evaluates components not typically found in vent gas from these
operations (e.g., helium). The commenter noted that concerns expressed
about the availability of labs, analysis time, and cost with ASTM
D1945-14 have not changed since the commenter submitted its previous
reconsideration letter.
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\150\ Document ID No. EPA-HQ-OAR-2024-0358-0083.
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One commenter stated that GPA Midstream 2261 is equivalent to ASTM
D1495-14D1945 in constituents, has a broader range of heavier
hydrocarbons, elutes all gases sequentially without material peak
overlap (including nitrogen and methane), meets the regulatory
requirements of 40 CFR 60.54717b(d)(8), and employs thermal
conductivity detectors.\151\ The commenter provided a detailed
analysis/rationale for each of these factors in its comment letter.
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\151\ Document ID No. EPA-HQ-OAR-2024-0358-0089.
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Several commenters expressed that allowing more test methods would
help lab capacity issues but may lead to inconsistent results. One
commenter suggested that it is essential to ensure that all approved
methods provide equally accurate and precise data.\152\
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\152\ Document ID No. EPA-HQ-OAR-2024-0358-0078.
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Regarding Tedlar bags, one commenter suggested that Tedlar bags be
excluded from use for the collection of flare gas samples.\153\ The
commenter explained that Tedlar bags are not designed for the
compositions and sampling handling requirements of typical flare gas.
The commenter stated that the January 2025 Proposal cites section
8.2.1.1 of EPA Method 18. According to the commenter, EPA Method 18 is
not a valid method for the collection and analysis of the gas typically
found in flares. Section 1.2.1 of EPA Method 18 states, ``[t]his method
is designed to measure gaseous organics emitted from an industrial
source. While designed for parts per million (ppm) level sources, some
detectors are quite capable of detecting compounds at ambient levels,
e.g., ECD, ELCD, and helium ionization detectors.'' The commenter
asserted that this method, and its allowed use of Tedlar bags, was
designed for ppm level and ambient sources and that it was not designed
and validated for percent level gaseous compounds, as found in typical
flare gas. According to the commenter, the more appropriate EPA method
for the sampling of the typical compositions and compound
concentrations found in flare gas is EPA Method 0040, Sampling of
Principal Organic Hazardous Constituents from Combustion Sources Using
Tedlar Bags. However, the commenter stated that EPA Method 0040 clearly
states that Tedlar bags are not applicable for the compounds typically
found in flare gas. The commenter stated that hydrocarbon contamination
contributed by the Tedlar bag has the potential of distorting the
sample and biasing the NHV high. Therefore, the commenter suggested
that Tedlar bags be excluded from use for flare gas sampling.
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\153\ Document ID No. EPA-HQ-OAR-2024-0358-0084.
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Another commenter recommended that the final rule allow for the use
of single cavity stainless steel constant volume cylinders as a vent
gas collection method.\154\ The commenter stated that the EPA proposed
to allow Tedlar bags as an alternative sample collection method. The
commenter agreed that alternative sample collection methods are
necessary, as Summa canisters are not a good option for vent gas
collection. The commenter strongly supported allowing Tedlar bags as an
alternative sample collection method. In addition, the commenter
requested that the EPA clarify that operators and laboratories may
collect grab samples using single cavity stainless steel constant
volume cylinders for sample collection, so long as they are maintained
according to the requirements set forth in 43 CFR 3175 (Onshore Oil and
Gas Operations; Federal and Indian Oil and Gas Leases; Measurement of
Gas).
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\154\ Document ID No. EPA-HQ-OAR-2024-0358-0092.
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Several commenters supported the use of Tedlar bags over air
sampling canisters primarily due to cost, convenience, and ease of
handling. One commenter explained that cleaning canisters is nearly
impossible, particularly for rich gas streams (such as those from
storage vessels), which leave residuals in canisters and further
complicate cleaning and reuse.\155\ The commenter explained that the
conditioning of Tedlar bags is easier (as they fit easily into standard
heating ovens), and Tedlar bags are available in larger quantities per
shipment (which makes getting supplies easier).
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\155\ Document ID No. EPA-HQ-OAR-2024-0358-0089.
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Response: The EPA acknowledges that allowing additional test
methods, especially GPA Midstream 2261 (which was the most cited
addition to testing method options), would provide additional
flexibility to sources, as well as potential relief to analytical
laboratories with substantial backlogs. Since GPA 2261 utilizes the
same analytical equipment, including a similar procedure as the
existing standard method, and generally provides equivalent results, we
are allowing this method as an option (as GPA 2261-19) in the final
rule for all sources. For those owners or operators with streams
expecting a significant concentration of inert compounds, they should
conduct the analysis according to ASTM D1945 or utilize the ``single
column method'' in Section 2.1.4 of GPA 2261. Due to the concerns
expressed by several commenters about potential issues that could arise
from allowing the use of Tedlar bags to satisfy the grab sampling
requirements specified by NSPS OOOOb and EG OOOOc, we will not be
revising the sample media requirements for canisters currently
specified by 40 CFR 60.5413b(d)(5), 60.5417b(d)(8), 60.5413c(d)(5), and
60.5417c(d)(8).
[[Page 18088]]
5. NHVcz and NHVdil for Air- and Steam-Assisted
Flares and Enclosed Combustion Devices at Existing and New Sources
In the January 2025 Proposal, the EPA proposed to retain the
NHVcz and NHVdil requirements for air- and steam-
assisted flares for sources subject to NSPS OOOOb because, as noted in
the November 2021 Action (86 FR 63246; November 15, 2021), we had
received some data indicating that air- and steam-assisted flares have
been found operating outside of the conditions necessary to achieve at
least 98 percent control efficiency on a continuous basis. In the
January 2025 Proposal, we disagreed with petitioners that these NHV-
related parameters are not appropriate for assisted flares in the oil
and gas industry, because we had evidence of poor-performing assisted
flares in the oil and gas industry. We, therefore, proposed to conclude
(as we had in the March 2024 Final Rule) that sufficient evidence
exists demonstrating poor destruction efficiencies due to over-
assisting a flare or ECD, and thus NHV compliance demonstrations are
necessary to show that these particular control devices meet the
requisite efficiency. The EPA requested comment on the proposed
retention of the NHVcz and NHVdil provisions for
new sources. We also requested comment on whether the NHVdil
parameter is appropriate for ECD with perimeter assist air and the
appropriate effective diameter to use in the calculation of
NHVdil, if it is retained, particularly for devices with
multiple burner tips within the ECD.
Regarding statements that 40 CFR 60.5417b(d)(8)(iii)(H) appears to
not allow alternative test methods to continuously monitor
NHVcz and NHVdil, we noted that the provisions at
40 CFR 60.5417b(d)(8)(iii) are specific to the 14-day alternative
performance test (sampling demonstration) option and do not apply to
continuous monitoring. We did not include provisions for a 14-day
demonstration using continuous monitoring of NHVcz and
NHVdil because assist rates could be changed and alter the
control device's performance. Continuous monitoring using alternative
test methods is expressly provided for in 40 CFR 60.5412b(d) and
60.5415b(f)(1)(xi). Additionally, we proposed to clarify in 40 CFR
60.5417b(d)(8)(vi) that continuous monitoring of NHVcz and,
if applicable, NHVdil using an approved alternative method
as provided under 40 CFR 60.5412b(d)(1)(i) and (ii) is allowed and
that, when using this alternative test method, owners and operators are
not required to monitor NHV of the vent gas as specified in 40 CFR
60.5412b(d)(8)(ii) or monitor flow rates as specified in 40 CFR
60.5412b(d)(8)(vi) provided they can demonstrate that the maximum flow
rate to the flare cannot cause the flare tip velocity to exceed 18.3
meter/second (60 feet/second). The EPA requested comment on the
proposed clarifications when using the alternative test method to
demonstrate continuous compliance and requested comment on whether and
how to use such monitoring as part of the 14-day sampling
demonstration.
With respect to the monitoring requirements for NHVcz
and NHVdil for air- and steam-assisted flares at new
sources, the EPA acknowledged the petitioners' concerns but did not
propose significant changes to this requirement for new sources subject
to NSPS OOOOb. However, in reviewing these requirements, we noted that
the requirements in 40 CFR 60.5417b(d)(8)(vi) reference NHV
determinations using the lowest NHV result of the sampling
demonstration in 40 CFR 60.5417b(d)(8)(iii), but 40 CFR
60.5417b(d)(8)(iii) does not have provisions for steam-assisted nor for
certain air-assisted flares or ECD. Therefore, we proposed to clarify
that 40 CFR 60.5417b(d)(8)(iii) can be used for any steam- or air-
assisted flare (including perimeter assist air) or ECD, and that the
effective vent gas NHV to allow the use of the demonstration is 300
Btu/scf when using continuous 14-day sampling or 360 Btu/scf when using
the 14-day grab sampling approach. This revision in 40 CFR
60.5417b(d)(8)(iii) is necessary considering the calculation provision
in 40 CFR 60.5417b(d)(8)(vi) and corrects an unintended error in the
March 2024 Final Rule. The EPA also requested comment on the use of the
proposed use of the 14-day sampling demonstration in 40 CFR
60.5417b(d)(8)(iii) for air- and steam-assisted flares, particularly
those at new sources subject to the NHVcz and
NHVdil requirements.
With the alternative sampling provisions being proposed in 40 CFR
60.5417b(d)(8)(iii) and the assessments outlined in 40 CFR
60.5417b(d)(8)(iv), we expect that few facilities will need to install
continuous monitoring systems. With the monitoring options provided, we
considered the costs of the monitoring provisions to be reasonable and
necessary to ensure proper operation of these flares at new sources and
therefore retain the NHVcz and NHVdil
requirements in NSPS OOOOb.
Conversely, the requirement to conduct monitoring for
NHVcz and NHVdil at existing sources was included
in EG OOOOc in error. The EPA did not conduct Refinery MACT cost level
monitoring for existing sources and stated in the preamble to the March
2024 Final Rule that monitoring of NHVcz and
NHVdil was not required for existing sources due to concerns
about retrofitting existing flares to meet the requirements.\156\ The
EPA proposed to correct this inadvertent error by removing the
requirements to conduct monitoring of NHVcz and
NHVdil at existing sources and specifying the requirements
for these control systems is an NHV of 300 Btu/scf in the vent gas. The
EPA requested comment on the appropriateness of using an NHV of 300
Btu/scf in the vent gas for air- and steam-assisted flares or ECD at
existing sources for demonstrating compliance with the combustion
efficiency requirements for these control devices.
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\156\ 89 FR 16895, 16967 (March 8, 2024).
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Comment: The EPA received numerous comments regarding the
NHVcz and NHVdil provisions discussed in the
January 2025 Proposal, many of which were out-of-scope from the
proposal. Regarding the issues for which the EPA specifically requested
comment, one commenter \157\ noted that for new NSPS OOOOb sources, the
EPA proposed to retain the NHVcz and NHVdil
requirements, which is already a Refinery MACT requirement. The
commenter reminded the EPA that petitioners provided data, experience,
and knowledge on why these testing requirements are inappropriate
(e.g., non-steady state flow) and are excessively costly ($1 million or
more). The commenter requested that the EPA remove this requirement
from the proposed rule.
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\157\ Document ID No. EPA-HQ-OAR-2024-0358-0095.
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Conversely, one commenter \158\ believed the Agency should retain
the requirement to monitor NHVcz and NHVdil for
air- and steam-assisted flares and ECD at new NSPS OOOOb sources. The
commenter agreed with the EPA's statement in the proposed rule that
there is sufficient evidence to demonstrate that over-assisting a flare
or ECD leads to poor destruction efficiencies, necessitating NHV
compliance demonstrations. The commenter also agreed that the
NHVcz and NHVdil parameter terms account for the
reduction in heating value caused by the introduction of air or steam
and that requiring compliance with the NHVcz and
NHVdil limits for air- and steam-assisted flares and ECD
constitutes BSER under CAA section 111(a)(1).
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\158\ Document ID No. EPA-HQ-OAR-2024-0358-0086.
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[[Page 18089]]
Regarding the alternative test method option to demonstrate
continuous compliance and whether and how to use such monitoring as
part of the 14-day sampling demonstration for air- and steam-assisted
flares, particularly those at new sources subject to NHVcz
and NHVdil requirements, one commenter \159\ stated that
although NSPS OOOOb includes provisions for alternate test methods and
alternate NHVcz and NHVdil demonstrations in lieu
of monitoring, those alternatives may not be feasible for every control
device. For example, the commenter stated that OTM-56 can only be used
for flares since the Video Imaging Spectral Radiometer (VISR) camera
needs a clear view of the flame. The commenter explained that alternate
test methods are costly to implement and take time for Agency approval,
so they are not an option for immediate compliance and unlikely to be
used by small operators. Moreover, the alternate NHVcz and
NHVdil demonstrations are problematic given the intermittent
operation of control devices at production sites, explained the
commenter.
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\159\ Document ID No. EPA-HQ-OAR-2024-0358-0083.
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Another commenter \160\ urged the EPA to remove the
NHVcz and NHVdil requirements for all control
devices subject to NSPS OOOOb. The commenter explained that oil and
natural gas facilities are fundamentally different than petroleum
refineries in that they do not operate at steady state conditions. The
commenter explained that this highly variable, non-steady state flow
mandates that equipment be sized much larger than ideal steady state
conditions and makes flow measurement infeasible. The commenter
explained that costs are also an issue, in that upstream facilities do
not have the necessary utilities and instrumentation resources that a
refinery has, nor do they have instruments that can operate reliably
under the varying operating conditions found at oil and natural gas
facilities. The commenter added that the alternative NHVcz
and NHVdil demonstrations also are problematic, given that
the production site does not operate under steady state conditions.
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\160\ Document ID No. EPA-HQ-OAR-2024-0358-0088.
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Regarding the appropriateness of using an NHV of 300 Btu/scf in the
vent gas for air- and steam-assisted flares or ECD at existing sources
for demonstrating compliance with the combustion efficiency
requirements for these control devices, one commenter \161\ stated that
EG OOOOc air- and steam-assist flare vent gas limit of 300 Btu/scf is a
reasonable alternative to the NHVcz and NHVdil
limits. The commenter supported the flare vent gas limit of 300 Btu/scf
as a reasonable alternative to the NHVcz and
NHVdil limits in EG OOOOc. The commenter noted that the EPA
did not conduct Refinery MACT cost level monitoring for existing
sources and stated in the preamble to the March 2024 Final Rule that
monitoring of NHVcz and NHVdil was not
recommended as part of the EGG for existing sources due to concerns
about retrofitting existing flares to meet the requirements.
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\161\ Document ID No. EPA-HQ-OAR-2024-0358-0094.
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Response: While some commenters have requested that the removal of
NHVcz and NHVdil requirements from NSPS OOOOb,
the EPA has made it clear that these monitoring requirements are
appropriate and necessary for these types of devices, as there is
sufficient evidence to demonstrate that over-assisting a flare or ECD
leads to poor destruction efficiencies, necessitating NHV compliance
demonstrations (i.e., it is understood that inert gases can be
introduced to steam-assisted, air-assisted, and perimeter assist air
flares). However, the EPA recognizes that the operation of control
devices at oil and natural gas facilities can be fundamentally
different than petroleum refineries, which also have NHVcz
and NHVdil requirements prescribed under the Refinery MACT.
The EPA believes that this final rule, which will impose NHV sampling
requirements for only those sources and situations where inert gases
are present or under miscellaneous operating scenarios that may lower
the NHV of the inlet gas stream, will result in a more manageable
monitoring and testing situation industry-wide, and allow the
evaluation of certain situations on a case-by-case basis. As previously
noted in section IV.B.3 of this preamble, the General Provisions in 40
CFR part 60 include procedures for alternatives to monitoring,
including alternative locations for monitoring ``when the owner or
operator can demonstrate that installation at alternate locations will
enable accurate and representative measurements''.\162\
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\162\ See footnotes 48 and 49.
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Based on our analysis of the data submitted by industry, we find
that gas streams expected to be routed to a flare or ECD at sites that
do not have sources with inerts will have a NHV of well over 800 Btu/
scf. At these high NHVs, we expect that facilities will always be
compliant with the NHVcz or NHVdil operating
limits, even at low flare gas flow rates. Because of the high assurance
that these flares or ECD will operate at a high efficiency at all times
that vent gas is directed to the devices, we find it reasonable to
exempt these flares and ECD from the monitoring and compliance
requirements, provided that these devices do not receive streams with
inerts that can lower the NHV inlet to the flare or ECD. When inerts
are included in the inlet gas stream, it is much more likely that the
NHV of the vent gas would fall below 800 Btu/scf and that the
NHVcz or NHVdil will fall below the Btu content
thresholds. Therefore, we are finalizing the requirement to conduct
assessments or monitor NHV and flows to determine continuous compliance
with the NHVcz or NHVdil operating limits in
cases where inert gases are added or for other miscellaneous scenarios
which decrease the NHVcz or NHVdil content of the
inlet stream gas to all flare and ECDs for new sources.
The EPA did not receive adverse comments on the proposal to
increase the minimum NHV content threshold from 270 to 300 Btu/scf for
air- or steam-assisted flares or ECD for existing EG OOOOc sources.
Hence, the EPA is finalizing this aspect of the rule as proposed.
The EPA did not receive specific comments on whether the
NHVdil parameter is appropriate for ECD with perimeter
assist air and the appropriate effective diameter to use in the
calculation of NHVdil, particularly for devices with
multiple burner tips within the ECD. Hence, the EPA is finalizing these
aspects of the rule as proposed.
No additional changes are being made to the NHVdil and
NHVcz requirements at this time based upon other comments
and suggestions received, which are considered out-of-scope for this
rulemaking.
6. Other Miscellaneous Comments on the NHV Provisions
The following subsections describe other miscellaneous provisions
of the NSPS OOOOb and EG OOOOc rules that pertain to NHV sampling that
the EPA either wishes to address or clarify based upon comments
received regarding the January 2025 Proposal.
a. NHV Temperature Basis
In the January 2025 Proposal, the EPA proposed to clarify that the
NHV of the vent gas stream must be determined in Btu/scf and not Btu/
lb, where the standard condition temperature is 20[deg]C. More
specifically, regarding the units in which the NHV is determined as
prescribed in the March 2024 Final Rule, we do not disallow the use of
[[Page 18090]]
measurement methods that determine concentrations in terms of weight
fractions, but the weight fractions must be converted to volume
fractions because the calculations referenced therein from 40 CFR part
63 use Btu/scf, not Btu/lb. Therefore, we did not propose to change the
units in the March 2024 Final Rule but rather proposed to clarify that
NHV for individual components must be determined in units of Btu/scf
consistent with the existing specification using published values of
the component NHV per mole at 25[deg]C and one atmosphere and using
20[deg]C as the standard temperature for determining the volume
corresponding to one mole of vent gas. We proposed to clarify that
since the standard temperature at 40 CFR 60.18(f)(3) is 20[deg]C, the
NHV under NSPS OOOOb and EG OOOOc must be determined at this standard
temperature. The Agency proposed these clarifications to ensure the NHV
determinations are conducted consistently and accurately.
The EPA received only supporting comments on this issue and is
finalizing this clarification as proposed.
b. Averaging Periods
In the January 2025 Proposal, the EPA also proposed to clarify that
for the purpose of determining the hourly average of the NHV for
continuously sampled (i.e., sampled continuously for 14 consecutive
days) inlet streams, the hourly average shall be determined on a block
(and not a rolling) average. The EPA proposed this clarifying edit to
ensure that all owners and operators are using the same averaging
timeframe and that it is not left to individual interpretation whether
the average should be a block average or a rolling average. Block
averages are required for other averaging time periods in the March
2024 Final Rule, and we consider this change to be warranted for
consistency and clarity.
The EPA received no comments on this issue and is finalizing this
clarification as proposed.
c. Compliance Timing and Deadlines
The EPA also proposed a change to address compliance timing pending
the re-evaluation that must occur after a process change that
potentially reduces the NHV of the gas sent to an flare or ECD. More
specifically for continuous monitoring, which must occur after the
results of periodic monitoring indicate the vent stream is not
sufficiently above the required NHV, we proposed that continuous
monitoring should commence within 60 days after the re-evaluation
indicates that the inlet gas stream does not meet the limits. The EPA
also proposed to clarify, for both periodic testing and re-evaluations
which occur after a process change, that if the results of the grab
sampling indicate that the vent stream is not sufficiently above the
required NHV, continuous monitoring using a calorimeter, GC, MS, or
continuous grab sampling (i.e., once every eight hours) must commence
within the specified timeframe.
The EPA received no comments on this issue and is finalizing this
clarification as proposed.
V. How do these final amendments impact the implementation of EG OOOOc?
The EPA's final amendments discussed in section III of this
preamble will not significantly impact the implementation of EG OOOOc
or the State planning process. Based on the EPA's reconsideration, we
are finalizing amendments that revise two narrow aspects of the EG: the
associated gas temporary flaring provisions for certain situations, and
the NHV continuous monitoring and alternative performance test
(sampling demonstration) provisions for certain combustion control
devices. These final amendments do not alter in any way the EPA's
identified BSER in the EG, or the EPA's identified degree of emissions
limitation achievable via application of that BSER. Any changes that a
State or Tribe may make to their developing plan as a result of this
final action will be minor, and the State or Tribe should be able to
make such changes before their plans are required to be submitted for
approval. The EPA does not anticipate that States will require
additional time for State plan submittal solely because of the changes
finalized in this rulemaking.
However, after the January 2025 Proposal was published, the EPA
published an IFR to extend certain deadlines pertaining to the March
2024 Final Rule in July 2025 and later issued a final rule in December
2025 confirming those amendments and making further changes to the
compliance deadlines in the IFR related to NHV monitoring and the
initial reporting deadline.\163\ Relevant to this discussion, in the
IFR, the EPA extended the State plan submittal deadline in EG OOOOc
from March 9, 2026, to January 22, 2027.
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\163\ 90 FR 35966 (July 31, 2025) and 90 FR 55671 (December 3,
2025).
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As indicated in section I.B of this preamble, the issuance of the
CAA section 111(d) final EG does not impose binding requirements
directly on existing sources. The EG (codified in 40 CFR part 60,
subpart OOOOc) applies to States in the development, submittal, and
implementation of State plans to establish performance standards to
reduce emissions of GHGs from designated facilities (those that were
existing sources on or before December 6, 2022). Further, under the
TAR, eligible Tribes may seek approval to implement a plan under CAA
section 111(d) in a manner similar to a State, and Tribes are
authorized under the TAR to develop and implement their own air quality
programs, or portions thereof, under the CAA. The response to comments
on the January 2025 Proposal on this section of this preamble is in the
EPA's RTC document for the final rule.\164\
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\164\ Reconsideration of Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review.
Response to Public Comments on the January 2025, Proposed Rule (90
FR 3734; January 15, 2025).
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VI. Statutory and Executive Order Reviews
Additional information about these statutes and Executive Orders
(EO) is available at https://www.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is a significant action under E.O. 12866 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, Economic Impact
Analysis for 2025 Oil and Natural gas NSPS & EG Reconsideration, is
available in the docket.
We present the estimated PV and EAV of the estimated cost savings
of this final reconsideration in 2024 dollars over the 2024 to 2038
period. The cost savings are represented in this analysis as the
reduction in the number of affected sources and a reduction in the
number of tests required for each affected source for the changes
finalized in this reconsideration. In simple terms, these cost savings
are an estimate of the decreased industry expenditures resulting from
the final changes to the March 2024 Final Rule requirements. Under this
final action, emissions changes and benefits from emission changes were
not quantified, nor were
[[Page 18091]]
cost changes from the temporary flaring provisions. Qualitatively, the
changes to the temporary flaring limitation could result in cost
savings and increases to emissions, while we do not expect any
emissions changes to result from the changes to the NHV testing
compliance demonstration.
Table 3 presents the estimated cost savings of this proposed action
in 2024 dollars for the baseline which includes the March 2024 Final
Rule (i.e., the primary baseline analyzed in the EIA).
(i.e., the primary baseline analyzed in the EIA). This table
presents the PV and EAV of these estimates discounted at three percent
and seven percent.
Table 3--Present Value and Equivalent Annualized Value of Compliance
Cost Savings Estimates of the Final Action From 2024-2038
[Millions of 2024$]
------------------------------------------------------------------------
3 percent 7 percent
discount discount
rate rate
------------------------------------------------------------------------
Present Value..................................... 2,480 1,900
Equivalent Annualized Value....................... 208 209
------------------------------------------------------------------------
The analysis, which is contained in the Economic Impact Analysis for
this rulemaking, is consistent with E.O. 12866 and is available in the
docket for this action.
B. Executive Order 14192: Unleashing Prosperity Through Deregulation
This action is considered an Executive Order 14192 deregulatory
action. Details on the estimated cost savings of this final rule can be
found in the EPA's analysis of the potential costs and benefits
associated with this action.
C. Paperwork Reduction Act (PRA)
OMB has approved the information collection activities contained in
this rule under the PRA and has assigned OMB control number 2060-0721
to NSPS OOOOb and EG OOOOc. You can find a copy of the information
collection request (ICR) in the docket for this rule, and it is briefly
summarized here. The EPA has revised the approved ICR to include small
changes to incorporate the EPA's final recordkeeping and reporting to
indicate whether the flare or ECD receives inert gases or other streams
which may lower the NHV of the combined stream as discussed in section
III.B of this preamble. The EPA estimates an average of 48 respondents
will be affected by this requirement over the three-year period (2024-
2026). The average annual burden for the recordkeeping and reporting
requirements for these owners and operators is estimated at 83 person-
hours, with an average annual cost of $6,393 (2024$) over the three-
year period.
The EPA has also revised the approved ICR to include burden
estimates for the maintenance of records associated with the final
requirements. Specifically, the EPA includes burden estimates in the
revised ICR for the records and annual reporting included in the final
rule related to the use of the associated gas extended flaring
allowance under ``exigent circumstances'' as specified in section III.A
of this preamble. The incremental increase in burden that would be
associated with these recordkeeping and reporting requirements relative
to the baseline is estimated at two hours per event annually over the
three-year period (2024-2026) at an average annual cost of $176 per
flaring event over the three-year period. The occurrence of flaring
that could potentially be claimed due to ``exigent circumstances'' is
unknown. However, we expect that a maximum of 16 percent of flaring
events could potentially require an owner or operator to need to extend
flaring beyond 72 hours due to ``exigent circumstances.''
The burden associated with the two aforementioned requirements
under this final action minimally affects the ICR burden estimated for
compliance with EG OOOOc with an estimated annual cost increase of less
than one percent for the States. Provided below is a summary of the ICR
burden associated with the final notification, recordkeeping and
reporting requirements.
Respondents/affected entities: Oil and natural gas owners and
operators.
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: 48.
Frequency of response: Annually.
Total estimated burden: 86 hours per year. Burden is defined at 5
CFR 1320.3(b).
Total estimated cost: $6,570 per year (2024$). There are no capital
or operation and maintenance costs.
An agency may not conduct or sponsor, and a person is not required
to respond to, an ICR 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.
The approved ICR document that the EPA prepared was assigned OMB
Control No. 2060-0721 and EPA ICR number 2523.07. You can find a copy
of the previously submitted ICR in Docket EPA-HQ-OAR-2021-0317. The
revised ICR document that the EPA prepared for this reconsideration
final rule has been assigned OMB Control No. 2060-0721 and EPA ICR
number 2523.08. You can find a copy of the revised ICR in Docket EPA-
HQ-OAR-2024-0358.
D. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. In
making this determination, the EPA concludes that the impact of concern
for this rule is any significant adverse economic impact on small
entities and that the Agency is certifying that this rule will not have
a significant economic impact on a substantial number of small entities
because the rule has reduced net regulatory burden on the small
entities subject to the rule. This action addresses two discrete
compliance requirement aspects of NSPS OOOOb and the model rules within
EG OOOOc based on petitions for reconsideration received on the March
2024 Final Rule requirements,\165\ providing additional flexibilities
to entities subject to the NSPS requirements and to the model rules
within EG OOOOc. Specifically, those flexibilities include extending
the limitation on temporary flaring from 24 to 72 hours, granting
exemptions from monitoring for an expanded number of gas streams due to
high NHV content, allowing sampling to be conducted upstream of the
control device inlet for operators meeting the NHV compliance
demonstration via the alternative performance test, and allowing breaks
in performance testing over weekends and holidays during the 14-day
period for the performance test option. We have therefore concluded
that this action will have reduced net regulatory burden for all
directly regulated small entities. For instance, on average, we
estimate cost savings of roughly $19,000 per well site due to the
changes to the NHV testing provisions across all business size
classifications. For further details, see the document, Economic Impact
Analysis for 2025 Oil and Natural Gas NSPS & EG Reconsideration, in the
docket.
---------------------------------------------------------------------------
\165\ The EPA convened a Small Business Advocacy Review (SBAR)
Panel prior to the November 2021 Action that was ultimately
finalized in the March 2024 Final Rule.
---------------------------------------------------------------------------
E. Unfunded Mandates Reform Act (UMRA)
This action does not contain an unfunded mandate of $100 million or
more as described in UMRA, 2 U.S.C.
[[Page 18092]]
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. This action
addresses two discrete compliance requirement aspects of NSPS OOOOb and
the model rules within EG OOOOc based on petitions for reconsideration
received on the March 2024 Final Rule requirements.
F. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government. However,
the EPA recognizes that States will have a substantial interest in this
action and any future revisions to associated requirements. This action
addresses two discrete compliance requirement aspects of NSPS OOOOb and
the model rules within EG OOOOc based on petitions for reconsideration
received on the March 2024 Final Rule requirements.
G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have Tribal implications as specified in E.O.
13175. This action addresses two discrete compliance requirement
aspects of NSPS OOOOb and the model rules within EG OOOOc based on
petitions for reconsideration received on the March 2024 Final Rule
requirements. Thus, E.O. 13175 does not apply to this action. However,
consistent with the EPA Policy on Consultation with Indian Tribes, the
EPA offered consultation to all Federally Recognized Tribes during the
development of this action on December 23, 2024. No Tribes requested
consultation.
H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets E.O. 13045 as applying only to those regulatory
actions that concern environmental health or safety risks that the EPA
has reason to believe may disproportionately affect children, per the
definition of ``covered regulatory action'' in section 2-202 of the
E.O. The EPA believes that it is not practicable to assess whether an
environmental health risk or safety risk affecting children may exist
prior to this action. This action addresses two discrete compliance
requirement aspects of NSPS OOOOb and the model rules within EG OOOOc
based on petitions for reconsideration received on the March 2024 Final
Rule requirements and does not result in any changes to the BSER of
NSPS OOOOb or EG OOOOc. The EPA believes that the EPA's Policy on
Children's Health also does not apply.
Therefore, this action is not subject to Executive Order 13045
because it does not concern an environmental health risk or safety
risk. Since this action does not concern human health, EPA's Policy on
Children's Health also does not apply.
I. 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. Further, we have concluded that this
action is not likely to have any adverse energy effects because this
action addresses two discrete compliance requirement aspects of NSPS
OOOOb and the model rules within EG OOOOc based on petitions for
reconsideration received on the March 2024 Final Rule requirements and
does not result in any changes to the BSER of NSPS OOOOb or EG OOOOc.
J. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR
Part 51
This action does not involve any new technical standards.
Therefore, the NTTAA does not apply. In this rule, the EPA is including
regulatory text for 40 CFR part 60, subparts OOOOb and OOOOc that
includes incorporation by reference. In accordance with requirements of
40 CFR 60.17, the EPA is incorporating the following two standards by
reference.
GPA Standard 2261-19 (GPA 2261-19), Analysis for Natural
Gas and Similar Gaseous Mixtures by Gas Chromatography, (Revised 2019),
IBR approval requested for NSPS subpart OOOOb Sec.
60.5417b(d)(8)(ii)(D) and NSPS subpart OOOOc Sec.
60.5417c(d)(8)(ii)(D). This is a method for determining the chemical
composition of natural gas and similar gaseous mixtures using a Gas
Chromatograph. This method uses a gas chromatograph to separate and
quantify hydrocarbons and non-hydrocarbons. This information can be
used to calculate the Btu content of the natural gas sample.
ASTM D1945-14 (Reapproved 2019), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography, approved December 1,
2019; IBR approval requested for Sec. Sec. 60.5417b(d)(8)(ii)(D);
60.5417c(d)(8)(ii)(D). This method covers the determination of the
chemical composition of natural gases and similar gaseous mixtures
within the range of composition. The method uses gas chromatography to
physically separate the component in the sample and compares them
against calibration data from a reference standard. This method is used
to determine gas properties such as heating value.
The GPA 2261-19 standard is available at the GPA Midstream website
at the following location: GPA Midstream Association, 6060 American
Plaza, Suite 700, Tulsa, OK 74135; phone: (918) 493-3872; website:
www.gpamidstream.org. GPA offers memberships or subscriptions that
allows access to their methods.
ASTM D1945-14 is available at ASTM International, 1850 M Street NW,
Suite 1030, Washington, DC 20036. See https://www.astm.org/. This
standard is available to everyone at a cost determined by the ASTM
($96). The ASTM also offers memberships or subscriptions that allow
unlimited access to their methods. The cost of obtaining these methods
is not a significant financial burden, making the methods reasonably
available to stakeholders.
K. Congressional Review Act (CRA)
This action is subject to the CRA, and the EPA will submit the rule
report to each House of the Congress and to the Comptroller General of
the United States. This action meets the criteria set forth in 5 U.S.C.
804(2).
List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedures,
Air pollution control, Incorporation by reference, Reporting and
recordkeeping requirements.
Lee Zeldin,
Administrator.
For the reasons stated in the preamble, the Environmental
Protection Agency amends part 60 of title 40, chapter I, of the Code of
Federal Regulations as follows:
PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
[[Page 18093]]
Subpart A--General Provisions
0
2. Amend Sec. 60.17 by revising paragraphs (h)(78) and (m)(5) to read
as follows:
* * * * *
(h) * * *
(78) ASTM D1945-14 (Reapproved 2019), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography, approved December 1,
2019; IBR approved for Sec. Sec. 60.485b(g); 60.5417b(d); 60.5417c(d).
* * * * *
(m) * * *
(5) GPA Standard 2261-19 (GPA 2261-19), Analysis for Natural Gas
and Similar Gaseous Mixtures by Gas Chromatography, (Revised 2019), IBR
approved for Sec. Sec. 60.4415(a); 60.5417b(d); 60.5417c(d).
* * * * *
Subpart OOOOb--Standards of Performance for Crude Oil and Natural
Gas Facilities for Which Construction, Modification or
Reconstruction Commenced After December 6, 2022
0
3. Amend Sec. 60.5377b by revising paragraphs (b) through (g) to read
as follows:
Sec. 60.5377b What GHG and VOC standards apply to associated gas
wells at well affected facilities?
* * * * *
(b) For associated gas wells that commenced construction between
May 7, 2024 and May 7, 2026, you can comply with the requirements in
paragraph (f) of this section continually upon startup instead of
paragraph (a) of this section until May 7, 2026 if you demonstrate and
certify that it is not feasible to comply with paragraphs (a)(1)
through (4) of this section due to technical reasons in accordance with
paragraph (g) of this section. After May 7, 2026, you must continually
comply with paragraph (a) of this section at all times.
(c) For associated gas wells that commenced construction between
December 6, 2022, and May 7, 2024, and for associated gas wells that
undergo reconstruction or modification after December 6, 2022, you can
comply with the requirements in paragraph (f) of this section instead
of paragraph (a) of this section if you demonstrate and certify that it
is not feasible to comply with paragraphs (a)(1) through (4) of this
section due to technical reasons in accordance with paragraph (g) of
this section. Associated gas wells that are modified or reconstructed
must comply with paragraph (a) or (f) of this section upon startup and
at all times thereafter.
(d) If you are complying with paragraph (a) of this section, you
may temporarily route the associated gas to a flare or control device
that achieves a 95.0 percent reduction in VOC and methane emissions in
the situations and for the durations identified in paragraph (d)(1),
(2), (3), or (4) of this section. The associated gas must be routed
through a closed vent system that meets the requirements of Sec.
60.5411b(a) and (c) and the control device must meet the conditions
specified in Sec. 60.5412b during the period when the associated gas
is routed to the flare. Records must be kept of all instances in which
associated gas is temporarily routed to a flare or to a control device
in accordance with Sec. 60.5420b(c)(3)(i)(B) and reported in the
annual report in accordance with Sec. 60.5420b(b)(4)(i)(B).
(1) During a malfunction or incident that endangers the safety of
operator personnel or the public you are allowed to route associated
gas to a flare or control device until the malfunction or incident is
resolved, but not longer than 72 hours per incident. Temporarily
routing associated gas to a flare or control device is allowed only
until the malfunction or incident is resolved. Notwithstanding the
previous sentences, if there are exigent circumstances that reasonably
require routing to a flare or control device for more than 72 hours,
paragraphs (d)(1)(i) through (iii) of this section apply.
(i) An ``exigent circumstance'' for purposes of this paragraph
(d)(1) is a situation that results in the inability to reasonably
access a site with the necessary equipment and personnel to address and
resolve incidents that cause the need to temporarily flare associated
gas for more than 72 hours. This includes circumstances where there is
a need to flare beyond 72 hours due to an unexpected malfunction event
and equipment needed to resolve an incident are not readily available
due to an owner's or operator's inability to secure the required
equipment for reasons beyond an owner's or operator's control (i.e.,
supply chain issues); or there is a temporary shortage of personnel
needed to resolve an incident due to a circumstance such as a declared
national pandemic that is beyond the owner's or operator's control.
(ii) Temporarily routing associated gas to a flare or control
device is allowed until the malfunction or incident is resolved, but
shall not be longer than 72 hours after the site can be accessed
following the passing of the exigent circumstance.
(iii) For instances where you route associated gas to a flare or
control device for more than 72 hours, you must meet the reporting
requirements specified in Sec. 60.5420b(b)(4)(i)(B)(4) and must
maintain the records specified in Sec. 60.5420b(c)(3)(v).
(2) During repair and maintenance, including blow downs, a
production test, or commissioning, you are allowed to route associated
gas to a flare or control device until the incident is resolved, but no
longer than 72 hours per incident. Temporarily routing associated gas
to a flare or control device is allowed only until the incident is
resolved. Notwithstanding the previous sentences, if there are exigent
circumstances that reasonably require routing to a flare or control
device for more than 72 hours, paragraphs (d)(1)(i) through (iii)
apply.
(3) For wells complying with paragraph (a)(1) of this section,
during a temporary interruption in service from the gathering or
pipeline system you are allowed to route to a flare or route to a
control device for the duration of the temporary interruption not to
exceed 30 days per incident.
(4) During periods when the composition of the associated gas does
not meet pipeline specifications for sources complying with paragraph
(a)(1) of this section, or when the composition of the associated gas
does not meet the quality requirements for use as a fuel for sources
complying with paragraph (a)(2) of this section, or when the
composition of the associated gas does not meet the quality
requirements for another useful purpose for sources complying with
paragraph (a)(3) of this section, you are allowed to route to a flare
or control device until the associated gas meets the required
specifications or for 72 hours per incident, whichever is less.
(e) If you are complying with paragraph (a), (d), or (f) of this
section, you may vent the associated gas in the situations and for the
durations identified in paragraph (e)(1), (2), or (3) of this section
per incident. The cumulative period of venting must not exceed 24 hours
for any calendar year. Records must be kept of all venting instances in
accordance with Sec. 60.5420b(c)(3)(ii) and reported in the annual
report in accordance with Sec. 60.5420b(b)(4)(ii).
(1) For up to 12 hours per incident to protect the safety of
personnel.
(2) For up to 30 minutes per incident during bradenhead monitoring.
(3) For up to 30 minutes per incident during a packer leakage test.
(f) You must route the associated gas to a control device that
reduces methane and VOC emissions by at least 95.0 percent. The
associated gas must be routed through a closed vent system that
[[Page 18094]]
meets the requirements of Sec. 60.5411b(a) and (c) and the control
device must meet the conditions specified in Sec. 60.5412b.
(1) For associated gas wells identified in paragraph (b) of this
section, you can comply with the requirements in this paragraph (f) for
up to a one year period if you demonstrate and certify that it is not
feasible to comply with paragraphs (a)(1) through (4) of this section
due to technical reasons in accordance with paragraph (g) of this
section. This allowance is renewable each year with an updated
technical infeasibility demonstration and certification in accordance
with paragraph (g) of this section. Associated gas wells identified in
paragraph (b) of this section are not allowed to comply with the
requirements in this paragraph (f) after May 7, 2026.
(2) For associated gas wells identified in paragraph (c) of this
section, you can comply with the requirements in this paragraph (f) for
up to a one year period if you demonstrate and certify that it is not
feasible to comply with paragraphs (a)(1) through (4) of this section
due to technical reasons in accordance with paragraph (g) of this
section. This allowance is renewable each year with an updated
technical infeasibility demonstration and certification in accordance
with paragraph (g) of this section.
(g) For affected sources identified in paragraphs (b) and (c) of
this section that are complying with the requirements in paragraph (f)
of this section, you must demonstrate that it is not feasible to comply
with paragraphs (a)(1) through (4) of this section due to technical
reasons by providing a detailed analysis documenting and certifying the
technical reasons for this infeasibility.
(1) The demonstration must address the technical infeasibility for
all options identified in paragraphs (a)(1) through (4) of this
section.
(2) This demonstration must be certified by a professional engineer
or another qualified individual with expertise in the uses of
associated gas. The following certification, signed and dated by the
qualified professional engineer or other qualified individual shall
state: ``I certify that the assessment of technical and safety
infeasibility was prepared under my direction or supervision. I further
certify that the assessment was conducted, and this report was prepared
pursuant to the requirements of Sec. 60.5377b(b). Based on my
professional knowledge and experience, and inquiry of personnel
involved in the assessment, the certification submitted herein is true,
accurate, and complete.''
(3) This demonstration and certification are valid for no more than
12 months. You must re-analyze the feasibility of complying with
paragraphs (a)(1) through (4) of this section and finalize a new
demonstration and certification each year.
(4) Documentation of these demonstrations, along with the
certifications, must be maintained in accordance with Sec.
60.5420b(c)(3)(iii) and submitted in annual reports in accordance with
Sec. 60.5420b(b)(4)(iii)(C) and (D).
* * * * *
0
4. Amend Sec. 60.5417b by revising paragraph (c)(1) introductory text,
paragraphs (d)(7) and (8), (g)(1), and (i)(6)(v) to read as follows:
Sec. 60.5417b What are the continuous monitoring requirements for my
control devices?
* * * * *
(c) * * *
(1) Except for continuous parameter monitoring systems used to
detect the presence of a pilot or combustion flame, each continuous
parameter monitoring system must measure data values at least once
every hour and record the values for each parameter as required in
paragraph (c)(1)(i) or (ii) of this section. Continuous parameter
monitoring systems used to detect the presence of a pilot or combustion
flame must record a reading at least once every 5 minutes.
* * * * *
(d) * * *
(7) For a combustion control device whose model is tested under
Sec. 60.5413b(d), continuous monitoring systems as specified in
paragraphs (d)(8)(i) through (iv) and (vi) of this section and visible
emission observations conducted as specified in paragraph (d)(8)(v) of
this section.
(8) For an enclosed combustion device, other than those listed in
paragraphs (d)(1) through (3) and (7) of this section, or for a flare,
continuous monitoring systems as specified in paragraphs (d)(8)(i)
through (iv) of this section and visible emission observations
conducted as specified in paragraph (d)(8)(v) of this section.
Additionally, for enclosed combustion devices or flares that are air-
assisted or steam-assisted, the continuous monitoring systems specified
in paragraph (d)(8)(vi) of this section.
(i) After January 22, 2027, continuously monitor at least once
every five minutes for the presence of a pilot flame or combustion
flame using a device (including, but not limited to, a thermocouple,
ultraviolet beam sensor, or infrared sensor) capable of detecting that
the pilot or combustion flame is present at all times. After January
22, 2027, an alert must be sent to the nearest control room whenever
the pilot or combustion flame is unlit. Continuous monitoring systems
used for the presence of a pilot flame or combustion flame are not
subject to a minimum accuracy requirement beyond being able to detect
the presence or absence of a flame and are exempt from the calibration
requirements of this section.
(ii) Except as provided in this paragraph (d)(8)(ii) and paragraphs
(d)(8)(iii) and (vi) of this section, use one of the following methods
to continuously determine the NHV of the inlet gas to the enclosed
combustion device or flare at standard conditions. If the inlet gas
stream to the flare or enclosed combustion device does not include
streams from processes or equipment where inert gas or other vent gas
streams which may lower the NHV of the combined stream are added (e.g.,
vent streams from acid gas removal (AGR) system amine regenerator still
columns, vent streams from glycol dehydrator unit reboilers without
water removal, vent streams from compressors in acid gas service, vent
streams containing water or CO2 used for enhanced oil
recovery, vent streams from storage vessels with high water content
where the owner or operator has determined that the vent stream could
cause the inlet gas to the enclosed combustion device or flare to not
meet the minimum NHV, vent streams from gas plants that receive acid
gas from sweetening units, and vent streams from nitrogen removal units
(NRU)), the NHV of the inlet stream is considered to be sufficiently
above the minimum required NHV for the inlet gas, and you are not
required to conduct the continuous monitoring in this paragraph
(d)(8)(ii) of this section or the demonstration in paragraph
(d)(8)(iii) of this section, but you must submit the report in Sec.
60.5420b(b)(11)(v)(I) and maintain the record in Sec.
60.5420b(c)(11)(vi) indicating that the flare or enclosed combustion
device does not receive inert gases or other vent gas streams which may
lower the NHV of the combined stream.
(A) A calorimeter with a minimum accuracy of 2 percent
of span.
(B) A gas chromatograph that meets the requirements in paragraphs
(d)(8)(ii)(B)(1) through (5) of this section.
(1) You must follow the procedure in Performance Specification 9 of
appendix B of this part, except that a
[[Page 18095]]
single daily mid-level calibration check can be used (rather than
triplicate analysis), the multi-point calibration can be conducted
quarterly (rather than monthly), and the sampling line temperature must
be maintained at a minimum temperature of 60 [deg]C (rather than 120
[deg]C). Calibration gas cylinders must be certified to an accuracy of
2 percent and traceable to National Institute of Standards and
Technology (NIST) standards.
(2) You must meet the accuracy requirements in Performance
Specification 9 of appendix B of this part.
(3) You must use a calibration gas or multiple gases that includes
the compounds that are reasonably expected to be present in the flare
gas stream. If multiple calibration gases are necessary to cover all
compounds, you must calibrate the instrument on all of the gases. You
may only use the compounds used to calibrate the gas chromatograph in
the calculation of the vent gas NHV.
(4) In lieu of the calibration gas described in paragraph
(d)(8)(ii)(B)(3) of this section, you may use a surrogate calibration
gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All
of the calibration gases may be combined in one cylinder. If multiple
calibration gases are necessary to cover all compounds, you must
calibrate the instrument on all of the gases. Use the response factor
for the nearest normal hydrocarbon (i.e., n-alkane) in the calibration
mixture to quantify unknown components detected in the analysis. Use
the response factor for n-pentane to quantify unknown components
detected in the analysis that elute after n-pentane.
(5) To determine the NHV of the vent gas, determine the product of
the volume fraction of the individual component in the vent gas and the
net heating value of that individual component. Sum the products for
all components in the vent gas to determine the NHV for the vent gas.
For the net heating value of each individual component, use any
published values for the net heating value per mole at 25 [deg]C and 1
atmosphere and use 20 [deg]C as the standard temperature for
determining the volume corresponding to one mole of vent gas.
(C) A mass spectrometer that meets the requirements in paragraphs
(d)(8)(ii)(C)(1) through (6) of this section.
(1) You must meet applicable requirements in Performance
Specification 9 of appendix B of this part for continuous monitoring
system acceptance including, but not limited to, performing an initial
multi-point calibration check at three concentrations following the
procedure in Section 10.1. A single daily mid-level calibration check
can be used (rather than triplicate analysis), the multi-point
calibration can be conducted quarterly (rather than monthly), and the
sampling line temperature must be maintained at a minimum temperature
of 60 [deg]C (rather than 120 [deg]C). Calibration gas cylinders must
be certified to an accuracy of 2 percent and traceable to NIST
standards.
(2) The average instrument calibration error (CE) for each
calibration compound at any calibration concentration must not differ
by more than 10 percent from the certified cylinder gas value. The CE
for each component in the calibration blend must be calculated using
the following equation:
Equation 1 to Paragraph (d)(8)(ii)(C)(2)
[GRAPHIC] [TIFF OMITTED] TR09AP26.005
Where:
Cm = Average instrument response (ppm).
Ca = Certified cylinder gas value (ppm).
(3) You must use a calibration gas or multiple gases that includes
the compounds that are reasonably expected to be present in the flare
gas stream. If multiple calibration gases are necessary to cover all
compounds, you must calibrate the instrument on all of the gases. You
may only use the compounds used to calibrate the mass spectrometer in
the calculation of the vent gas NHV.
(4) In lieu of the calibration gas described in paragraph
(d)(8)(ii)(C)(3) of this section, you may use a surrogate calibration
gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All
of the calibration gases may be combined in one cylinder. If multiple
calibration gases are necessary to cover all compounds, you must
calibrate the instrument on all of the gases. For unknown gas
components that have similar analytical mass fragments to calibration
compounds, you may report the unknowns as an increase in the overlapped
calibration gas compound. For unknown compounds that produce mass
fragments that do not overlap calibration compounds, you may use the
response factor for the nearest molecular weight hydrocarbon in the
calibration mix to quantify the unknown component. You may use the
response factor for n-pentane to quantify any unknown components
detected with a higher molecular weight than n-pentane.
(5) You must perform an initial calibration to identify mass
fragment overlap and response factors for the target compounds.
(6) To determine the NHV of the vent gas, determine the product of
the volume fraction of the individual component in the vent gas and the
net heating value of that individual component. Sum the products for
all components in the vent gas to determine the NHV for the vent gas.
For the net heating value of each individual component, use any
published value for the net heating value per mole at 25 [deg]C and 1
atmosphere and use 20 [deg]C as the standard temperature for
determining the volume corresponding to one mole of vent gas.
(D) A grab sampling system capable of collecting an evacuated
canister sample for subsequent compositional analysis at least once
every eight hours. Subsequent compositional analysis of the samples
must be performed according to ASTM D1945-14 (R2019) or alternatively
GPA 2261-19 (incorporated by reference, see Sec. 60.17). To determine
the NHV of the vent gas, determine the product of the volume fraction
of the individual component in the vent gas and the net heating value
of that individual component. Sum the products for all components in
the vent gas to determine the NHV for the vent gas. For the net heating
value of each individual component, use any published value for the net
heating value per mole at 25 [deg]C and 1 atmosphere and use 20 [deg]C
as the standard temperature for determining the volume corresponding to
one mole of vent gas.
(iii) As an alternative to the continuous composition monitoring
requirements in paragraph (d)(8)(ii) of this section, a sampling
demonstration may be used as specified in this paragraph. Flares or
enclosed combustion devices that are not required to monitor flare gas
composition because the inlet gas streams to the flare or enclosed
combustion device does not include streams from processes or equipment
where inert gas or other vent gas streams which may lower the NHV of
the combined stream are added (e.g., vent streams from acid gas removal
(AGR) system amine regenerator still columns, vent streams from glycol
dehydrator unit reboilers without water removal, vent streams from
compressors in acid gas service, vent streams containing water or
CO2 used for enhanced oil recovery, vent streams from
storage vessels with high water content where the owner or operator has
determined
[[Page 18096]]
that the vent stream could cause the inlet gas to the enclosed
combustion device or flare to not meet the minimum NHV, vent streams
from gas plants that receive acid gas from sweetening units, and vent
streams from nitrogen removal units (NRU)), are not required to conduct
sampling demonstrations specified in this paragraph. For an unassisted
or pressure-assisted flare or enclosed combustion device, if you
demonstrate according to the methods described in paragraphs
(d)(8)(iii)(A) through (F) of this section that the NHV of the inlet
gas to the enclosed combustion device or flare consistently exceeds the
applicable operating limit specified in Sec. 60.5415b(f)(1)(vii)(B) or
(C), continuous monitoring of the NHV is not required, but you must
conduct the ongoing sampling in paragraph (d)(8)(iii)(G) of this
section. For flares and enclosed combustion devices that use assist air
(including perimeter assist air) or assist steam, if you demonstrate
according to the methods described in paragraphs (d)(8)(iii)(A) through
(F) of this section that the NHV of the inlet gas to the enclosed
combustion device or flare consistently exceeds 300 Btu/scf, continuous
monitoring of the NHV is not required, but you must conduct the ongoing
sampling in paragraph (d)(8)(iii)(G) of this section. For an unassisted
or pressure-assisted flare or enclosed combustion device, in lieu of
conducting the demonstration outlined in paragraphs (d)(8)(iii)(A)
through (D) of this section, you may conduct the demonstration outlined
in paragraph (d)(8)(iii)(H) of this section, but you must still comply
with paragraphs (d)(8)(iii)(E) through (G) of this section.
(A) Continuously monitor the inlet stream which is routed to the
flare or enclosed combustion device for 14 operating days or collect a
sample of the inlet gas which is routed to the enclosed combustion
device or flare twice daily to determine the average NHV of the gas
stream for 14 operating days with no sampling day to be spaced more
than 3 operating days apart from the previous sampling day. If you do
not continuously monitor the NHV, the minimum time of collection for
each individual sample be at least one hour when technically feasible.
When it is not technically feasible to collect individual samples for
at least one hour (e.g., low or intermittent flow), the collection time
must be as long as possible up to one hour. For samples taken during
low or intermittent flow events, the collection time and the reason for
not obtaining a full one hour sample must be documented and reported
with the NHV sampling results. Samples must be separated by at least 6
hours. If inlet gas flow is intermittent such that there are not at
least 28 samples over the 14 operating day period, you must continue to
collect samples of the inlet gas beyond the 14 operating day period
until you collect a minimum of 28 samples.
(B) If you collect samples twice per day, count the number of
samples where the NHV value is less than 1.2 times the applicable
operating limit specified in Sec. 60.5415b(f)(1)(vii)(B), (C), or this
paragraph (d)(8)(iii) (i.e., values that are less than 240, 360, or 960
Btu/scf, as applicable) during the sample collection period in
paragraph (d)(8)(iii)(A) of this section.
(C) If you continuously sample the inlet stream for 14 days, count
the number of hourly block average (e.g., noon to 1 p.m., 1 p.m. to 2
p.m., etc.) NHV values that are less than the applicable operating
limit specified in Sec. 60.5415b(f)(1)(vii)(B), Sec.
60.5415b(f)(1)(vii)(C), or this paragraph (d)(8)(iii) (i.e., values
that are less than 200, 300, or 800 Btu/scf, as applicable), during the
sample collection period in paragraph (d)(8)(iii)(A) of this section.
(D) If there are no samples counted under paragraph (d)(8)(iii)(B)
of this section or there are no hourly block average values counted
under paragraph (d)(8)(iii)(C) of this section, the gas stream is
considered to consistently exceed the applicable NHV operating limit
and on-going continuous monitoring is not required.
(E) If process operations are revised that could reduce the NHV of
the gas sent to the enclosed combustion device or flare, such as the
removal or addition of process equipment, and at any time the
Administrator requires, re-evaluation of the gas stream must be
performed according to paragraphs (d)(8)(iii)(A) through (D) of this
section within 60 days of the revisions to process operations to ensure
the gas stream still consistently exceeds the applicable operating
limit specified in Sec. 60.5415b(f)(1)(vii)(B), (C)(1), or this
paragraph (d)(8)(iii). If any of the samples counted under paragraph
(d)(8)(iii)(B) of this section or any hourly block average values
counted under paragraph (d)(8)(iii)(C) of this section are less than
the limits in the respective paragraph you must conduct the continuous
monitoring required by one of the options paragraphs (d)(8)(ii)(A)
through (D) of this section within 60 days of the re-evaluation of the
gas stream.
(F) When collecting samples under paragraph (d)(8)(iii)(A) of this
section, the owner or operator must account for any sources of inert
gases or other vent gas streams which may lower the NHV of the combined
stream (e.g., vent streams from AGR system amine regenerator still
columns, vent streams from glycol dehydrator unit reboilers, vent
streams from compressors in acid gas service, vent streams from
enhanced oil recovery facilities, or vent streams from storage vessel
with high water content where the owner or operator has determined that
the vent stream could cause the inlet gas to the enclosed combustion
device or flare to not meet the minimum NHV) that can be sent to the
enclosed combustion device or flare. The owner or operator must
document in the report in Sec. 60.5420b(b)(11)(v)(I) and the records
in Sec. 60.5420b(c)(11)(vi) must note the operating scenario(s) which
may lower the NHV of the combined stream through the introduction of
inert gases or other vent gas streams, and whether the sampling
included periods where the highest percentage of inert gases or other
vent gas streams which may lower the NHV of the combined stream were
sent to the enclosed combustion device or flare. If the introduction of
inerts or other vent gas streams which may lower the NHV of the
combined stream is intermittent and does not occur during the initial
demonstration, the introduction of inerts or other vent gas streams
which may lower the NHV of the combined stream will be considered a
revision to process operations that triggers a re-evaluation under
paragraph (d)(8)(iii)(E). If conditions at the site did not allow
sampling during periods where the introduction of inert gases or other
vent gas streams which may lower the NHV of the combined stream was at
the highest percentage possible, increasing the percentage of inerts
will be considered a revision to process operations that triggers a re-
evaluation under paragraph (d)(8)(iii)(E).
(G) You must collect three samples of the inlet gas to the enclosed
combustion device or flare at least once every 5 years. The minimum
time of collection for each individual sample must be at least one
hour, when technically feasible. When it is not technically feasible to
collect individual samples for at least one hour (e.g., low or
intermittent flow), the collection time must be as long as possible up
to one hour. For samples taken during low or intermittent flow events,
the collection time and the reason for not obtaining a full one hour
sample must be documented and reported with the NHV sampling results.
The samples must be taken during the period with the lowest expected
NHV (i.e., the period with the
[[Page 18097]]
highest percentage of inerts or other vent gas streams which may lower
the NHV of the combined stream). The first set of periodic samples must
be taken, or continuous monitoring commenced, no later than 60 calendar
months following the last sample taken under paragraph (d)(8)(iii)(A)
of this section. Subsequent periodic samples must be taken, or
continuous monitoring commenced, no later than 60 calendar months
following the previous sample. If any sample taken in accordance with
this paragraph (d)(8)(iii)(G) has an NHV value less than 1.2 times the
applicable operating limit specified in Sec. 60.5415b(f)(1)(vii)(B),
(C), or this paragraph (d)(8)(iii) (i.e., values that are less than
240, 360, or 960 Btu/scf, as applicable), you must conduct the
continuous monitoring required by one of the options in paragraphs
(d)(8)(ii)(A) through (D) of this section within 60 days of receipt of
the last sample.
(H) You may request an alternative test method under Sec.
60.5412b(d) to demonstrate that the flare or enclosed combustion device
reduces methane and VOC in the gases vented to the device by 95.0
percent by weight or greater. You must use an alternative test method
that demonstrates compliance with the combustion efficiency limit; you
may not use an alternative test method that demonstrates compliance
with NHVcz and NHVdil in lieu of measuring
combustion efficiency directly. You must measure data values at the
frequency specified in the alternative test method and conduct the
quality assurance and quality control requirements outlined in the
alternative test method at the frequency outlined in the alternative
test method. You must monitor the combustion efficiency of the flare
continuously for 14 days. If there are no values of the combustion
efficiency measured by the alternative test method that are less than
95.0 percent, the gas stream is considered to consistently exceed the
applicable NHV operating limit, and you are not required to
continuously monitor the NHV of the inlet gas to the flare or enclosed
combustion device.
(iv) Except as noted in paragraphs (d)(8)(iv)(A) through (F) and
(vi) of this section, a continuous parameter monitoring system for
measuring the flow of gas to the enclosed combustion device or flare.
You may use direct flow meters or other parameter monitoring systems
combined with engineering calculations, such as inlet line pressure,
line size, and burner nozzle dimensions, to satisfy this requirement.
The monitoring instrument must have an accuracy of 10
percent or better at the maximum expected flow rate.
(A) Pressure-assisted flares and pressure-assisted enclosed
combustion devices are not required to have a continuous parameter
monitoring system for measuring the inlet flow of gas to the device if
you install, calibrate, maintain, and operate a backpressure regulator
valve calibrated to open at the minimum pressure set point
corresponding to the minimum inlet gas flow rate. The set point must be
consistent with manufacturer specifications for minimum flow or
pressure and must be supported by an engineering evaluation. At least
annually, you must confirm that the backpressure regulator valve set
point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(B) Unassisted flares are not required to have a continuous
parameter monitoring system for measuring the inlet flow of gas to the
device if you meet the conditions in paragraphs (d)(8)(iv)(B)(1) and
(2) of this section.
(1) You must demonstrate, based on the maximum potential pressure
of units manifolded to the flare and applicable engineering
calculations for the manifolded closed vent system, that the maximum
flow rate to the flare cannot cause the flare tip velocity to exceed
the maximum tip velocity as specified in the applicable provisions in
Sec. 60.18(c) and (f) of this chapter. You must use the minimum
expected value of the NHV of the inlet gas to the flare or enclosed
combustion based on previous sampling results or process knowledge of
the streams sent to the enclosed flare of combustion device in your
demonstration. If there are changes to the process or control device
that can be reasonably expected to increase the maximum flow rate to
the flare, you must conduct a new demonstration to determine whether
the maximum flow rate to the flare is compliant with the applicable
maximum flare tip velocity provisions in Sec. 60.18(c) and (f) of this
chapter.
(2) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an engineering evaluation. At
least annually, you must confirm that the backpressure regulator valve
set point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(C) Unassisted enclosed combustion devices are not required to have
a continuous parameter monitoring system for measuring the inlet flow
of gas to the device if you meet the conditions in paragraphs
(d)(8)(iv)(C)(1) and (2) of this section.
(1) You must demonstrate, based on the maximum potential pressure
of units manifolded to the enclosed combustion device and applicable
engineering calculations for the manifolded closed vent system, that
the maximum flow rate to the enclosed combustion device cannot cause
the maximum inlet flow rate established in accordance with paragraph
(f)(1) of this section to be exceeded. If there are changes to the
process or control device that can be reasonably expected to impact the
maximum flow rate to the enclosed combustion device, you must conduct a
new demonstration to determine whether the maximum flow rate to the
enclosed combustor is less than the maximum inlet flow rate established
in accordance with paragraph (f)(1) of this section.
(2) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an engineering evaluation. At
least annually, you must confirm that the backpressure regulator valve
set point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(D) Air-assisted flares or enclosed combustion devices that use
only perimeter assist air and have no assist steam or premix assist air
are not required to have a continuous parameter monitoring system for
measuring the inlet flow of gas to the device or the flow of assist air
if you meet the conditions in paragraphs (d)(8)(iv)(D)(1) through (3)
of this section, as applicable. For these flares and enclosed
combustion devices, NHVcz is assumed to be equal to the vent
gas NHV.
(1) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an
[[Page 18098]]
engineering evaluation. At least annually, you must confirm that the
backpressure regulator valve set point is correct and consistent with
the engineering evaluation and manufacturer specifications and that the
valve fully closes when not in the open position.
(2) If you are required to monitor vent gas composition for the
flare or enclosed combustion device according to paragraph (d)(8)(ii)
or (iii) of this section, you must demonstrate, based on the maximum
flow rate of perimeter assist air to the enclosed combustion device or
flare and applicable engineering calculations, that the
NHVdil can never be less than the minimum required
NHVdil. The demonstration must clearly document why the
maximum flow rate of perimeter assist air will never exceed the rate
used in the demonstration. You must use the minimum flow rate of vent
gas allowed by your backpressure regulator valve and the minimum
expected value of the NHV of the inlet gas to the enclosed combustion
device or flare based on previous sampling results or process knowledge
of the streams sent to the enclosed combustion device or flare in your
demonstration. You must update this demonstration if there are changes
to the backpressure regulator valve, the backpressure regulator valve
set point, or the maximum flow rate of perimeter assist air. You must
also update this demonstration if any sampling results of the NHV of
the inlet gas to the enclosed combustion device or flare under
paragraph (d)(8)(ii) or (iii) of this section are lower than the NHV
vent gas value used in your demonstration.
(3) For air-assisted flares, you must also demonstrate, based on
the maximum potential pressure of units manifolded to the flare and
applicable engineering calculations for the manifolded closed vent
system, that the maximum flow rate to the flare cannot cause the flare
tip velocity to exceed the maximum tip velocity as specified in the
applicable provisions in Sec. 60.18(c) and (f) of this chapter. You
must use the minimum expected value of the NHV of the inlet gas to the
flare or enclosed combustion based on previous sampling results or
process knowledge of the streams sent to the enclosed flare of
combustion device in your demonstration. If there are changes to the
process or control device that can be reasonably expected to increase
the maximum flow rate to the flare, you must conduct a new
demonstration to determine whether the maximum flow rate to the flare
is compliant with the applicable maximum flare tip velocity provisions
in Sec. 60.18(c) and (f) of this chapter.
(E) Air-assisted flares or enclosed combustion devices that use
only premix assist air and have no assist steam or perimeter assist air
are not required to have a continuous parameter monitoring system for
measuring the inlet flow of gas to the device or the flow of assist air
if you meet the conditions in paragraphs (d)(8)(iv)(E)(1) through (3)
of this section, as applicable.
(1) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an engineering evaluation. At
least annually, you must confirm that the backpressure regulator valve
set point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(2) If you are required to monitor vent gas composition for the
flare or enclosed combustion device according to paragraph (d)(8)(ii)
or (iii) of this section, you must demonstrate, based on the maximum
flow rate of premix assist air to the enclosed combustion device or
flare and applicable engineering calculations, that the
NHVcz will never be less than the minimum required
NHVcz. The demonstration must clearly document why the
maximum flow rate of premix assist air will never exceed the rate used
in the demonstration. You must use the minimum flow rate of vent gas
allowed by your backpressure regulator valve in and the minimum
expected value of the NHV of the inlet gas to the enclosed combustion
device or flare based on previous sampling results or process knowledge
of the streams sent to the enclosed combustion device or flare in your
demonstration. You must update this demonstration if there are changes
to the backpressure regulator valve, the backpressure regulator valve
set point, or the maximum flow rate of premix assist air. You must also
update this demonstration if any sampling results of the NHV of the
inlet gas to the enclosed combustion device or flare under paragraph
(d)(8)(ii) or (iii) of this section are lower than the NHV vent gas
value used in your demonstration.
(3) For air-assisted flares, you must also demonstrate, based on
the maximum potential pressure of units manifolded to the flare and
applicable engineering calculations for the manifolded closed vent
system, that the maximum flow rate to the flare cannot cause the flare
tip velocity to exceed the maximum tip velocity as specified in the
applicable provisions in Sec. 60.18(c) and (f) of this chapter. You
must use the minimum expected value of the NHV of the inlet gas to the
flare or enclosed combustion based on previous sampling results or
process knowledge of the streams sent to the enclosed flare of
combustion device in your demonstration. If there are changes to the
process or control device that can be reasonably expected to increase
the maximum flow rate to the flare, you must conduct a new
demonstration to determine whether the maximum flow rate to the flare
is compliant with the applicable maximum flare tip velocity provisions
in Sec. 60.18(c) and (f) of this chapter.
(F) Steam-assisted flares or enclosed combustion devices that have
no premix assist air and or perimeter assist air (other than perimeter
assist air intentionally entrained in lower and/or upper steam at the
flare tip and the effective diameter of the flare tip is 9 inches or
greater) are not required to have a continuous parameter monitoring
system for measuring the inlet flow of gas to the device or the flow of
assist steam if you meet the conditions in paragraphs (d)(8)(iv)(F)(1)
through (3) of this section, as applicable.
(1) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an engineering evaluation. At
least annually, you must confirm that the backpressure regulator valve
set point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(2) If you are required to monitor vent gas composition for the
flare or enclosed combustion device according to paragraph (d)(8)(ii)
or (iii) of this section, you must demonstrate, based on the maximum
flow rate of assist steam to the enclosed combustion device or flare
and applicable engineering calculations, that the NHVcz will
never be less than the minimum required NHVcz. The
demonstration must clearly document why the maximum flow rate of assist
steam will never exceed the rate used in the demonstration. You must
use the minimum flow rate of vent gas allowed by your backpressure
[[Page 18099]]
regulator valve in and the minimum expected value of the NHV of the
inlet gas to the enclosed combustion device or flare based on previous
sampling results or process knowledge of the streams sent to the
enclosed combustion device or flare in your demonstration. You must
update this demonstration if there are changes to the backpressure
regulator valve, the backpressure regulator valve set point, or the
maximum flow rate of assist steam. You must also update this
demonstration if any sampling results of the NHV of the inlet gas to
the enclosed combustion device or flare under paragraph (d)(8)(ii) or
(iii) of this section are lower than the NHV vent gas value used in
your demonstration.
(3) For steam-assisted flares, you must also demonstrate, based on
the maximum potential pressure of units manifolded to the flare and
applicable engineering calculations for the manifolded closed vent
system, that the maximum flow rate to the flare cannot cause the flare
tip velocity to exceed the maximum tip velocity as specified in the
applicable provisions in Sec. 60.18(c) and (f) of this chapter. You
must use the minimum expected value of the NHV of the inlet gas to the
flare or enclosed combustion based on previous sampling results or
process knowledge of the streams sent to the enclosed flare of
combustion device in your demonstration. If there are changes to the
process or control device that can be reasonably expected to increase
the maximum flow rate to the flare, you must conduct a new
demonstration to determine whether the maximum flow rate to the flare
is compliant with the applicable maximum flare tip velocity provisions
in Sec. 60.18(c) and (f) of this chapter.
(v) Conduct inspections monthly and at other times as requested by
the Administrator to monitor for visible emissions from the combustion
device using section 11 of Method 22 of appendix A of this part or
conduct visible emissions monitoring according to paragraph (h) of this
section. The observation period shall be 15 minutes or once the amount
of time visible emissions is present has exceeded 1 minute. Devices
must be operated with no visible emissions, except for periods not to
exceed a total of 1 minute during any 15-minute period.
(vi) If you use a flare or enclosed combustion device that is air-
assisted or steam-assisted and that receives streams from processes or
equipment where inert gas or other vent gas streams which may lower the
NHV of the combined stream are added (e.g., vent streams from acid gas
removal (AGR) system amine regenerator still columns, vent streams from
glycol dehydrator unit reboilers without water removal, vent streams
from compressors in acid gas service, vent streams containing water or
CO2 used for enhanced oil recovery, vent streams from
storage vessels with high water content where the owner or operator has
determined that the vent stream could cause the inlet gas to the
enclosed combustion device or flare to not meet the minimum NHV, vent
streams from gas plants that receive acid gas from sweetening units,
and vent streams from nitrogen removal units (NRU)), you must either
meet the applicable requirements in (d)(8)(vi)(A) through (D) of this
section or you must use an approved alternative method allowed under
Sec. 60.5412b(d)(1)(i) and (ii) to continuously monitor
NHVcz and, if applicable, NHVdil. If you elect to
continuously monitor NHVcz and, if applicable,
NHVdil using an approved alternative method as provided
under Sec. 60.5412b(d)(1)(i) and (ii), you are not required to monitor
NHV of the vent gas as specified in paragraph (d)(8)(ii) of this
section or monitor flow rates as specified in this paragraph (d)(8)(vi)
provided you can demonstrate that the maximum flow rate to the flare
cannot cause the flare tip velocity to exceed the maximum tip velocity
as specified in the applicable provisions in Sec. 60.18(c) and (f) of
this chapter. You must use the minimum expected value of the NHV of the
inlet gas to the flare or enclosed combustion based on previous
sampling results or process knowledge of the streams sent to the
enclosed flare of combustion device in your demonstration.
(A) Except as allowed by paragraph (d)(8)(iv)(E) or (F) of this
section, you must monitor and calculate NHVcz as specified
in Sec. 63.670(m) of this chapter. Additionally, for flares and
enclosed combustion devices that use only perimeter assist air and do
not use steam assist or premix assist air, the NHVcz is
equal to the vent gas NHV. When NHVcz is equal to the vent
gas NHV, you are not required to continuously monitor NHVcz
if you meet the requirements in paragraph (d)(8)(iii) of this section.
(B) Except as allowed by paragraph (d)(8)(iv)(D) of this section,
for each flare using perimeter assist air, you must also monitor and
calculate NHVdil as specified in Sec. 63.670(n) of this
chapter. If the only assist air provided to the flare or enclosed
combustion control device is perimeter assist air intentionally
entrained in lower and/or upper steam at the flare tip and the
effective diameter is 9 inches or greater, you are only required to
comply with the NHVcz limit specified in paragraph
(f)(8)(vi)(A) of this section.
(C) Except as allowed by paragraph (d)(8)(iv) of this section, you
must monitor the flare vent gas and assist gas as specified in Sec.
63.670(i) of this chapter.
(D) You must determine the flare vent gas net heating value as
specified in Sec. 63.670(l) of this chapter using one of the methods
specified in paragraph (d)(8)(ii) of this section. Where the phrase
``petroleum refinery'' is used, for purposes of this subpart, it will
refer to flares controlling an affected facility under this subpart. If
you are not required to continuously monitor the NHV of the inlet gas
because you have demonstrated that it consistently exceeds the
applicable operating limit as provided in paragraph (d)(8)(iii) of this
section, you must use the lowest net heating value measured in the
sampling program in paragraph (d)(8)(iii) of this section for the
calculations performed in paragraphs (d)(8)(vi)(A) and (B). You must
update this value if a subsequent sampling result of the NHV of the
inlet gas to the enclosed combustion device or flare under paragraph
(d)(8)(iii) of this section is lower than the NHV vent gas value used
in your calculations.
* * * * *
(g) * * *
(1) A deviation occurs when the average value of a monitored
operating parameter determined in accordance with paragraph (e) of this
section is less than the minimum operating parameter limit (and, if
applicable, greater than the maximum operating parameter limit)
established in paragraph (f)(1) of this section; for flares, when the
average value of a monitored operating parameter determined in
accordance with paragraph (e) of this section is below the applicable
limits specified in Sec. 60.5415b(f)(1)(vii)(B)(1) through (4) and (6)
or above the limit specified in Sec. 60.5415b(f)(1)(vii)(B)(5); or for
each flare or enclosed combustion device except for boilers and process
heaters meeting the requirements in Sec. 60.5412b(a)(1)(iii) and
catalytic vapor incinerators meeting the requirements in Sec.
60.5412b(a)(1)(v), when the heat sensing device indicates that there is
no pilot or combustion flame present for any time period. If you use a
backpressure regulator valve to maintain the inlet gas flow to an
enclosed combustion device or flare above the minimum value, a
deviation occurs if the annual inspection finds that the backpressure
regulator valve set point is not set correctly or indicates that the
backpressure regulator valve does not
[[Page 18100]]
fully close when not in the open position.
* * * * *
0
5. Amend Sec. 60.5420b by revising paragraphs (a)(4), (b), (c)(3)
through (6), (c)(11) through (15), and paragraph (d) to read as
follows:
Sec. 60.5420b What are my notification, reporting, and recordkeeping
requirements?
(a) * * *
(4) An owner or operator who commences well closure activities must
submit the following notices to the Administrator according to the
schedule in paragraphs (a)(4)(i) and (ii) of this section. The
notification shall include contact information for the owner or
operator; the United States Well Number; the latitude and longitude
coordinates for each well at the well site in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using the North
American Datum of 1983. You must submit notifications in portable
document format (PDF) following the procedures specified in paragraph
(d) of this section.
(i) You must submit a well closure plan to the Administrator within
30 days of the cessation of production from all wells located at the
well site.
(ii) You must submit a notification of the intent to close a well
site 60 days before you begin well closure activities.
(b) Reporting requirements. You must submit annual reports
containing the information specified in paragraphs (b)(1) through (14)
of this section following the procedure specified in paragraph (b)(15)
of this section. You must submit performance test reports as specified
in paragraph (b)(12) or (13) of this section, if applicable. Subject to
the exception in the next sentence, the initial annual report is due no
later than 90 days after the end of the initial compliance period as
determined according to Sec. 60.5410b; subsequent annual reports are
due no later than the same date each year as the initial annual report.
Notwithstanding the preceding sentence, no annual report is due before
November 30, 2026, on or before which date you must submit all annual
reports that were due before November 30, 2026, per the timing
specified in the preceding sentence; then subsequent annual reports
thereafter are due no later than 90 days after the end of each annual
compliance period. If you own or operate more than one affected
facility, you may submit one report for multiple affected facilities
provided the report contains all of the information required as
specified in paragraphs (b)(1) through (14) of this section. Annual
reports may coincide with title V reports as long as all the required
elements of the annual report are included. You may arrange with the
Administrator a common schedule on which reports required by this part
may be submitted as long as the schedule does not extend the reporting
period. You must submit the information in paragraph (b)(1)(v) of this
section, as applicable, for your well affected facility which undergoes
a change of ownership during the reporting period, regardless of
whether reporting under paragraphs (b)(2) through (4) of this section
is required for the well affected facility.
(1) The general information specified in paragraphs (b)(1)(i)
through (v) of this section is required for all reports.
(i) The company name, facility site name associated with the
affected facility, U.S. Well ID or U.S. Well ID associated with the
affected facility, if applicable, and address of the affected facility.
If an address is not available for the site, include a description of
the site location and provide the latitude and longitude coordinates of
the site in decimal degrees to an accuracy and precision of five (5)
decimals of a degree using the North American Datum of 1983.
(ii) An identification of each affected facility being included in
the annual report.
(iii) Beginning and ending dates of the reporting period.
(iv) A certification by a certifying official of truth, accuracy,
and completeness. This certification shall state that, based on
information and belief formed after reasonable inquiry, the statements
and information in the document are true, accurate, and complete. If
your report is submitted via CEDRI, the certifier's electronic
signature during the submission process replaces the requirement in
this paragraph (b)(1)(iv).
(v) Identification of each well affected facility for which
ownership changed due to sale or transfer of ownership including the
United States Well Number; the latitude and longitude coordinates of
the well affected facility in decimal degrees to an accuracy and
precision of five (5) decimals of a degree using the North American
Datum of 1983; and the information in paragraph (b)(1)(v)(A) or (B) of
this section, as applicable.
(A) The name and contact information, including the phone number,
email address, and mailing address, of the owner or operator to which
you sold or transferred ownership of the well affected facility
identified in this paragraph (b)(1)(v).
(B) The name and contact information, including the phone number,
email address, and mailing address, of the owner or operator from whom
you acquired the well affected facility identified in this paragraph
(b)(1)(v).
(2) For each well affected facility that is subject to Sec.
60.5375b(a) or (f), the records of each well completion operation
conducted during the reporting period, including the information
specified in paragraphs (b)(2)(i) through (xiv) of this section, if
applicable. In lieu of submitting the records specified in paragraphs
(b)(2)(i) through (xiv) of this section, the owner or operator may
submit a list of each well completion with hydraulic fracturing
completed during the reporting period, and the digital photograph
required by paragraph (c)(1)(v) of this section for each well
completion. For each well affected facility that routes all flowback
entirely through one or more production separators, only the records
specified in paragraphs (b)(2)(i) through (iv) and (vi) of this section
are required to be reported. For periods where salable gas is unable to
be separated, the records specified in paragraphs (b)(2)(iv) and (viii)
through (xii) of this section must also be reported, as applicable. For
each well affected facility that is subject to Sec. 60.5375b(g), the
record specified in paragraph (b)(2)(xv) of this section is required to
be reported. For each well affected facility which makes a claim that
the exemption in Sec. 60.5375b(h) was met, the records specified in
paragraph (b)(2)(i) through (iv) and (xvi) of this section are required
to be reported.
(i) Well Completion ID.
(ii) Latitude and longitude of the well in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using North
American Datum of 1983.
(iii) U.S. Well ID.
(iv) The date and time of the onset of flowback following hydraulic
fracturing or refracturing or identification that the well immediately
starts production.
(v) The date and time of each attempt to direct flowback to a
separator as required in Sec. 60.5375b(a)(1)(ii).
(vi) The date and time that the well was shut in and the flowback
equipment was permanently disconnected, or the startup of production.
(vii) The duration (in hours) of flowback.
(viii) The duration (in hours) of recovery and disposition of
recovery (i.e., routed to the gas flow line or collection system, re-
injected into the well or another well, used as an onsite fuel source,
or used for another useful purpose that a purchased fuel or raw
material would serve).
[[Page 18101]]
(ix) The duration (in hours) of combustion.
(x) The duration (in hours) of venting.
(xi) The specific reasons for venting in lieu of capture or
combustion.
(xii) For any deviations recorded as specified in paragraph
(c)(1)(ii) of this section, the date and time the deviation began, the
duration of the deviation in hours, and a description of the deviation.
(xiii) For each well affected facility subject to Sec.
60.5375b(f), a record of the well type (i.e., wildcat well, delineation
well, or low pressure well (as defined Sec. 60.5430b)) and supporting
inputs and calculations, if applicable.
(xiv) For each well affected facility for which you claim an
exception under Sec. 60.5375b(a)(2), the specific exception claimed
and reasons why the well meets the claimed exception.
(xv) For each well affected facility with less than 300 scf of gas
per stock tank barrel of oil produced, the supporting analysis that was
performed in order the make that claim, including but not limited to,
GOR values for established leases and data from wells in the same basin
and field.
(xvi) For each well affected facility which meets the exemption in
Sec. 60.5375b(h), a statement that the well completion operation
requirements of Sec. 60.5375b(a)(1) through (3) were met.
(3) For each well affected facility that is subject to Sec.
60.5376b(a)(1) or (2), your annual report is required to include the
information specified in paragraphs (b)(3)(i) and (ii) of this section,
as applicable.
(i) For each well affected facility where all gas well liquids
unloading operations comply with Sec. 60.5376b(a)(1), your annual
report must include the information specified in paragraphs
(b)(3)(i)(A) through (C) of this section, as applicable.
(A) Identification of each well affected facility (U.S. Well ID or
U.S. Well ID associated with the well affected facility) that conducts
a gas well liquid unloading operation during the reporting period using
a method that does not vent to the atmosphere and the technology or
technique used. If more than one non-venting technology or technique is
used, you must identify all of the differing non-venting liquids
unloading methods used during the reporting period.
(B) Number of gas well liquids unloading operations conducted
during the year where the well affected facility identified in
(b)(3)(i)(A) had unplanned venting to the atmosphere and best
management practices were conducted according to your best management
practice plan, as required by Sec. 60.5376b(c). If no venting events
occurred, the number would be zero. Other reported information required
to be submitted where unplanned venting occurs is specified in
paragraphs (b)(3)(i)(B)(1) and (2) of this section.
(1) Log of best management practice plan steps used during the
unplanned venting to minimize emissions to the maximum extent possible.
(2) The number of liquids unloading events during the year where
deviations from your best management practice plan occurred, the date
and time the deviation began, the duration of the deviation in hours,
documentation of why best management practice plan steps were not
followed, and what steps, in lieu of your best management practice plan
steps, were followed to minimize emissions to the maximum extent
possible.
(C) The number of liquids unloading events where unplanned
emissions are vented to the atmosphere during a gas well liquids
unloading operation where you complied with best management practices
to minimize emissions to the maximum extent possible.
(ii) For each well affected facility where all gas well liquids
unloading operations comply with Sec. 60.5376b(b) and (c) best
management practices, your annual report must include the information
specified in paragraphs (b)(3)(ii)(A) through (E) of this section.
(A) Identification of each well affected facility that conducts a
gas well liquids unloading during the reporting period.
(B) Number of liquids unloading events conducted during the
reporting period.
(C) Log of best management practice plan steps used during the
reporting period to minimize emissions to the maximum extent possible.
(D) The number of liquids unloading events during the year that
best management practices were conducted according to your best
management practice plan.
(E) The number of liquids unloading events during the year where
deviations from your best management practice plan occurred, the date
and time the deviation began, the duration of the deviation in hours,
documentation of why best management practice plan steps were not
followed, and what steps, in lieu of your best management practice plan
steps, were followed to minimize emissions to the maximum extent
possible.
(4) For each associated gas well subject to Sec. 60.5377b, your
annual report is required to include the applicable information
specified in paragraphs (b)(4)(i) through (vi) of this section, as
applicable.
(i) For each associated gas well that complies with Sec.
60.5377b(a)(1), (2), (3), or (4) your annual report is required to
include the information specified in paragraphs (b)(4)(i)(A) and (B) of
this section.
(A) An identification of each associated gas well constructed,
modified, or reconstructed during the reporting period that complies
with Sec. 60.5377b(a)(1), (2), (3), or (4).
(B) The information specified in paragraphs (b)(4)(i)(B)(1) through
(4) of this section for each incident when the associated gas was
temporarily routed to a flare or control device in accordance with
Sec. 60.5377b(d).
(1) The reason in Sec. 60.5377b(d)(1), (2), (3), or (4) for each
incident.
(2) The start date and time of each incident of routing associated
gas to the flare or control device, along with the total duration in
hours of each incident.
(3) Documentation that all CVS requirements specified in Sec.
60.5411b(a) and (c) and all applicable flare or control device
requirements specified in Sec. 60.5412b were met during each period
when the associated gas is routed to the flare or control device.
(4) For each instance where you route associated gas to a flare or
control device beyond 72 hours due to ``exigent circumstances''
according to Sec. 60.5377b(d)(1) or (2), you must include the record
information specified in paragraph (c)(3)(v) of this section in your
annual report.
(ii) For all instances where you temporarily vent the associated
gas in accordance with Sec. 60.5377b(e), you must report the
information specified in paragraphs (b)(4)(ii)(A) through (D) of this
section. This information is required to be reported if you are
routinely complying with Sec. 60.5377b(a) or (f) or temporarily
complying with Sec. 60.5377b(d). In addition to this information for
each incident, you must report the cumulative duration in hours of
venting incidents and the cumulative VOC and methane emissions in
pounds for all incidents in the calendar year.
(A) The reason in Sec. 60.5377b(e)(1), (2), or (3) for each
incident.
(B) The start date and time of each incident of venting the
associated gas, along with the total duration in hours of each
incident.
(C) The VOC and methane emissions in pounds that were emitted
during each incident.
(D) The total duration of venting for all incidents in the year,
along with the cumulative VOC and methane emissions in pounds that were
emitted.
(iii) For each associated gas well that complies with the
requirements of Sec. 60.5377b(f) your annual report must
[[Page 18102]]
include the information specified in paragraphs (b)(4)(iii)(A) through
(E) of this section. The information in paragraphs (b)(4)(iii)(A) and
(B) of this section is only required in the initial annual report.
(A) An identification of each associated gas well that commenced
construction between May 7, 2024, and May 7, 2026. This identification
must include the certification of why it is infeasible to comply with
Sec. 60.5377b(a)(1), (2), (3), or (4) in accordance with Sec.
60.5377b(g).
(B) An identification of each associated gas well that commenced
construction between December 6, 2022, and May 7, 2024. This
identification must include the certification of why it is infeasible
to comply with Sec. 60.5377b(a)(1), (2), (3), or (4) in accordance
with Sec. 60.5377b(g).
(C) An identification of each associated gas well modified or
reconstructed during the reporting period that complies by routing the
gas to a control device that reduces VOC and methane emissions by at
least 95.0 percent. This identification must include the certification
of why it is infeasible to comply with Sec. 60.5377b(a)(1), (2), (3),
or (4) in accordance with Sec. 60.5377b(g).
(D) For each associated gas well that was constructed, modified or
reconstructed in a previous reporting period that complies by routing
the gas to a control device that reduces VOC and methane emissions by
at least 95.0 percent, a re-certification of why it is infeasible to
comply with Sec. 60.5377b(a)(1), (2), (3), or (4) in accordance with
Sec. 60.5377b(g).
(E) The information specified in paragraphs (b)(11)(i) through (iv)
of this section.
(iv) If you comply with Sec. 60.5377b(f) with a control device,
identification of the associated gas well using the control device and
the information in paragraph (b)(11)(v) of this section.
(v) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(b)(11)(i) and (ii) of this section, you must provide the information
specified in Sec. 60.5424b.
(vi) For each deviation recorded as specified in paragraph
(c)(3)(v) of this section, the date and time the deviation began, the
duration of the deviation in hours, and a description of the deviation.
If no deviations occurred during the reporting period, you must include
a statement that no deviations occurred during the reporting period.
(5) For each wet seal centrifugal compressor affected facility, the
information specified in paragraphs (b)(5)(i) through (v) of this
section. For each self-contained wet seal centrifugal compressor,
Alaska North Slope centrifugal compressor equipped with sour seal oil
separator and capture system, or dry seal centrifugal compressor
affected facility, the information specified in paragraphs (b)(5)(vi)
through (ix) of this section.
(i) An identification of each centrifugal compressor constructed,
modified, or reconstructed during the reporting period.
(ii) For each deviation that occurred during the reporting period
and recorded as specified in paragraph (c)(4) of this section, the date
and time the deviation began, the duration of the deviation in hours,
and a description of the deviation. If no deviations occurred during
the reporting period, you must include a statement that no deviations
occurred during the reporting period.
(iii) If required to comply with Sec. 60.5380b(a)(2) or (3), the
information specified in paragraphs (b)(11)(i) through (iv) of this
section, as applicable.
(iv) If complying with Sec. 60.5380b(a)(1) with a control device,
identification of the centrifugal compressor with the control device
and the information in paragraph (b)(11)(v) of this section.
(v) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(b)(11)(i) and (ii) of this section, you must provide the information
specified in Sec. 60.5424b.
(vi) If complying with Sec. 60.5380b(a)(4), (5), or (6) for a
self-contained wet seal centrifugal compressor, Alaska North Slope
centrifugal compressor equipped with sour seal oil separator and
capture system, or dry seal centrifugal compressor requirements, the
cumulative number of hours of operation since initial startup, since
May 7, 2024, or since the previous volumetric flow rate emissions
measurement, as applicable, which have elapsed prior to conducting your
volumetric flow rate emission measurement or emissions screening.
(vii) A description of the method used and the results of the
volumetric emissions measurement or emissions screening, as applicable.
(viii) Number and type of seals on delay of repair and explanation
for each delay of repair.
(ix) Date of planned shutdown(s) that occurred during the reporting
period if there are any seals that have been placed on delay of repair.
(6) For each reciprocating compressor affected facility, the
information specified in paragraphs (b)(6)(i) through (vii) of this
section, as applicable.
(i) The cumulative number of hours of operation since initial
startup, since May 7, 2024, since the previous volumetric flow rate
measurement, or since the previous reciprocating compressor rod packing
replacement, as applicable, which have elapsed prior to conducting your
volumetric flow rate measurement or emissions screening. Alternatively,
a statement that emissions from the rod packing are being routed to a
process or control device through a closed vent system.
(ii) If applicable, for each deviation that occurred during the
reporting period and recorded as specified in paragraph (c)(5)(i) of
this section, the date and time the deviation began, duration of the
deviation in hours and a description of the deviation. If no deviations
occurred during the reporting period, you must include a statement that
no deviations occurred during the reporting period.
(iii) A description of the method used and the results of the
volumetric flow rate measurement or emissions screening, as applicable.
(iv) If complying with Sec. 60.5385b(d)(1) or (2), the information
in paragraphs (b)(11)(i) through (iv) of this section. If complying by
routing emissions to a control device, as required in Sec.
60.5385b(d)(2), the information in paragraph (b)(11)(v) of this
section.
(v) Number and type of rod packing replacements/repairs on delay of
repair and explanation for each delay of repair.
(vi) Date of planned shutdown(s) that occurred during the reporting
period if there are any rod packing replacements/repairs that have been
placed on delay of repair.
(vii) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(b)(11)(i) and (ii) of this section, you must provide the information
specified in Sec. 60.5424b.
(7) For each process controller affected facility, the information
specified in paragraphs (b)(7)(i) through (iii) of this section in your
initial annual report and in subsequent annual reports for each process
controller affected facility that is constructed, modified, or
reconstructed during the reporting period. Each annual report must
contain the information specified in paragraphs (b)(7)(iv) through (x)
of this section for each process controller affected facility.
(i) An identification of each process controller that is driven by
natural gas, as required by Sec. 60.5390b(d), that allows traceability
to the records required in paragraph (c)(6)(i) of this section.
[[Page 18103]]
(ii) For each process controller in the affected facility complying
with Sec. 60.5390b(a), you must report the information specified in
paragraphs (b)(7)(ii)(A) and (B) of this section, as applicable.
(A) An identification of each process controller complying with
Sec. 60.5390b(a) by routing the emissions to a process.
(B) An identification of each process controller complying with
Sec. 60.5390b(a) by using a self-contained natural gas-driven process
controller.
(iii) For each process controller affected facility located at a
site in Alaska that does not have access to electrical power and that
complies with Sec. 60.5390b(b), you must report the information
specified in paragraph (b)(7)(iii)(A), (B), or (C) of this section, as
applicable.
(A) For each process controller complying with Sec. 60.5390b(b)(1)
process controller bleed rate requirements, you must report the
information specified in paragraphs (b)(7)(iii)(A)(1) and (2) of this
section.
(1) The identification of process controllers designed and operated
to achieve a bleed rate less than or equal to 6 scfh.
(2) Where necessary to meet a functional need, the identification
and demonstration why it is necessary to use a process controller with
a natural gas bleed rate greater than 6 scfh.
(B) An identification of each intermittent vent process controller
complying with the requirements in paragraph Sec. 60.5390b(b)(2).
(C) An identification of each process controller complying with the
requirements in Sec. 60.5390b(b) by routing emissions to a control
device in accordance with Sec. 60.5390b(b)(3).
(iv) Identification of each process controller which changes its
method of compliance during the reporting period and the applicable
information specified in paragraphs (b)(7)(v) through (ix) of this
section for the new method of compliance.
(v) For each process controller in the affected facility complying
with the requirements of Sec. 60.5390b(a) by routing the emissions to
a process, you must report the information specified in (b)(11)(i)
through (iii) of this section.
(vi) For each process controller in the affected facility complying
with the requirements of Sec. 60.5390b(a) by using a self-contained
natural gas-driven process controller, you must report the information
specified in paragraphs (b)(7)(vi)(A) and (B) of this section.
(A) Dates of each inspection required under Sec. 60.5416b(b); and
(B) Each defect or leak identified during each natural gas-driven-
self-contained process controller system inspection, and the date of
repair or date of anticipated repair if repair is delayed.
(vii) For each process controller in the affected facility
complying with the requirements of Sec. 60.5390b(b)(2), you must
report the information specified in paragraphs (b)(7)(vii)(A) and (B)
of this section.
(A) Dates and results of the intermittent vent process controller
monitoring required by Sec. 60.5390b(b)(2)(ii).
(B) For each instance in which monitoring identifies emissions to
the atmosphere from an intermittent vent controller during idle
periods, the date of repair or replacement or the date of anticipated
repair or replacement if the repair or replacement is delayed, and the
date and results of the re-survey after repair or replacement.
(viii) For each process controller affected facility complying with
Sec. 60.5390b(b)(3) by routing emissions to a control device, you must
report the information specified in paragraph (b)(11) of this section.
(ix) For each deviation that occurred during the reporting period,
the date and time the deviation began, the duration of the deviation in
hours, and a description of the deviation. If no deviations occurred
during the reporting period, you must include a statement that no
deviations occurred during the reporting period.
(x) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(b)(7)(vi) and (vii) and (b)(11)(i) and (ii) of this section, you must
provide the information specified in Sec. 60.5424b.
(8) For each storage vessel affected facility, the information in
paragraphs (b)(8)(i) through (x) of this section.
(i) An identification, including the location, of each storage
vessel affected facility, including those for which construction,
modification, or reconstruction commenced during the reporting period,
and those provided in previous reports. The location of the storage
vessel affected facility shall be in latitude and longitude coordinates
in decimal degrees to an accuracy and precision of five (5) decimals of
a degree using the North American Datum of 1983.
(ii) Documentation of the methane and VOC emission rate
determination according to Sec. 60.5365b(e)(1) for each tank battery
that became an affected facility during the reporting period or is
returned to service during the reporting period.
(iii) For each deviation that occurred during the reporting period
and recorded as specified in paragraph (c)(7)(iii) of this section, the
date and time the deviation began, duration of the deviation in hours
and a description of the deviation. If no deviations occurred during
the reporting period, you must include a statement that no deviations
occurred during the reporting period.
(iv) For each storage vessel affected facility constructed,
modified, reconstructed, or returned to service during the reporting
period complying with Sec. 60.5395b(a)(2) with a control device,
report the identification of the storage vessel affected facility with
the control device and the information in paragraph (b)(11)(v) of this
section.
(v) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(b)(11)(i) and (ii) of this section, you must provide the information
specified in Sec. 60.5424b.
(vi) If required to comply with Sec. 60.5395b(b)(1), the
information in paragraphs (b)(11)(i) through (iv) of this section.
(vii) You must identify each storage vessel affected facility that
is removed from service during the reporting period as specified in
Sec. 60.5395b(c)(1)(ii), including the date the storage vessel
affected facility was removed from service. You must identify each
storage vessel that that is removed from service from a storage vessel
affected facility during the reporting period as specified in Sec.
60.5395b(c)(2)(iii), including identifying the impacted storage vessel
affected facility and the date each storage vessel was removed from
service.
(viii) You must identify each storage vessel affected facility or
portion of a storage vessel affected facility returned to service
during the reporting period as specified in Sec. 60.5395b(c)(4),
including the date the storage vessel affected facility or portion of a
storage vessel affected facility was returned to service.
(ix) You must identify each storage vessel affected facility that
no longer complies with Sec. 60.5395b(a)(3) and instead complies with
Sec. 60.5395b(a)(2). You must identify whether the change in the
method of compliance was due to fracturing or refracturing or whether
the change was due to an increase in the monthly emissions
determination. If the change was due to an increase in the monthly
emissions determination, you must provide documentation of the
emissions rate. You must identify the date that you complied with Sec.
60.5395b(a)(2) and must submit the information in (b)(8)(iii) through
(vii) of this section.
[[Page 18104]]
(x) You must submit a statement that you are complying with Sec.
60.112b(a)(1) or (2), if applicable, in your initial annual report.
(9) For the fugitive emissions components affected facility, report
the information specified in paragraphs (b)(9)(i) through (v) of this
section, as applicable.
(i)(A) Designation of the type of site (i.e., well site,
centralized production facility, or compressor station) at which the
fugitive emissions components affected facility is located.
(B) For the fugitive emissions components affected facility at a
well site or centralized production facility that became an affected
facility during the reporting period, you must include the date of the
startup of production or the date of the first day of production after
modification. For the fugitive emissions components affected facility
at a compressor station that became an affected facility during the
reporting period, you must include the date of startup or the date of
modification.
(C) For the fugitive emissions components affected facility at a
well site, you must specify what type of well site it is (i.e., single
wellhead only well site, small wellsite, multi-wellhead only well site,
or a well site with major production and processing equipment).
(D) For the fugitive emissions components affected facility at a
well site where during the reporting period you complete the removal of
all major production and processing equipment such that the well site
contains only one or more wellheads, you must include the date of the
change to status as a wellhead only well site.
(E) For the fugitive emissions components affected facility at a
well site where you previously reported under paragraph (b)(9)(i)(D) of
this section the removal of all major production and processing
equipment and during the reporting period major production and
processing equipment is added back to the well site, the date that the
first piece of major production and processing equipment is added back
to the well site.
(F) For the fugitive emissions components affected facility at a
well site where during the reporting period you undertake well closure
requirements, the date of the cessation of production from all wells at
the well site, the date you began well closure activities at the well
site, and the dates of the notifications submitted in accordance with
paragraph (a)(4) of this section.
(ii) For each fugitive emissions monitoring survey performed during
the annual reporting period, the information specified in paragraphs
(b)(9)(ii)(A) through (G) of this section.
(A) Date of the survey.
(B) Monitoring instrument or, if the survey was conducted by AVO
methods, notation that AVO was used.
(C) Any deviations from the monitoring plan elements under Sec.
60.5397b(c)(1), (2), and (7), (c)(8)(i), or (d) or a statement that
there were no deviations from these elements of the monitoring plan.
(D) Number and type of components for which fugitive emissions were
detected.
(E) Number and type of fugitive emissions components that were not
repaired as required in Sec. 60.5397b(h).
(F) Number and type of fugitive emission components (including
designation as difficult-to-monitor or unsafe-to-monitor, if
applicable) on delay of repair and explanation for each delay of
repair.
(G) Date of planned shutdown(s) that occurred during the reporting
period if there are any components that have been placed on delay of
repair.
(iii) For the fugitive emissions components affected facility
complying with an alternative fugitive emissions standard under Sec.
60.5399b, in lieu of the information specified in paragraphs (b)(9)(i)
and (ii) of this section, you must provide the information specified in
paragraphs (b)(9)(iii)(A) through (C) of this section.
(A) The alternative standard with which you are complying.
(B) The site-specific reports specified by the specific alternative
fugitive emissions standard, submitted in the format in which they were
submitted to the state, local, or Tribal authority. If the report is in
hard copy, you must scan the document and submit it as an electronic
attachment to the annual report required in this paragraph (b).
(C) If the report specified by the specific alternative fugitive
emissions standard is not site-specific, you must submit the
information specified in paragraphs (b)(9)(i) and (ii) of this section
for each individual site complying with the alternative standard.
(iv) For well closure activities which occurred during the
reporting period, the information in paragraphs (b)(9)(iv)(A) and (B)
of this section.
(A) A status report with dates for the well closure activities
schedule developed in the well closure plan. If all steps in the well
closure plan are completed in the reporting period, the date that all
activities are completed.
(B) If an OGI survey is conducted during the reporting period, the
information in paragraphs (b)(9)(iv)(B)(1) through (3) of this section.
(1) Date of the OGI survey.
(2) Monitoring instrument used.
(3) A statement that no fugitive emissions were found, or if
fugitive emissions were found, a description of the steps taken to
eliminate those emissions, the date of the resurvey, the results of the
resurvey, and the date of the final resurvey which detected no
emissions.
(v) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(b)(9)(i) and (ii) of this section, you must provide the information
specified in Sec. 60.5424b.
(10) For each pump affected facility, the information specified in
paragraphs (b)(10)(i) through (iv) of this section in your initial
annual report and in subsequent annual reports for each pump affected
facility that is constructed, modified, or reconstructed during the
reporting period. Each annual report must contain the information
specified in paragraphs (b)(10)(v) through (ix) of this section for
each pump affected facility.
(i) The identification of each of your pumps that are driven by
natural gas, as required by Sec. 60.5393b(a) that allows traceability
to the records required by paragraph (c)(15)(i) of this section.
(ii) For each pump affected facility for which there is a control
device on site but it does not achieve a 95.0 percent emissions
reduction, the certification that there is a control device available
on site but it does not achieve a 95.0 percent emissions reduction
required under Sec. 60.5393b(b)(5). You must also report the emissions
reduction percentage the control device is designed to achieve.
(iii) For each pump affected facility for which there is no control
device or vapor recovery unit on site, the certification required under
Sec. 60.5393b(b)(6) that there is no control device or vapor recovery
unit on site.
(iv) For each pump affected facility for which it is technically
infeasible to route the emissions to a process or control device, the
certification of technically infeasibility required under Sec.
60.5393b(b)(7).
(v) For any pump affected facility which has previously reported as
required under paragraphs (b)(10)(i) through (iv) of this section and
for which a change in the reported condition has occurred during the
reporting period, provide the identification of the pump affected
facility and the date that the pump affected facility meets one of the
change
[[Page 18105]]
conditions described in paragraph (b)(10)(v)(A), (B), or (C) of this
section.
(A) If you install a control device or vapor recovery unit, you
must report that a control device or vapor recovery unit has been added
to the site and that the pump affected facility now is required to
comply with Sec. 60.5393b(b)(2), (3) or (5), as applicable.
(B) If your pump affected facility previously complied with Sec.
60.5393b(b)(2), (3) or (5) by routing emissions to a process or a
control device and the process or control device is subsequently
removed from the site or is no longer available such that there is no
ability to route the emissions to a process or control device at the
site, or that it is not technically feasible to capture and route the
emissions to another control device or process located on site, report
that you are no longer complying with the applicable requirements of
Sec. 60.5393b(b)(2), (3), or (5) and submit the information provided
in paragraph (b)(10)(v)(B)(1) or (2) of this section.
(1) Certification that there is no control device or vapor recovery
unit on site.
(2) Certification of the engineering assessment that it is
technically infeasible to capture and route the emissions to another
control device or process located on site.
(C) If any pump affected facility or individual natural gas-driven
pump changes its method of compliance during the reporting period other
than for the reasons specified in paragraphs (b)(10)(v)(A) and (B) of
this section, identify the new compliance method for each natural gas-
driven pump within the affected facility which changes its method of
compliance during the reporting period and provide the applicable
information specified in paragraphs (b)(10)(ii) through (iv) and (vi)
through (viii) of this section for the new method of compliance.
(vi) For each pump affected facility complying with the
requirements of Sec. 60.5393b(a) or (b)(1) or (3) by routing the
emissions to a process, you must report the information specified in
paragraphs (b)(11)(i) through (iv) of this section.
(vii) For each pump affected facility complying with the
requirements of Sec. 60.5393b(b)(3) or (5) by routing the emissions to
a control device, you must report the information required under
paragraphs (b)(11)(i) through (v) of this section.
(viii) For each deviation that occurred during the reporting
period, the date and time the deviation began, the duration of the
deviation in hours, and a description of the deviation. If no
deviations occurred during the reporting period, you must include a
statement that no deviations occurred during the reporting period.
(ix) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(b)(11)(i) and (ii) of this section, you must provide the information
specified in Sec. 60.5424b.
(11) For each well, centrifugal compressor, reciprocating
compressor, storage vessel, process controller, pump, or process unit
equipment affected facility which uses a closed vent system routed to a
control device to meet the emissions reduction standard, you must
submit the information in paragraphs (b)(11)(i) through (v) of this
section. For each reciprocating compressor, process controller, pump,
storage vessel, or process unit equipment which uses a closed vent
system to route to a process, you must submit the information in
paragraphs (b)(11)(i) through (iv) of this section. For each
centrifugal compressor, reciprocating compressor, and storage vessel
equipped with a cover, you must submit the information in paragraphs
(b)(11)(i) and (ii) of this section.
(i) Dates of each inspection required under Sec. 60.5416b(a) and
(b).
(ii) Each defect or emissions identified during each inspection and
the date of repair or the date of anticipated repair if the repair is
delayed.
(iii) Date and time of each bypass alarm or each instance the key
is checked out if you are subject to the bypass requirements of Sec.
60.5416b(a)(4).
(iv) You must submit the certification signed by the qualified
professional engineer or in-house engineer according to Sec.
60.5411b(c) for each closed vent system routing to a control device or
process in the reporting year in which the certification is signed.
(v) If you comply with the emissions standard for your well,
centrifugal compressor, reciprocating compressor, storage vessel,
process controller, pump, or process unit equipment affected facility
with a control device, the information in paragraphs (b)(11)(v)(A)
through (L) of this section, unless you use an enclosed combustion
device or flare using an alternative test method approved under Sec.
60.5412b(d). If you use an enclosed combustion device or flare using an
alternative test method approved under Sec. 60.5412b(d), the
information in paragraphs (b)(11)(v)(A) through (C) and (L) through (P)
of this section.
(A) Identification of the control device.
(B) Make, model, and date of installation of the control device.
(C) Identification of the affected facility controlled by the
device.
(D) For each continuous parameter monitoring system used to
demonstrate compliance for the control device, a unique continuous
parameter monitoring system identifier and the make, model number, and
date of last calibration check of the continuous parameter monitoring
system.
(E) For each instance where there is a deviation of the control
device in accordance with Sec. 60.5417b(g)(1) through (3) or (g)(5)
through (7) include the date and time the deviation began, the duration
of the deviation in hours, the type of the deviation (e.g., NHV
operating limit, lack of pilot or combustion flame, condenser
efficiency, bypass line flow, visible emissions), and cause of the
deviation.
(F) For each instance where there is a deviation of the continuous
parameter monitoring system in accordance with Sec. 60.5417b(g)(4)
include the date and time the deviation began, the duration of the
deviation in hours, and cause of the deviation.
(G) For each visible emissions test following return to operation
from a maintenance or repair activity, the date of the visible
emissions test or observation of the video surveillance output, the
length of the observation in minutes, and the number of minutes for
which visible emissions were present.
(H) If a performance test was conducted on the control device
during the reporting period, provide the date the performance test was
conducted. Submit the performance test report following the procedures
specified in paragraph (b)(12) of this section.
(I) An indication of whether the enclosed combustion device or
flare receives inert gases or other vent streams which may lower the
NHV of the combined stream, and if so, a description of the operating
scenario(s) which may lower the NHV of the combined stream through the
introduction of inert gases or other vent gas streams. If a
demonstration of the NHV of the inlet gas to the enclosed combustion
device or flare was conducted during the reporting period in accordance
with Sec. 60.5417b(d)(8)(iii), an indication of whether this is a re-
evaluation of vent gas NHV and the reason for the re-evaluation; the
applicable required minimum vent gas NHV; if twice daily samples of the
vent stream were taken, the number of samples with NHV values that are
less than 1.2 times the applicable required minimum NHV, an indication
of whether full one hour samples were
[[Page 18106]]
collected or if shorter sampling times were used, and, if shorter
sampling times were used, the collection time(s) used and the reason
for not obtaining a full one hour sample; if continuous NHV sampling of
the vent stream was conducted, the number of hourly block average NHV
values that are less than the required minimum vent gas NHV; if
continuous combustion efficiency monitoring was conducted using an
alternative test method approved under Sec. 60.5412b(d), the number of
values of the combustion efficiency that were less than 95.0 percent;
the resulting determination of whether continuous NHV monitoring is
required or not in accordance with Sec. 60.5417b(d)(8)(iii)(D), (E),
or (H); and if the enclosed combustion device or flare received inert
gases or other vent streams which may lower the NHV of the combined
stream, whether the sampling included periods where the highest
percentage of inert gases or other gases which may lower the NHV of the
combined stream were sent to the enclosed combustion device or flare.
(J) If a demonstration was conducted in accordance with Sec.
60.5417b(d)(8)(iv) that the maximum potential pressure of units
manifolded to an enclosed combustion device or flare cannot cause the
maximum inlet flow rate established in accordance with Sec.
60.5417b(f)(1) or a flare tip velocity limit of 18.3 meter/second (60
feet/second) to be exceeded, an indication of whether this is a re-
evaluation of the gas flow and the reason for the re-evaluation; the
demonstration conducted; and applicable engineering calculations.
(K) For each periodic sampling event conducted under Sec.
60.5417b(d)(8)(iii)(G), provide the date of the sampling, the required
minimum vent gas NHV, and the NHV value for each vent gas sample.
(L) For each flare and enclosed combustion device, provide the date
each device is observed with OGI in accordance with Sec.
60.5415b(f)(1)(x) and whether uncombusted emissions were present.
Provide the date each device was visibly observed during an AVO
inspection in accordance with Sec. 60.5415b(f)(1)(x), whether the
pilot or combustion flame was lit at the time of observation, and
whether the device was found to be operating properly.
(M) An identification of the alternative test method used.
(N) For each instance where there is a deviation of the control
device in accordance with Sec. 60.5417b(i)(6)(i) or (iii) through (v)
include the date and time the deviation began, the duration of the
deviation in hours, the type of the deviation (e.g., NHVcz
operating limit, lack of pilot or combustion flame, visible emissions),
and cause of the deviation.
(O) For each instance where there is a deviation of the data
availability in accordance with Sec. 60.5417b(i)(6)(ii) include the
date of each operating day when monitoring data are not available for
at least 75 percent of the operating hours.
(P) If no deviations occurred under paragraph (b)(11)(v)(N) or (O)
of this section, a statement that there were no deviations for the
control device during the annual report period.
(Q) Any additional information required to be reported as specified
by the Administrator as part of the alternative test method approval
under Sec. 60.5412b(d).
(12) Within 60 days after the date of completing each performance
test (see Sec. 60.8) required by this subpart, except testing
conducted by the manufacturer as specified in Sec. 60.5413b(d), you
must submit the results of the performance test following the
procedures specified in paragraph (d) of this section. Data collected
using test methods that are supported by the EPA's Electronic Reporting
Tool (ERT) as listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at
the time of the test must be submitted in a file format generated using
the EPA's ERT. Alternatively, you may submit an electronic file
consistent with the extensible markup language (XML) schema listed on
the EPA's ERT website. Data collected using test methods that are not
supported by the EPA's ERT as listed on the EPA's ERT website at the
time of the test must be included as an attachment in the ERT or
alternate electronic file.
(13) For combustion control devices tested by the manufacturer in
accordance with Sec. 60.5413b(d), an electronic copy of the
performance test results required by Sec. 60.5413b(d) shall be
submitted via email to [email protected] unless the test results
for that model of combustion control device are posted at the following
website: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.
(14) If you had a super-emitter event during the reporting period,
the start date of the super-emitter event, the duration of the super-
emitter event in hours, and the affected facility associated with the
super-emitter event, if applicable.
(15) You must submit your annual report using the appropriate
electronic report template on the Compliance and Emissions Data
Reporting Interface (CEDRI) website for this subpart and following the
procedure specified in paragraph (d) of this section. If the reporting
form specific to this subpart is not available on the CEDRI website at
the time that the report is due, you must submit the report to the
Administrator at the appropriate address listed in Sec. 60.4. Once the
form has been available on the CEDRI website for at least 90 calendar
days, you must begin submitting all subsequent reports via CEDRI. The
date reporting forms become available will be listed on the CEDRI
website. Unless the Administrator or delegated state agency or other
authority has approved a different schedule for submission of reports,
the report must be submitted by the deadline specified in this subpart,
regardless of the method in which the report is submitted.
(c) * * *
(3) For each associated gas well, you must maintain the applicable
records specified in paragraphs (c)(3)(i) or (ii) and (iii), (iv), (v)
and (vi) of this section, as applicable.
(i) For each associated gas well that complies with the
requirements of Sec. 60.5377b(a)(1), (2), (3), or (4), you must keep
the records specified in paragraphs (c)(3)(i)(A) and (B).
(A) Documentation of the specific method(s) in Sec.
60.5377b(a)(1), (2), (3), or (4) that is used.
(B) For instances where you temporarily route the associated gas to
a flare or control device in accordance with Sec. 60.5377b(d), you
must keep the records specified in paragraphs (c)(3)(i)(B)(1) through
(3).
(1) The reason in Sec. 60.5377b(d)(1), (2), (3), or (4) for each
incident.
(2) The date of each incident, along with the times when routing
the associated gas to the flare or control device started and ended,
along with the total duration of each incident.
(3) Documentation that all CVS requirements specified in Sec.
60.5411b(a) and (c) and all applicable flare or control device
requirements specified in Sec. 60.5412b are met during each period
when the associated gas is routed to the flare or control device.
(ii) For instances where you temporarily vent the associated gas in
accordance with Sec. 60.5377b(e), you must keep the records specified
in paragraphs (c)(3)(ii)(A) through (D) of this section. These records
are required if you are routinely complying with Sec. 60.5377b(a) or
Sec. 60.5377b(f) or temporarily complying with Sec. 60.5377b(d).
(A) The reason in Sec. 60.5377b(e)(1), (2), or (3) for each
incident.
(B) The date of each incident, along with the times when venting
the
[[Page 18107]]
associated gas started and ended, along with the total duration of each
incident.
(C) The VOC and methane emissions that were emitted during each
incident.
(D) The cumulative duration of venting incidents and VOC and
methane emissions for all incidents in each calendar year.
(iii) For each associated gas well that complies with the
requirements of Sec. 60.5377b(f) because it has demonstrated that it
is not feasible to comply with Sec. 60.5377b(a)(1) through (4) due to
technical reasons in accordance with Sec. 60.5377b(g), records of each
annual demonstration and certification of the technical reason that it
is not feasible to comply with Sec. 60.5377b(a)(1) through (4) in
accordance with Sec. 60.5377b(g).
(iv) For each associated gas well that complies with the
requirements of Sec. 60.5377b(f), meet the recordkeeping requirements
specified in paragraphs (c)(3)(iv)(A) through (E) of this section.
(A) Identification of each instance when associated gas was vented
and not routed to a control device that reduces VOC and methane
emissions by at least 95.0 percent.
(B) If you comply with the emission reduction standard in Sec.
60.5377b with a control device, the information for each control device
in paragraphs (c)(11) and (13) of this section.
(C) Records of the closed vent system inspection as specified in
paragraph (c)(8) of this section. If you comply with an alternative GHG
and VOC standard under Sec. 60.5398b, in lieu of the information
specified in paragraph (c)(8) of this section, you must maintain
records of the information specified in Sec. 60.5424b.
(D) If applicable, the records of bypass monitoring as specified in
paragraph (c)(10) of this section.
(E) Records of the closed vent system assessment as specified in
paragraph (c)(12) of this section.
(v) For each instance where you route associated gas to a flare or
control device beyond 72 hours due to an ``exigent circumstance''
according to Sec. 60.5377b(d)(1) or (2), you must maintain the records
specified in paragraphs (c)(3)(v)(A) through (D) of this section.
(A) A written description of the ``exigent circumstance'' requiring
the need to flare or route to a control device beyond 72 hours.
(B) A description of the steps taken to resolve the need for
temporary flaring/routing to a control device;
(C) The dates and times an identified ``exigent circumstance''
started and ended (e.g., when owners or operators are able to access
site, when personnel and/or equipment are available) and the total
duration of each ``exigent circumstance''; and
(D) The dates and times temporary flaring/routing to a control
device started and ended and the total duration of temporary flaring/
routing to a control device due to the identified ``exigent
circumstance.''
(vi) Records of each deviation, the date and time the deviation
began, the duration of the deviation, and a description of the
deviation.
(4) For each centrifugal compressor affected facility, you must
maintain the records specified in paragraphs (c)(4)(i) through (iii) of
this section.
(i) For each centrifugal compressor affected facility, you must
maintain records of deviations in cases where the centrifugal
compressor was not operated in compliance with the requirements
specified in Sec. 60.5380b, including a description of each deviation,
the date and time each deviation began and the duration of each
deviation.
(ii) For each wet seal compressor complying with the emissions
reduction standard in Sec. 60.5380b(a)(1), you must maintain the
records in paragraphs (c)(4)(ii)(A) through (E) of this section. For
each wet seal compressor complying with the alternative standard in
Sec. 60.5380b(a)(3) by routing the closed vent system to a process,
you must maintain the records in paragraphs (c)(4)(ii)(B) through (E)
of this section.
(A) If you comply with the emission reduction standard in Sec.
60.5380b(a)(1) with a control device, the information for each control
device in paragraph (c)(11) of this section.
(B) Records of the closed vent system inspection as specified in
paragraph (c)(8) of this section. If you comply with an alternative GHG
and VOC standard under Sec. 60.5398b, in lieu of the information
specified in paragraph (c)(8) of this section, you must maintain the
information specified in Sec. 60.5424b.
(C) Records of the cover inspections as specified in paragraph
(c)(9) of this section. If you comply with an alternative GHG and VOC
standard under Sec. 60.5398b, in lieu of the information specified in
paragraphs (c)(9) of this section, you must maintain the information
specified in Sec. 60.5424b.
(D) If applicable, the records of bypass monitoring as specified in
paragraph (c)(10) of this section.
(E) Records of the closed vent system assessment as specified in
paragraph (c)(12) of this section.
(iii) For each centrifugal compressor affected facility using a
self-contained wet seal compressor, centrifugal compressor equipped
with sour seal oil separator and capture system, or dry seal compressor
complying with the standard in Sec. 60.5380b(a)(4), (5) or (6), you
must maintain the records specified in paragraphs (c)(4)(iii)(A)
through (H) of this section.
(A) Records of the cumulative number of hours of operation since
initial startup, since May 7, 2024, or since the previous volumetric
flow rate measurement, as applicable.
(B) A description of the method used and the results of the
volumetric flow rate measurement or emissions screening, as applicable.
(C) Records for all flow meters, composition analyzers and pressure
gauges used to measure volumetric flow rates as specified in paragraphs
(c)(4)(iii)(C)(1) through (6).
(1) Description of standard method published by a consensus-based
standards organization or industry standard practice.
(2) Records of volumetric flow rate emissions calculations
conducted according to paragraphs Sec. 60.5380b(a)(4) through (6), as
applicable.
(3) Records of manufacturer's operating procedures and measurement
methods.
(4) Records of manufacturer's recommended procedures or an
appropriate industry consensus standard method for calibration and
results of calibration, recalibration, and accuracy checks.
(5) Records which demonstrate that measurements at the remote
location(s) can, when appropriate correction factors are applied,
reliably and accurately represent the actual temperature or total
pressure at the flow meter under all expected ambient conditions. You
must include the date of the demonstration, the data from the
demonstration, the mathematical correlation(s) between the remote
readings and actual flow meter conditions derived from the data, and
any supporting engineering calculations. If adjustments were made to
the mathematical relationships, a record and description of such
adjustments.
(6) Record of each initial calibration or a recalibration which
failed to meet the required accuracy specification and the date of the
successful recalibration.
(D) Date when performance-based volumetric flow rate is exceeded.
(E) The date of successful repair of the compressor seal, including
follow-up performance-based volumetric flow rate measurement to confirm
successful repair.
(F) Identification of each compressor seal placed on delay of
repair and explanation for each delay of repair.
(G) For each compressor seal or part needed for repair placed on
delay of
[[Page 18108]]
repair because of replacement seal or part unavailability, the operator
must document: the date the seal or part was added to the delay of
repair list, the date the replacement seal or part was ordered, the
anticipated seal or part delivery date (including any estimated
shipment or delivery date provided by the vendor), and the actual
arrival date of the seal or part.
(H) Date of planned shutdowns that occur while there are any seals
or parts that have been placed on delay of repair.
(5) For each reciprocating compressor affected facility, you must
maintain the records in paragraphs (c)(5)(i) through (x) and (c)(8)
through (13) of this section, as applicable. If you comply with an
alternative GHG and VOC standard under Sec. 60.5398b, in lieu of the
information specified in paragraph (c)(8) of this section, you must
provide the information specified in Sec. 60.5424b.
(i) For each reciprocating compressor affected facility, you must
maintain records of deviations in cases where the reciprocating
compressor was not operated in compliance with the requirements
specified in Sec. 60.5385b, including a description of each deviation,
the date and time each deviation began and the duration of each
deviation in hours.
(ii) Records of the date of installation of a rod packing emissions
collection system and closed vent system as specified in Sec.
60.5385b(d).
(iii) Records of the cumulative number of hours of operation since
initial startup, since May 7, 2024, or since the previous volumetric
flow rate measurement, as applicable. Alternatively, a record that
emissions from the rod packing are being routed to a process through a
closed vent system.
(iv) A description of the method used and the results of the
volumetric flow rate measurement or emissions screening, as applicable.
(v) Records for all flow meters, composition analyzers and pressure
gauges used to measure volumetric flow rates as specified in paragraphs
(c)(5)(v)(A) through (F).
(A) Description of standard method published by a consensus-based
standards organization or industry standard practice.
(B) Records of volumetric flow rate calculations conducted
according to Sec. 60.5385b(b) or (c), as applicable.
(C) Records of manufacturer operating procedures and measurement
methods.
(D) Records of manufacturer's recommended procedures or an
appropriate industry consensus standard method for calibration and
results of calibration, recalibration, and accuracy checks.
(E) Records which demonstrate that measurements at the remote
location(s) can, when appropriate correction factors are applied,
reliably and accurately represent the actual temperature or total
pressure at the flow meter under all expected ambient conditions. You
must include the date of the demonstration, the data from the
demonstration, the mathematical correlation(s) between the remote
readings and actual flow meter conditions derived from the data, and
any supporting engineering calculations. If adjustments were made to
the mathematical relationships, a record and description of such
adjustments.
(F) Record of each initial calibration or a recalibration which
failed to meet the required accuracy specification and the date of the
successful recalibration.
(vi) Date when performance-based volumetric flow rate is exceeded.
(vii) The date of successful replacement or repair of reciprocating
compressor rod packing, including follow-up performance-based
volumetric flow rate measurement to confirm successful repair.
(viii) Identification of each reciprocating compressor placed on
delay of repair because of rod packing or part unavailability and
explanation for each delay of repair.
(ix) For each reciprocating compressor that is placed on delay of
repair because of replacement rod packing or part unavailability, the
operator must document: the date the rod packing or part was added to
the delay of repair list, the date the replacement rod packing or part
was ordered, the anticipated rod packing or part delivery date
(including any estimated shipment or delivery date provided by the
vendor), and the actual arrival date of the rod packing or part.
(x) Date of planned shutdowns that occur while there are any
reciprocating compressors that have been placed on delay of repair due
to the unavailability of rod packing or parts to conduct repairs.
(6) For each process controller affected facility, you must
maintain the records specified in paragraphs (c)(6)(i) through (vii) of
this section.
(i) Records identifying each process controller that is driven by
natural gas and that does not function as an emergency shutdown device.
(ii) For each process controller affected facility complying with
Sec. 60.5390b(a), you must maintain records of the information
specified in paragraphs (c)(6)(ii)(A) and (B) of this section, as
applicable.
(A) If you are complying with Sec. 60.5390b(a) by routing process
controller vapors to a process through a closed vent system, you must
report the information specified in paragraphs (c)(6)(ii)(A)(1) and (2)
of this section.
(1) An identification of all the natural gas-driven process
controllers in the process controller affected facility for which you
collect and route vapors to a process through a closed vent system.
(2) The records specified in paragraphs (c)(8), (10), and (12) of
this section. If you comply with an alternative GHG and VOC standard
under Sec. 60.5398b, in lieu of the information specified in paragraph
(c)(8) of this section, you must provide the information specified in
Sec. 60.5424b.
(B) If you are complying with Sec. 60.5390b(a) by using a self-
contained natural gas-driven process controller, you must report the
information specified in paragraphs (c)(6)(ii)(B)(1) through (3) of
this section.
(1) An identification of each process controller complying with
Sec. 60.5390b(a) by using a self-contained natural gas-driven process
controller;
(2) Dates of each inspection required under Sec. 60.5416b(b); and
(3) Each defect or leak identified during each natural gas-driven-
self-contained process controller system inspection, and date of repair
or date of anticipated repair if repair is delayed.
(iii) For each process controller affected facility complying with
the Sec. 60.5390b(b)(1) process controller bleed rate requirements,
you must maintain records of the information specified in paragraphs
(c)(6)(iii)(A) and (B) of this section.
(A) The identification of process controllers designed and operated
to achieve a bleed rate less than or equal to 6 scfh and records of the
manufacturer's specifications indicating that the process controller is
designed with a natural gas bleed rate of less than or equal to 6 scfh.
(B) Where necessary to meet a functional need, the identification
of the process controller and demonstration of why it is necessary to
use a process controller with a natural gas bleed rate greater than 6
scfh.
(iv) For each intermittent vent process controller in the affected
facility complying with the requirements in paragraphs Sec.
60.5390b(b)(2), you must keep records of the information specified in
paragraphs (c)(6)(iv)(A) through (C) of this section.
(A) The identification of each intermittent vent process
controller.
(B) Dates and results of the intermittent vent process controller
monitoring required by Sec. 60.5390b(b)(2)(ii).
[[Page 18109]]
(C) For each instance in which monitoring identifies emissions to
the atmosphere from an intermittent vent controller during idle
periods, the date of repair or replacement, or the date of anticipated
repair or replacement if the repair or replacement is delayed and the
date and results of the re-survey after repair or replacement.
(v) For each process controller affected facility complying with
Sec. 60.5390b(b)(3), you must maintain the records specified in
paragraphs (c)(6)(v)(A) and (B) of this section.
(A) An identification of each process controller for which
emissions are routed to a control device.
(B) Records specified in paragraphs (c)(8) and (10) through (13) of
this section. If you comply with an alternative GHG and VOC standard
under Sec. 60.5398b, in lieu of the information specified in paragraph
(c)(8) of this section, you must provide the information specified in
Sec. 60.5424b.
(vi) Records of each change in compliance method, including
identification of each natural gas-driven process controller which
changes its method of compliance, the new method of compliance, and the
date of the change in compliance method.
(vii) Records of each deviation, the date and time the deviation
began, the duration of the deviation, and a description of the
deviation.
* * * * *
(11) Records for each control device used to comply with the
emission reduction standard in Sec. 60.5377b(d) or (f) for associated
gas wells, Sec. 60.5380b(a)(1) or (9) for centrifugal compressor
affected facilities, Sec. 60.5385b(d)(2) for reciprocating compressor
affected facilities, Sec. 60.5390b(b)(3) for your process controller
affected facility in Alaska, Sec. 60.5393b(b)(3) for your pump
affected facility, Sec. 60.5395b(a)(2) for your storage vessel
affected facility, Sec. 60.5376b(g) for well affected facility gas
well liquids unloading, or Sec. 60.5400b(f) or 60.5401b(e) for your
process equipment affected facility, as required in paragraphs
(c)(11)(i) through (viii) of this section. If you use an enclosed
combustion device or flare using an alternative test method approved
under Sec. 60.5412b(d), keep records of the information in paragraph
(c)(11)(ix) of this section, in lieu of the records required by
paragraphs (c)(11)(i) through (iv) and (vi) through (viii) of this
section.
(i) For a control device tested under Sec. 60.5413b(d) which meets
the criteria in Sec. 60.5413b(d)(11) and (e), keep records of the
information in paragraphs (c)(11)(i)(A) through (E) of this section, in
addition to the records in paragraphs (c)(11)(ii) through (ix) of this
section, as applicable.
(A) Serial number of purchased device and copy of purchase order.
(B) Location of the affected facility associated with the control
device in latitude and longitude coordinates in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using the North
American Datum of 1983.
(C) Minimum and maximum inlet gas flow rate specified by the
manufacturer.
(D) Records of the maintenance and repair log as specified in Sec.
60.5413b(e)(4), for all inspection, repair, and maintenance activities
for each control device failing the visible emissions test.
(E) Records of the manufacturer's written operating instructions,
procedures, and maintenance schedule to ensure good air pollution
control practices for minimizing emissions.
(ii) For all control devices, keep records of the information in
paragraphs (c)(11)(ii)(A) through (G) of this section, as applicable.
(A) Make, model, and date of installation of the control device,
and identification of the affected facility controlled by the device.
(B) Records of deviations in accordance with Sec. 60.5417b(g)(1)
through (7), including a description of the deviation, the date and
time the deviation began, the duration of the deviation, and the cause
of the deviation.
(C) The monitoring plan required by Sec. 60.5417b(c)(2).
(D) Make and model number of each continuous parameter monitoring
system.
(E) Records of minimum and maximum operating parameter values,
continuous parameter monitoring system data (including records that the
pilot or combustion flame is present at all times), calculated averages
of continuous parameter monitoring system data, and results of all
compliance calculations.
(F) Records of continuous parameter monitoring system equipment
performance checks, system accuracy audits, performance evaluations, or
other audit procedures and results of all inspections specified in the
monitoring plan in accordance with Sec. 60.5417b(c)(2). Records of
calibration gas cylinders, if applicable.
(G) Periods of monitoring system malfunctions, repairs associated
with monitoring system malfunctions and required monitoring system
quality assurance or quality control activities Records of repairs on
the monitoring system.
(iii) For each carbon adsorption system, records of the schedule
for carbon replacement as determined by the design analysis
requirements of Sec. 60.5413b(c)(2) and (3) and records of each carbon
replacement as specified in Sec. Sec. 60.5412b(c)(1) and
60.5415b(f)(1)(viii).
(iv) For enclosed combustion devices and flares, records of visible
emissions observations as specified in paragraph (c)(11)(iv)(A) or (B)
of this section.
(A) Records of observations with Method 22 of appendix A-7 to this
part, including observations required following return to operation
from a maintenance or repair activity, which include: company,
location, company representative (name of the person performing the
observation), sky conditions, process unit (type of control device),
clock start time, observation period duration (in minutes and seconds),
accumulated emission time (in minutes and seconds), and clock end time.
You may create your own form including the above information or use
Figure 22-1 in Method 22 of appendix A-7 to this part.
(B) If you monitor visible emissions with a video surveillance
camera, location of the camera and distance to emission source, records
of the video surveillance output, and documentation that an operator
looked at the feed daily, including the date and start time of
observation, the length of observation, and length of time visible
emissions were present.
(v) For enclosed combustion devices and flares, video of the OGI
inspection conducted in accordance with Sec. 60.5415b(f)(1)(x).
Records documenting each enclosed combustion device and flare was
visibly observed during each inspection conducted under Sec. 60.5397b
using AVO in accordance with Sec. 60.5415b(f)(1)(x).
(vi) For enclosed combustion devices and flares, an indication of
whether the enclosed combustion device or flare receives inert gases or
other vent streams which may lower the NHV of the combined stream, and
if so, a description of the operating scenario(s) which may lower the
NHV of the combined stream through the introduction of inert gases or
other vent gas streams. Records of each demonstration of the NHV of the
inlet gas to the enclosed combustion device or flare conducted in
accordance with Sec. 60.5417b(d)(8)(iii), including the sampling
approach used (continuous NHV, twice daily sampling, alternative
method), the date, time and results of each analysis, and, if shorter
sampling
[[Page 18110]]
times were used with twice daily sampling, the collection time(s) used
and the reason for not obtaining a full one hour sample. For each re-
evaluation of the NHV of the inlet gas, records of process changes and
explanation of the conditions that led to the need to re-evaluation the
NHV of the inlet gas. For each demonstration where the enclosed
combustion device or flare received inert gases, record the highest
percentage of inert gases that can be sent to the enclosed combustion
device or flare and the highest percent of inert gases sent to the
enclosed combustion device or flare during the NHV demonstration.
Records of periodic sampling conducted under Sec.
60.5417b(d)(8)(iii)(G).
(vii) For enclosed combustion devices and flares, if you use a
backpressure regulator valve, the make and model of the valve, date of
installation, and record of inlet flow rating. Maintain records of the
engineering evaluation and manufacturer specifications that identify
the pressure set point corresponding to the minimum inlet gas flow
rate, the annual confirmation that the backpressure regulator valve set
point is correct and consistent with the engineering evaluation and
manufacturer specifications, and the annual confirmation that the
backpressure regulator valve fully closes when not in open position.
(viii) For enclosed combustion devices and flares, records of each
demonstration required under Sec. 60.5417b(d)(8)(iv).
(ix) If you use an enclosed combustion device or flare using an
alternative test method approved under Sec. 60.5412b(d), keep records
of the information in paragraphs (c)(11)(ix)(A) through (H) of this
section, in lieu of the records required by paragraphs (c)(11)(i)
through (iv) and (vi) through (viii) of this section.
(A) An identification of the alternative test method used.
(B) Data recorded at the intervals required by the alternative test
method.
(C) Monitoring plan required by Sec. 60.5417(i)(2).
(D) Quality assurance and quality control activities conducted in
accordance with the alternative test method.
(E) If required by Sec. 60.5412b(d)(4) to conduct visible
emissions observations, records required by paragraph (c)(11)(iv) of
this section.
(F) If required by Sec. 60.5412b(d)(5) to conduct pilot or
combustion flame monitoring, record indicating the presence of a pilot
or combustion flame and periods when the pilot or combustion flame is
absent.
(G) For each instance where there is a deviation of the control
device in accordance with Sec. 60.5417b(i)(6)(i) through (v), the date
and time the deviation began, the duration of the deviation in hours,
and cause of the deviation.
(H) Any additional information required to be recorded as specified
by the Administrator as part of the alternative test method approval
under Sec. 60.5412b(d).
(12) For each closed vent system routing to a control device or
process, the records of the assessment conducted according to Sec.
60.5411b(c):
(i) A copy of the assessment conducted according to Sec.
60.5411b(c)(1); and
(ii) A copy of the certification according to Sec.
60.5411b(c)(1)(i) and (ii).
(13) A copy of each performance test submitted under paragraph
(b)(12) or (13) of this section.
(14) For the fugitive emissions components affected facility,
maintain the records identified in paragraphs (c)(14)(i) through (viii)
of this section.
(i) The date of the startup of production or the date of the first
day of production after modification for the fugitive emissions
components affected facility at a well site and the date of startup or
the date of modification for the fugitive emissions components affected
facility at a compressor station.
(ii) For the fugitive emissions components affected facility at a
well site, you must maintain records specifying what type of well site
it is (i.e., single wellhead only well site, small wellsite, multi-
wellhead only well site, or a well site with major production and
processing equipment.)
(iii) For the fugitive emissions components affected facility at a
well site where you complete the removal of all major production and
processing equipment such that the well site contains only one or more
wellheads, record the date the well site completes the removal of all
major production and processing equipment from the well site, and, if
the well site is still producing, record the well ID or separate tank
battery ID receiving the production from the well site. If major
production and processing equipment is subsequently added back to the
well site, record the date that the first piece of major production and
processing equipment is added back to the well site.
(iv) The fugitive emissions monitoring plan as required in Sec.
60.5397b(b), (c), and (d).
(v) The records of each monitoring survey as specified in
paragraphs (c)(14)(v)(A) through (I) of this section.
(A) Date of the survey.
(B) Beginning and end time of the survey.
(C) Name of operator(s), training, and experience of the
operator(s) performing the survey.
(D) Monitoring instrument or method used.
(E) Fugitive emissions component identification when Method 21 of
appendix A-7 to this part is used to perform the monitoring survey.
(F) Ambient temperature, sky conditions, and maximum wind speed at
the time of the survey. For compressor stations, operating mode of each
compressor (i.e., operating, standby pressurized, and not operating-
depressurized modes) at the station at the time of the survey.
(G) Any deviations from the monitoring plan or a statement that
there were no deviations from the monitoring plan.
(H) Records of calibrations for the instrument used during the
monitoring survey.
(I) Documentation of each fugitive emission detected during the
monitoring survey, including the information specified in paragraphs
(c)(14)(v)(I)(1) through (9) of this section.
(1) Location of each fugitive emission identified.
(2) Type of fugitive emissions component, including designation as
difficult-to-monitor or unsafe-to-monitor, if applicable.
(3) If Method 21 of appendix A-7 to this part is used for
detection, record the component ID and instrument reading.
(4) For each repair that cannot be made during the monitoring
survey when the fugitive emissions are initially found, a digital
photograph or video must be taken of that component or the component
must be tagged for identification purposes. The digital photograph must
include the date that the photograph was taken and must clearly
identify the component by location within the site (e.g., the latitude
and longitude of the component or by other descriptive landmarks
visible in the picture). The digital photograph or identification
(e.g., tag) may be removed after the repair is completed, including
verification of repair with the resurvey.
(5) The date of first attempt at repair of the fugitive emissions
component(s).
(6) The date of successful repair of the fugitive emissions
component, including the resurvey to verify repair and instrument used
for the resurvey.
(7) Identification of each fugitive emission component placed on
delay of repair and explanation for each delay of repair.
[[Page 18111]]
(8) For each fugitive emission component placed on delay of repair
for reason of replacement component unavailability, the operator must
document: the date the component was added to the delay of repair list,
the date the replacement fugitive component or part thereof was
ordered, the anticipated component delivery date (including any
estimated shipment or delivery date provided by the vendor), and the
actual arrival date of the component.
(9) Date of planned shutdowns that occur while there are any
components that have been placed on delay of repair.
(vi) For the fugitive emissions components affected facility
complying with an alternative means of emissions limitation under Sec.
60.5399b, you must maintain the records specified by the specific
alternative fugitive emissions standard for a period of at least 5
years.
(vii) For well closure activities, you must maintain the
information specified in paragraphs (c)(14)(vii)(A) through (G) of this
section.
(A) The well closure plan developed in accordance with Sec.
60.5397b(l) and the date the plan was submitted.
(B) The notification of the intent to close the well site and the
date the notification was submitted.
(C) The date of the cessation of production from all wells at the
well site.
(D) The date you began well closure activities at the well site.
(E) Each status report for the well closure activities reported in
paragraph (b)(9)(iv)(A) of this section.
(F) Each OGI survey reported in paragraph (b)(9)(iv)(B) of this
section including the date, the monitoring instrument used, and the
results of the survey or resurvey.
(G) The final OGI survey video demonstrating the closure of all
wells at the site. The video must include the date that the video was
taken and must identify the well site location by latitude and
longitude.
(viii) If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraphs
(c)(14)(iv) and (v) of this section, you must maintain the records
specified in Sec. 60.5424b.
(15) For each pump affected facility, you must maintain the records
identified in paragraphs (c)(15)(i) through (ix) of this section.
(i) Identification of each pump that is driven by natural gas and
that is in operation 90 days or more per calendar year.
(ii) If you are complying with Sec. 60.5393b(a) or (b)(1) by
routing pump vapors to a process through a closed vent system,
identification of all the pumps in the pump affected facility for which
you collect and route vapors to a process through a closed vent system
and the records specified in paragraphs (c)(8), (10), and (12) of this
section. If you comply with an alternative GHG and VOC standard under
Sec. 60.5398b, in lieu of the information specified in paragraph
(c)(8) of this section, you must provide the information specified in
Sec. 60.5424b.
(iii) If you are complying with Sec. 60.5393b(b)(1) by routing
pump vapors to control device achieving a 95.0 percent reduction in
methane and VOC emissions, you must keep the records specified in
paragraphs (c)(8) and (10) through (13) of this section. If you comply
with an alternative GHG and VOC standard under Sec. 60.5398b, in lieu
of the information specified in paragraph (c)(8) of this section, you
must provide the information specified in Sec. 60.5424b.
(iv) If you are complying with Sec. 60.5393b(b)(5) by routing pump
vapors to control device achieving less than a 95.0 percent reduction
in methane and VOC emissions, you must maintain records of the
certification that there is a control device on site but it does not
achieve a 95.0 percent emissions reduction and a record of the design
evaluation or manufacturer's specifications which indicate the
percentage reduction the control device is designed to achieve.
(v) If you have less than three natural gas-driven diaphragm pumps
in the pump affected facility, and you do not have a vapor recovery
unit or control device installed on site by the compliance date, you
must retain a record of your certification required under Sec.
60.5393b(b)(6), certifying that there is no vapor recovery unit or
control device on site. If you subsequently install a control device or
vapor recovery unit, you must maintain the records required under
paragraph (c)(15)(ii), (iii) or (iv) of this section, as applicable.
(vi) If you determine, through an engineering assessment, that it
is technically infeasible to route the pump affected facility emissions
to a process or control device, you must retain records of your
demonstration and certification that it is technically infeasible as
required under Sec. 60.5393b(b)(5).
(vii) If the pump is routed to a control device that is
subsequently removed from the location or is no longer available such
that there is no option to route to a control device, you are required
to retain records of this change and the records required under
paragraph (c)(15)(vi) of this section.
(viii) Records of each change in compliance method, including
identification of each natural gas-driven pump which changes its method
of compliance, the new method of compliance, and the date of the change
in compliance method.
(ix) Records of each deviation, the date and time the deviation
began, the duration of the deviation, and a description of the
deviation.
(d) Electronic reporting. If you are required to submit
notifications or reports following the procedure specified in this
paragraph (d), you must submit notifications or reports to the EPA via
CEDRI, which can be accessed through the EPA's Central Data Exchange
(CDX) (https://cdx.epa.gov/). The EPA will make all the information
submitted through CEDRI available to the public without further notice
to you. Do not use CEDRI to submit information you claim as CBI.
Although we do not expect persons to assert a claim of CBI, if you wish
to assert a CBI claim for some of the information in the report or
notification, you must submit a complete file in the format specified
in this subpart, including information claimed to be CBI, to the EPA
following the procedures in paragraphs (d)(1) and (2) of this section.
Clearly mark the part or all of the information that you claim to be
CBI. Information not marked as CBI may be authorized for public release
without prior notice. Information marked as CBI will not be disclosed
except in accordance with procedures set forth in 40 CFR part 2. All
CBI claims must be asserted at the time of submission. Anything
submitted using CEDRI cannot later be claimed CBI. Furthermore, under
CAA section 114(c), emissions data is not entitled to confidential
treatment, and the EPA is required to make emissions data available to
the public. Thus, emissions data will not be protected as CBI and will
be made publicly available. You must submit the same file submitted to
the CBI office with the CBI omitted to the EPA via the EPA's CDX as
described earlier in this paragraph (d).
(1) The preferred method to receive CBI is for it to be transmitted
electronically using email attachments, File Transfer Protocol, or
other online file sharing services. Electronic submissions must be
transmitted directly to the OAQPS CBI Office at the email address
[email protected], and as described above, should include clear CBI
markings. ERT files should be flagged to the attention of the Group
Leader, Measurement Policy Group; all other files should be flagged to
the
[[Page 18112]]
attention of the Oil and Natural Gas Sector Lead. If assistance is
needed with submitting large electronic files that exceed the file size
limit for email attachments, and if you do not have your own file
sharing service, please email [email protected] to request a file
transfer link.
(2) If you cannot transmit the file electronically, you may send
CBI information through the postal service to the following address:
U.S. EPA, Attn: OAQPS Document Control Officer, Mail Drop: C404-02, 109
T.W. Alexander Drive, P.O. Box 12055, RTP, NC 27711. ERT files should
be sent to the secondary attention of the Group Leader, Measurement
Policy Group, and all other files should be sent to the secondary
attention of the Oil and Natural Gas Sector Lead. The mailed CBI
material should be double wrapped and clearly marked. Any CBI markings
should not show through the outer envelope.
* * * * *
Subpart OOOOc--Emissions Guidelines for Greenhouse Gas Emissions
From Existing Crude Oil and Natural Gas Facilities
0
6. Amend Sec. 60.5391c by revising paragraphs (b) through (e) to read
as follows:
Sec. 60.5391c What GHG standards apply to associated gas wells at
well designated facilities?
* * * * *
(b) If you meet one of the conditions in paragraph (b)(1) or (2) of
this section, you may route the associated gas to a control device that
reduces methane emissions by at least 95.0 percent instead of complying
with paragraph (a) of this section. The associated gas must be routed
through a closed vent system that meets the requirements of Sec.
60.5411c(a) and (c) and the control device must meet the conditions
specified in Sec. 60.5412c(a) through (c).
(1) If the annual methane contained in the associated gas from your
oil well is 40 tons per year or less at the initial compliance date,
determined in accordance with paragraph (e) of this section.
(2) If you demonstrate and certify that it is not feasible to
comply with paragraphs (a)(1) through (4) of this section due to
technical reasons by providing a detailed analysis documenting and
certifying the technical reasons for this infeasibility in accordance
with paragraphs (b)(2)(i) through (iv) of this section.
(i) In order to demonstrate that it is not feasible to comply with
paragraphs (a)(1) through (4) of this section, you must provide a
detailed analysis documenting and certifying the technical reasons for
this infeasibility. The demonstration must address the technical
infeasibility for all options identified in paragraphs (a)(1) through
(4). Documentation of these demonstrations must be maintained in
accordance with Sec. 60.5420c(c)(2)(iv).
(ii) This demonstration must be certified by a professional
engineer or another qualified individual with expertise in the uses of
associated gas. The following certification, signed and dated by the
qualified professional engineer or other qualified individual shall
state: ``I certify that the assessment of technical and safety
infeasibility was prepared under my direction or supervision. I further
certify that the assessment was conducted, and this report was prepared
pursuant to the requirements of Sec. 60.5391c(b)(2). Based on my
professional knowledge and experience, and inquiry of personnel
involved in the assessment, the certification submitted herein is true,
accurate, and complete.''
(iii) This demonstration and certification are valid for no more
than 12 months. You must re-analyze the feasibility of complying with
paragraphs (a)(1) through (4) of this section and finalize a new
demonstration and certification each year.
(iv) Documentation of these demonstrations, along with the
certifications, must be maintained in accordance with Sec.
60.5420c(c)(2)(iv) and submitted in annual reports in accordance with
Sec. 60.5420c(b)(3).
(c) If you are complying with paragraph (a) of this section, you
may temporarily route the associated gas to a flare or control device
in the situations and for the durations identified in paragraph (c)(1),
(2), (3), or (4) of this section. The associated gas must be routed
through a closed vent system that meets the requirements of Sec.
60.5411c(a) and (c) and the control device must meet the conditions
specified in Sec. 60.5412c. If you are routing to a flare, you must
demonstrate that the Sec. 60.18 flare requirements are met during the
period when the associated gas is routed to the flare. Records must be
kept of all temporary flaring instances in accordance with Sec.
60.5420c(c)(2) and reported in the annual report in accordance with
Sec. 60.5420c(b)(3).
(1) During a malfunction or incident that endangers the safety of
operator personnel or the public you are allowed to route associated
gas to a flare or control device until the malfunction or incident is
resolved but not longer than 72 hours per incident. Temporarily routing
associated gas to a flare or control device is allowed only until the
malfunction or incident is resolved. Notwithstanding the previous
sentences, if there are exigent circumstances that reasonably require
routing to a flare or control device for more than 72 hours, paragraphs
(c)(1)(i) through (iii) of this section apply.
(i) An ``exigent circumstance'' for purposes of this paragraph
(c)(1) is a situation that results in the inability to reasonably
access a site with the necessary equipment and personnel to address and
resolve incidents that cause the need to temporarily flare associated
gas for more than 72 hours. This includes circumstances where there is
a need to flare beyond 72 hours due to an unexpected malfunction event
and equipment needed to resolve an incident are not readily available
due to an owner's or operator's inability to secure the required
equipment for reasons beyond an owner's or operator's control (i.e.,
supply chain issues); or there is a temporary shortage of personnel
needed to resolve an incident due to a circumstance such as a declared
national pandemic that is beyond an owner's or operator's control.
(ii) Temporarily routing associated gas to a flare or control
device is allowed until the malfunction or incident is resolved, but
shall not be longer than 72 hours after the site can be accessed
following the passing of the exigent circumstance.
(iii) For instances where you route associated gas to a flare or
control device for more than 72 hours, you must meet the reporting
requirements specified in Sec. 60.5420c(b)(3)(i)(B)(4) and must
maintain the records specified in Sec. 60.5420c(c)(2)(vi).
(2) During repair and maintenance, including blow downs, a
production test, or commissioning, you are allowed to route associated
gas to a flare or control device until the incident is resolved, but
not longer than 72 hours per incident. Temporarily routing associated
gas to a flare or control device is allowed only until the incident is
resolved. Notwithstanding the previous sentences, if there are exigent
circumstances that reasonably require routing to a flare or control
device for more than 72 hours, paragraphs (c)(1)(i) through (iii)
apply.
(3) For wells complying with paragraph (a)(1) of this section, for
the duration of a temporary interruption in service from the gathering
or pipeline system, or 30 days, whichever is less.
(4) For 72 hours from the time that the associated gas does not
meet pipeline specifications, or until the associated
[[Page 18113]]
gas meets pipeline specifications, whichever is less.
(d) If you are complying with paragraph (a), (b), or (c) of this
section, you may vent the associated gas in the situations and for the
durations identified in paragraph (d)(1), (2), or (3) of this section.
Records must be kept of all venting instances in accordance with Sec.
60.5420c(c)(2) and reported in the annual report in accordance with
Sec. 60.5420c(b)(3).
(1) For up to 12 hours to protect the safety of personnel.
(2) For up to 30 minutes during bradenhead monitoring.
(3) For up to 30 minutes during a packer leakage test.
(e) Calculate the methane content in associated gas as specified in
paragraph (e)(1) of this section and comply with paragraphs (e)(2) and
(3) of this section.
(1) Calculate the methane content in associated gas from your oil
well using the following equation:
Equation 1 to Paragraph (e)(1)
[GRAPHIC] [TIFF OMITTED] TR09AP26.006
Where:
AGmethane = Amount of methane in associated gas from the
oil well, tons methane per year.
GOR = Gas to oil ratio for the well in standard cubic feet of gas
per barrel of oil; oil here refers to hydrocarbon liquids produced
of all API gravities. GOR is to be determined for the well using
available data, an appropriate standard method published by a
consensus-based standards organization which include, but are not
limited to, the following: ASTM International, the American National
Standards Institute (ANSI), the American Gas Association (AGA), the
American Society of Mechanical Engineers (ASME), the American
Petroleum Institute (API), and the North American Energy Standards
Board (NAESB), or in industry standard practice.
V = Volume of oil produced in the calendar year preceding the
initial compliance date, in barrels per year.
Mmethane = mole fraction of methane in the associated
gas.0.0192 = density of methane gas at 60 [deg]F and 14.7 psia in
kilograms per cubic foot.
907.2 = conversion of kilograms to tons, kilograms per ton.
(2) You must maintain records of the calculation of the methane in
associated gas from your oil well results in accordance with Sec.
60.5420c(c)(2), and submit the information, as well as the background
information, in the next annual report in accordance with Sec.
60.5420c(b)(3).
(3) If a process change occurs that could increase the methane
content in the associated gas, you must recalculate the methane content
in accordance with paragraph (e)(1) of this section.
* * * * *
0
7. Amend Sec. 60.5412c by revising paragraphs (a)(1)(iv), (a)(3), and
(d)(1) to read as follows:
Sec. 60.5412c What additional requirements must I meet for
determining initial compliance of my control devices?
* * * * *
(a) * * *
(1) * * *
(iv) For an enclosed combustion device other than those meeting the
operating limits in paragraphs (a)(1)(ii), (iii), and (v) of this
section, you must maintain the net heating value (NHV) of the gas sent
to the enclosed combustion device at or above the applicable limits
specified in paragraphs (a)(1)(iv)(A) through (C) of this section.
(A) For enclosed combustion devices that do not use assist gas or
pressure-assisted burner tips to promote mixing at the burner tip, 200
British thermal units (Btu) per standard cubic foot (Btu/scf).
(B) For enclosed combustion devices that use pressure-assisted
burner tips to promote mixing at the burner tip, 800 Btu/scf.
(C) For steam-assisted and air-assisted enclosed combustion
devices, 300 Btu/scf.
* * * * *
(3) Each flare must be designed and operated according to the
requirements specified in paragraphs (a)(3)(i) through (vii) of this
section, as applicable. Alternatively, flares must meet the
requirements specified in paragraph (d) of this section.
(i) For unassisted flares, you must maintain the NHV of the vent
gas sent to the flare at or above 200 Btu/scf.
(ii) For flares that use pressure-assisted burner tips to promote
mixing at the burner tip, you must maintain the NHV of the vent gas
sent to the flare at or above 800 Btu/scf.
(iii) For steam-assisted and air-assisted flares, you must maintain
the NHV of the vent gas sent to the flare at or above 300 Btu/scf.
(iv) For flares other than pressure-assisted flares, you must
determine the maximum flow rate of vent gas to the control system based
on the design considerations of the designated facilities to
demonstrate compliance with the flare tip velocity limits in Sec.
60.18(b) according to Sec. 60.5417c(d)(8)(iv). The maximum flare tip
velocity limits do not apply for pressure-assisted flares.
(v) You must operate the flare at or above the minimum inlet gas
flow rate. The minimum inlet gas flow rate is established based on
manufacturer recommendations.
(vi) You must operate the flare with no visible emissions, except
for periods not to exceed a total of 1 minute during any 15-minute
period. You must conduct the compliance determination with the visible
emission limits using Method 22 of appendix A-7 to this part, or you
must monitor the flare according to Sec. 60.5417c(h).
(vii) You must install and operate a continuous burning pilot or
combustion flame. An alert must be sent to the nearest control room
whenever the pilot flame is unlit.
* * * * *
(d) * * *
(1) The alternative method must be capable of demonstrating
continuous compliance with a combustion efficiency of 95.0 percent or
greater.
* * * * *
0
8. Amend Sec. 60.5415c by revising paragraphs (c), (e)(1)(vii),
(e)(1)(xi)(A), (f), (h), and (i)(15) to read as follows:
Sec. 60.5415c How do I demonstrate continuous compliance with the
standards for each of my designated facilities?
* * * * *
(c) Centrifugal compressor designated facility. For each
centrifugal compressor designated facility complying with the
volumetric flow rate measurements requirements in Sec. 60.5392c(a)(1)
and (2), you must demonstrate continuous compliance according to
paragraphs (c)(1), (3), and (4) of this section. Alternatively, for
each centrifugal compressor designated facility complying with Sec.
60.5392c(a)(3) and either Sec. 60.5392c(a)(4) or (5) by routing
emissions to a control device or to a process, you must demonstrate
continuous compliance according to paragraphs (c)(2) through (4) of
this section.
(1) You must maintain volumetric flow rate at or below the
volumetric flow rates specified in paragraphs (c)(1)(i) through (iii)
of this section for your centrifugal compressor, as applicable, and you
must conduct the
[[Page 18114]]
required volumetric flow rate measurement of your dry or wet seal in
accordance with Sec. 60.5392c(a)(1) and (2) on or before 8,760 hours
of operation after your last volumetric flow rate measurement which
demonstrates compliance with the applicable volumetric flow rate.
(i) For your wet seal centrifugal compressors (including self-
contained wet seal centrifugal compressors), you must maintain the
volumetric flow rate at or below 3 scfm per seal (or in the case of
manifolded groups of seals, 3 scfm multiplied by the number of seals).
(ii) For your Alaska North Slope centrifugal compressor equipped
with sour seal oil separator and capture system, you must maintain the
volumetric flow rate at or below 9 scfm per seal (or in the case of
manifolded groups of wet seals, 9 scfm multiplied by the number of
seals).
(iii) For your dry seal compressor, you must maintain the
volumetric flow rate at or below 10 scfm per seal (or in the case of
manifolded groups of wet seals, 10 scfm multiplied by the number of
seals).
(2) For each wet seal and dry seal centrifugal compressor
designated facility complying by routing emissions to a control device
or to a process, you must operate the wet seal emissions collection
system and dry seal system to route emissions to a control device or a
process through a closed vent system and continuously comply with the
closed vent requirements of Sec. 60.5416c. If you comply with Sec.
60.5392c(a)(4) by using a control device, you also must comply with the
requirements in paragraph (e) of this section.
(3) You must submit the annual reports as required in Sec.
60.5420c(b)(1), (4) and (10)(i) through (iv), as applicable.
(4) You must maintain records as required in Sec. 60.5420c(c)(3)
and (7) through (9) and (11), as applicable.
* * * * *
(e) * * *
(1) * * *
(vii) If you use an enclosed combustion device to meet the
requirements of Sec. 60.5412c(a)(1) and you demonstrate compliance
using the test procedures specified in Sec. 60.5413c(b), or you use a
flare designed and operated in accordance with Sec. 60.5412c(a)(3),
you must comply with the applicable requirements in paragraphs
(e)(1)(vii)(A) through (E) of this section.
(A) For each enclosed combustion device which is not a catalytic
vapor incinerator and for each flare, you must comply with the
requirements in paragraphs (e)(1)(vii)(A)(1) through (4) of this
section.
(1) A pilot or combustion flame must be present at all times of
operation. An alert must be sent to the nearest control room whenever
the pilot or combustion flame is unlit.
(2) Devices must be operated with no visible emissions, except for
periods not to exceed a total of 1 minute during any 15-minute period.
A visible emissions test conducted according to section 11 of Method 22
of appendix A-7 to this part, must be performed at least once every
calendar month, separated by at least 15 days between each test. The
observation period shall be 15 minutes or once the amount of time
visible emissions is present has exceeded 1 minute, whichever time
period is less. Alternatively, you may conduct visible emissions
monitoring according to Sec. 60.5417c(h).
(3) Devices failing the visible emissions test must follow
manufacturer's repair instructions, if available, or best combustion
engineering practice as outlined in the unit inspection and maintenance
plan, to return the unit to compliant operation. All repairs and
maintenance activities for each unit must be recorded in a maintenance
and repair log and must be available for inspection.
(4) Following return to operation from maintenance or repair
activity, each device must pass a Method 22 of appendix A-7 to this
part visual observation as described in paragraph (e)(1)(vii)(D) of
this section or be monitored according to Sec. 60.5417c(h).
(B) For flares, you must comply with the requirements in paragraphs
(e)(1)(vii)(B)(1) through (5) of this section.
(1) For unassisted flares, maintain the NHV of the gas sent to the
flare at or above 200 Btu/scf.
(2) If you use a pressure assisted flare, maintain the NHV of gas
sent to the flare at or above 800 Btu/scf.
(3) For steam-assisted and air-assisted flares, maintain the NHV of
gas sent to the flare at or above 300 Btu/scf.
(4) Unless you use a pressure-assisted flare, maintain the flare
tip velocity below the applicable limits in Sec. 60.18(b).
(5) Maintain the total gas flow to the flare above the minimum
inlet gas flow rate. The minimum inlet gas flow rate is established
based on manufacturer recommendations.
(C) For enclosed combustion devices for which, during the
performance test conducted under Sec. 60.5413c(b), the combustion zone
temperature is not an indicator of destruction efficiency, you must
comply with the requirements in paragraphs (e)(1)(vii)(C)(1) through
(4) of this section, as applicable.
(1) Maintain the total gas flow to the enclosed combustion device
at or above the minimum inlet gas flow rate and at or below the maximum
inlet flow rate for the enclosed combustion device established in
accordance with Sec. 60.5417c(f).
(2) For unassisted enclosed combustion devices, maintain the NHV of
the gas sent to the enclosed combustion device at or above 200 Btu/scf.
(3) For enclosed combustion devices that use pressure-assisted
burner tips to promote mixing at the burner tip, maintain the NHV of
the gas sent to the enclosed combustion device at or above 800 Btu/scf.
(4) For steam-assisted and air-assisted enclosed combustion
devices, maintain the NHV-of gas sent to the flare at or above 300 Btu/
scf.
(D) For enclosed combustion devices for which, during the
performance test conducted under Sec. 60.5413c(b), the combustion zone
temperature is demonstrated to be an indicator of destruction
efficiency, you must comply with the requirements in paragraphs
(e)(1)(vii)(D)(1) and (2) of this section.
(1) Maintain the temperature at or above the minimum temperature
established during the most recent performance test. The minimum
temperature limit established during the most recent performance test
is the average temperature recorded during each test run, averaged
across the 3 test runs (average of the test run averages).
(2) Maintain the total gas flow to the enclosed combustion device
at or above the minimum inlet gas flow rate and at or below the maximum
inlet flow rate for the enclosed combustion device established in
accordance with Sec. 60.5417c(f).
(E) For catalytic vapor incinerators you must operate the catalytic
vapor incinerator at or above the minimum temperature of the catalyst
bed inlet and at or above the minimum temperature differential between
the catalyst bed inlet and the catalyst bed outlet established in
accordance with Sec. 60.5417c(f).
* * * * *
(xi) * * *
(A) You must maintain the combustion efficiency at or above 95.0
percent.
* * * * *
(f) Reciprocating compressor designated facility. For each
reciprocating compressor designated facility complying with Sec.
60.5393c(a) through (c), you must demonstrate
[[Page 18115]]
continuous compliance according to paragraphs (f)(1), (3), (5), and (6)
of this section. For each reciprocating compressor designated facility
complying with Sec. 60.5393c(d)(1) or (2), you must demonstrate
continuous compliance according to paragraphs (f)(2), (5), and (6) of
this section. For each reciprocating compressor affected facility
complying with Sec. 60.5393c(d)(3), you must demonstrate continuous
compliance according to paragraphs (f)(3) through (6) of this section.
(1) You must maintain the volumetric flow rate at or below 2 scfm
per cylinder (or at or below the combined volumetric flow rate
determined by multiplying the number of cylinders by 2 scfm), and you
must conduct the required volumetric flow rate measurement of your
reciprocating compressor rod packing vents in accordance with Sec.
60.5393c(b) or (c) on or before 8,760 hours of operation after your
last volumetric flow rate measurement which demonstrated compliance
with the applicable volumetric flow rate.
(2) You must operate the rod packing emissions collection system to
route emissions to a control device or to a process through a closed
vent system and continuously comply with the cover and closed vent
requirements of Sec. 60.5416c. If you comply with Sec. 60.5393c(d) by
using a control device, you also must comply with the requirements in
paragraph (e) of this section.
(3) You must continuously monitor the number of hours of operation
for each reciprocating compressor affected facility since initial
startup, since 60 days after the state plan submittal deadline (as
specified in Sec. 60.5362c(c)), since the previous flow rate
measurement, or since the date of the most recent reciprocating
compressor rod packing replacement, whichever date is latest.
(4) You must replace the reciprocating compressor rod packing on or
before the total number of hours of operation reaches 8,760 hours.
(5) You must submit the annual reports as required in Sec.
60.5420c(b)(1) and (5) and (b)(10)(i) through (iv), as applicable.
(6) You must maintain records as required in Sec. 60.5420c(c)(4),
(7) through (9), and (11), as applicable.
* * * * *
(h) Storage vessel designated facility. For each storage vessel
designated facility, you must demonstrate continuous compliance with
the requirements of Sec. 60.5396c according to paragraphs (h)(1)
through (10) of this section, as applicable.
(1) For each storage vessel designated facility complying with the
requirements of Sec. 60.5396c(a)(2), you must demonstrate continuous
compliance according to paragraphs (h)(5) and (9) and (10) of this
section.
(2) For each storage vessel designated facility complying with the
requirements of Sec. 60.5396c(a)(3), you must demonstrate continuous
compliance according to paragraph (h)(2)(i), (ii), or (iii) of this
section, as applicable, and paragraphs (h)(9) and (10) of this section.
(i) You must maintain the uncontrolled actual methane emissions
from the storage vessel designated facility at less than 14 tpy.
(ii) You must comply with paragraph (h)(5) of this section as soon
as liquids from the well are routed to the storage vessel designated
facility following fracturing or refracturing according to the
requirements of Sec. 60.5396c(a)(3)(i).
(iii) You must comply with paragraph (h)(5) of this section within
30 days of the monthly determination according to the requirements of
Sec. 60.5396c(a)(3)(ii), where the monthly emissions determination
indicates that methane emissions from your storage vessel designated
facility increase to 14 tpy or greater and the increase is not
associated with fracturing or refracturing of a well feeding the
storage vessel designated facility.
(3) For each storage vessel designated facility or portion of a
storage vessel designated facility removed from service, you must
demonstrate compliance with the requirements of Sec. 60.5396c(c)(1) or
(2) by complying with paragraphs (h)(6), (7), (9), and (10) of this
section.
(4) For each storage vessel designated facility or portion of a
storage vessel designated facility returned to service, you must
demonstrate compliance with the requirements of Sec. 60.5396c(c)(3)
and (4) by complying with paragraphs (h)(8) through (10) of this
section.
(5) For each storage vessel designated facility, you must comply
with paragraphs (h)(5)(i) and (ii) of this section.
(i) You must reduce methane emissions as specified in Sec.
60.5396c(a)(2).
(ii) For each control device installed to meet the requirements of
Sec. 60.5396c(a)(2), you must demonstrate continuous compliance with
the performance requirements of Sec. 60.5412c for each storage vessel
designated facility using the procedure specified in paragraphs
(h)(5)(ii)(A) and (B) of this section. When routing emissions to a
process, you must demonstrate continuous compliance as specified in
paragraph (h)(5)(ii)(A) of this section.
(A) You must comply with Sec. 60.5416c for each cover and closed
vent system.
(B) You must comply with the requirements specified in paragraph
(e) of this section.
(6) You must completely empty and degas each storage vessel, such
that each storage vessel no longer contains crude oil, condensate,
produced water or intermediate hydrocarbon liquids. For a portion of a
storage vessel designated facility to be removed from service, you must
completely empty and degas the storage vessel(s), such that the storage
vessel(s) no longer contains crude oil, condensate, produced water or
intermediate hydrocarbon liquids. A storage vessel where liquid is left
on walls, as bottom clingage or in pools due to floor irregularity is
considered to be completely empty.
(7) You must disconnect the storage vessel(s) from the tank battery
by isolating the storage vessel(s) from the tank battery such that the
storage vessel(s) is no longer manifolded to the tank battery by liquid
or vapor transfer.
(8) You must determine the designated facility status of a storage
vessel returned to service as provided in Sec. 60.5386c(e)(5).
(9) You must submit the annual reports as required by Sec.
60.5420c(b)(1) and (7) and (b)(10)(i) through (iv).
(10) You must maintain the records as required by Sec.
60.5420c(c)(6) through (9) and (11), as applicable.
(i) * * *
(15) You must maintain the records specified by Sec.
60.5420c(c)(7), (9), and (11) as applicable and Sec. 60.5421c.
* * * * *
0
9. Amend Sec. 60.5417c by revising paragraphs (d)(8), (e), (f)(1)(iv),
(g)(1), (6) and (7), and (i)(6)(i) to read as follows:
Sec. 60.5417c What are the continuous monitoring requirements for my
control devices?
* * * * *
(d) * * *
(8) For an enclosed combustion device, other than those listed in
paragraphs (d)(1) through (3) and (7) of this section, or for a flare,
continuous monitoring systems as specified in paragraphs (d)(8)(i)
through (iv) of this section and visible emission observations
conducted as specified in paragraph (d)(8)(v) of this section.
(i) Continuously monitor at least once every five minutes for the
presence of a pilot flame or combustion flame using a device
(including, but not limited to, a thermocouple, ultraviolet beam
sensor, or infrared sensor) capable of detecting that the pilot or
combustion flame is
[[Page 18116]]
present at all times. An alert must be sent to the nearest control room
whenever the pilot or combustion flame is unlit. Continuous monitoring
systems used for the presence of a pilot flame or combustion flame are
not subject to a minimum accuracy requirement beyond being able to
detect the presence or absence of a flame and are exempt from the
calibration requirements of this section.
(ii) Except as provided in this paragraph (d)(8)(ii) and paragraph
(d)(8)(iii) of this section, use one of the following methods to
continuously determine the NHV of the inlet gas to the enclosed
combustion device or flare at standard conditions. Except for pressure
assisted flares and pressure assisted enclosed combustion devices, if
the inlet gas stream to the flare or enclosed combustion device does
not include streams from processes or equipment where inert gas or
other vent gas streams which may lower the NHV of the combined stream
are added (e.g., vent streams from acid gas removal (AGR) system amine
regenerator still columns, vent streams from glycol dehydrator unit
reboilers without water removal, vent streams from compressors in acid
gas service, vent streams containing water or CO2 used for
enhanced oil recovery, vent streams from storage vessels with high
water content where the owner or operator has determined that the vent
stream could cause the inlet gas to the enclosed combustion device or
flare to not meet the minimum NHV, vent streams from gas plants that
receive acid gas from sweetening units, and vent streams from nitrogen
removal units (NRU)), the NHV of the inlet stream is considered to be
sufficiently above the minimum required NHV for the inlet gas, and you
are not required to conduct the continuous monitoring in this paragraph
(d)(8)(ii) or the demonstration in paragraph (d)(8)(iii) of this
section, but you must submit the report in Sec. 60.5420c(b)(10)(v)(I)
and maintain the record in Sec. 60.5420c(c)(10)(vi) indicating that
the flare or enclosed combustion device does not receive inert gas or
other vent gas streams which may lower the NHV of the combined stream.
(A) A calorimeter with a minimum accuracy of 2 percent
of span.
(B) A gas chromatograph that meets the requirements in paragraphs
(d)(8)(ii)(B)(1) through (5) of this section.
(1) You must follow the procedure in Performance Specification 9 of
appendix B to this part, except that a single daily mid-level
calibration check can be used (rather than triplicate analysis), the
multi-point calibration can be conducted quarterly (rather than
monthly), and the sampling line temperature must be maintained at a
minimum temperature of 60 [deg]C (rather than 120 [deg]C). Calibration
gas cylinders must be certified to an accuracy of 2 percent and
traceable to National Institute of Standards and Technology (NIST)
standards.
(2) You must meet the accuracy requirements in Performance
Specification 9 of appendix B to this part.
(3) You must use a calibration gas or multiple gases that includes
the compounds that are reasonably expected to be present in the flare
gas stream. If multiple calibration gases are necessary to cover all
compounds, you must calibrate the instrument on all of the gases. You
may only use the compounds used to calibrate the gas chromatograph in
the calculation of the vent gas NHV.
(4) In lieu of the calibration gas described in paragraph
(d)(8)(ii)(B)(3) of this section, you may use a surrogate calibration
gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All
of the calibration gases may be combined in one cylinder. If multiple
calibration gases are necessary to cover all compounds, you must
calibrate the instrument on all of the gases. Use the response factor
for the nearest normal hydrocarbon (i.e., n-alkane) in the calibration
mixture to quantify unknown components detected in the analysis. Use
the response factor for n-pentane to quantify unknown components
detected in the analysis that elute after n-pentane.
(5) To determine the NHV of the vent gas, determine the product of
the volume fraction of the individual component in the vent gas and the
net heating value of that individual component. Sum the products for
all components in the vent gas to determine the NHV for the vent gas.
For the net heating value of each individual component, use any
published values for the net heating value per mole at 25 [deg]C and 1
atmosphere and use 20 [deg]C as the standard temperature for
determining the volume corresponding to one mole of vent gas.
(C) A mass spectrometer that meets the requirements in paragraphs
(d)(8)(ii)(C)(1) through (6) of this section.
(1) You must meet applicable requirements in Performance
Specification 9 of appendix B of this part for continuous monitoring
system acceptance including, but not limited to, performing an initial
multi-point calibration check at three concentrations following the
procedure in Section 10.1. A single daily mid-level calibration check
can be used (rather than triplicate analysis), the multi-point
calibration can be conducted quarterly (rather than monthly), and the
sampling line temperature must be maintained at a minimum temperature
of 60 [deg]C (rather than 120 [deg]C). Calibration gas cylinders must
be certified to an accuracy of 2 percent and traceable to NIST
standards.
(2) The average instrument calibration error (CE) for each
calibration compound at any calibration concentration must not differ
by more than 10 percent from the certified cylinder gas value. The CE
for each component in the calibration blend must be calculated using
the following equation:
Equation 1 to Paragraph (d)(8)(ii)(C)(2)
[GRAPHIC] [TIFF OMITTED] TR09AP26.007
Where:
Cm = Average instrument response (ppm).
Ca = Certified cylinder gas value (ppm).
(3) You must use a calibration gas or multiple gases that includes
the compounds that are reasonably expected to be present in the flare
gas stream. If multiple calibration gases are necessary to cover all
compounds, you must calibrate the instrument on all of the gases. You
may only use the compounds used to calibrate the mass spectrometer in
the calculation of the vent gas NHV.
(4) In lieu of the calibration gas described in paragraph
(d)(8)(ii)(C)(3) of this section, you may use a surrogate calibration
gas consisting of hydrogen and C1 through C5 normal hydrocarbons. All
of the calibration gases may be combined in one cylinder. If multiple
calibration gases are necessary to cover all compounds, you must
calibrate the instrument on all of the gases. For unknown gas
components that have similar analytical mass fragments to calibration
compounds, you may report the unknowns as an increase in the overlapped
calibration gas compound. For unknown compounds that produce mass
fragments that do not overlap calibration compounds, you may use the
response factor for the nearest molecular weight hydrocarbon in the
calibration mix to quantify the unknown component. You may use the
response factor for n-pentane to quantify any unknown components
detected with a higher molecular weight than n-pentane.
(5) You must perform an initial calibration to identify mass
fragment
[[Page 18117]]
overlap and response factors for the target compounds.
(6) To determine the NHV of the vent gas, determine the product of
the volume fraction of the individual component in the vent gas and the
net heating value of that individual component. Sum the products for
all components in the vent gas to determine the NHV for the vent gas.
For the net heating value of each individual component, use any
published value for the net heating value per mole at 25 [deg]C and 1
atmosphere use 20 [deg]C as the standard temperature for determining
the volume corresponding to one mole of vent gas.
(D) A grab sampling system capable of collecting an evacuated
canister sample for subsequent compositional analysis at least once
every eight hours. Subsequent compositional analysis of the samples
must be performed according to ASTM D1945-14 (R2019) or alternatively
GPA 2261-19 (incorporated by reference, see Sec. 60.17). To determine
the NHV of the vent gas, determine the product of the volume fraction
of the individual component in the vent gas and the net heating value
of that individual component. Sum the products for all components in
the vent gas to determine the NHV for the vent gas. For the net heating
value of each individual component, use the net heating value per mole
at 25 [deg]C and 1 atmosphere use 20 [deg]C as the standard temperature
for determining the volume corresponding to one mole of vent gas.
(iii) As an alternative to the continuous composition monitoring
requirements in paragraph (d)(8)(ii) of this section, a sampling
demonstration may be used as specified in this paragraph. Flares or
enclosed combustion devices that are not required to monitor flare gas
composition because the inlet gas streams to the flare or enclosed
combustion device does not include streams from processes or equipment
where inert gas or other vent gas streams which may lower the NHV of
the combined stream are added (e.g., vent streams from acid gas removal
(AGR) system amine regenerator still columns, vent streams from glycol
dehydrator unit reboilers without water removal, vent streams from
compressors in acid gas service, vent streams containing water or
CO2 used for enhanced oil recovery, vent streams from
storage vessels with high water content where the owner or operator has
determined that the vent stream could cause the inlet gas to the
enclosed combustion device or flare to not meet the minimum NHV, vent
streams from gas plants that receive acid gas from sweetening units,
and vent streams from nitrogen removal units (NRU)), are not required
to conduct sampling demonstrations specified in this paragraph. For
flare or enclosed combustion device, if you demonstrate according to
the methods described in paragraphs (d)(8)(iii)(A) through (F) of this
section that the NHV of the inlet gas to the enclosed combustion device
or flare consistently exceeds the applicable operating limit specified
in Sec. 60.5415c(e)(1)(vii)(B) or (C), continuous monitoring of the
NHV is not required, but you must conduct the ongoing sampling in
paragraph (d)(8)(iii)(G) of this section. For an unassisted or
pressure-assisted flare or enclosed combustion device, in lieu of
conducting the demonstration outlined in paragraphs (d)(8)(iii)(A)
through (D) of this section, you may conduct the demonstration outlined
in paragraph (d)(8)(iii)(H) of this section, but you must still comply
with paragraphs (d)(8)(iii)(E) through (G) of this section.
(A) Continuously monitor the inlet stream which is routed to the
flare or enclosed combustor for 14 operating days or collect a sample
of the inlet gas which is routed to the enclosed combustion device or
flare twice daily to determine the average NHV of the gas stream for 14
operating days with no sampling day to be spaced more than 3 operating
days apart from the previous sampling day. If you do not continuously
monitor the NHV, the minimum time of collection for each individual
sample be at least one hour when technically feasible. When it is not
technically feasible to collect individual samples for at least one
hour (e.g., low or intermittent flow), the collection time must be as
long as possible up to one hour. For samples taken during low or
intermittent flow events, the collection time and the reason for not
obtaining a full one hour sample must be documented and reported with
the NHV sampling results. Samples must be separated by at least 6
hours. If inlet gas flow is intermittent such that there are not at
least 28 samples over the 14 operating day period, you must continue to
collect samples of the inlet gas beyond the 14 operating day period
until you collect a minimum of 28 samples.
(B) If you collect samples twice per day, count the number of
samples where the NHV value is less than 1.2 times the applicable
operating limit specified in Sec. 60.5415c(e)(1)(vii)(B) or (C) (i.e.,
values that are less than 240, 360, or 960 Btu/scf, as applicable)
during the sample collection period in paragraph (d)(8)(iii)(A) of this
section.
(C) If you continuously sample the inlet stream for 14 days, count
the number of hourly block average (e.g., noon to 1 p.m., 1 p.m. to 2
p.m., etc.) NHV values that are less than the applicable operating
limit specified in Sec. 60.5415c(e)(1)(vii)(B) or (C), (i.e., values
that are less than 200, 300, or 800 Btu/scf, as applicable), during the
sample collection period in paragraph (d)(8)(iii)(A) of this section.
(D) If there are no samples counted under paragraph (d)(8)(iii)(B)
of this section or there are no hourly values counted under paragraph
(d)(8)(iii)(C) of this section, the gas stream is considered to
consistently exceed the applicable NHV operating limit and on-going
continuous monitoring is not required.
(E) If process operations are revised that could reduce the NHV of
the gas sent to the enclosed combustion device or flare, such as the
removal or addition of process equipment, and at any time the
Administrator requires, re-evaluation of the gas stream must be
performed according to paragraphs (d)(8)(iii)(A) through (D) of this
section within 60 days of the revisions to process operations to ensure
the gas stream still consistently exceeds the applicable operating
limit specified in Sec. 60.5415c(e)(1)(vii)(B) or (C), or this
paragraph (d)(8)(iii). If any of the samples counted under paragraph
(d)(8)(iii)(B) of this section or any hourly values counted under
paragraph (d)(8)(iii)(C) of this section are less than the limits in
the respective paragraph you must conduct the continuous monitoring
required by one of the options specified in paragraphs (d)(8)(ii)(A)
through (D) of this section within 60 days of the re-evaluation of the
gas stream.
(F) When collecting samples under paragraph (d)(8)(iii)(A) of this
section, the owner or operator must account for any sources of inert
gases or other vent gas streams which may lower the NHV of the combined
stream (e.g., vent streams from AGR system amine regenerator still
columns, vent streams from glycol dehydrator unit reboilers, vent
streams from compressors in acid gas service, vent streams from
enhanced oil recovery facilities, or vent streams from storage vessel
with high water content where the owner or operator has determined that
the vent stream could cause the inlet gas to the enclosed combustion
device or flare to not meet the minimum NHV) that can be sent to the
enclosed combustion device or flare. The owner or operator must
document in the report in Sec. 60.5420c(b)(10)(v)(I) and the records
in Sec. 60.5420c(c)(10)(vi) must note the operating scenario(s) which
may lower the NHV of the combined stream through the
[[Page 18118]]
introduction of inert gases or other vent gas streams which may lower
the NHV of the combined stream, and whether the sampling included
periods where the highest percentage of inert gases or other vent gas
streams which may lower the NHV of the combined stream were sent to the
enclosed combustion device or flare. If the introduction of inerts or
other vent gas streams which may lower the NHV of the combined stream
is intermittent and does not occur during the initial demonstration,
the introduction of inerts or other vent gas streams which may lower
the NHV of the combined stream will be considered a revision to process
operations that triggers a re-evaluation under paragraph (d)(8)(iii)(E)
of this section. If conditions at the site did not allow sampling
during periods where the introduction of inert gases or other vent gas
streams which may lower the NHV of the combined stream was at the
highest percentage possible, increasing the percentage of inerts will
be considered a revision to process operations that triggers a re-
evaluation under paragraph (d)(8)(iii)(E).
(G) You must collect three samples of the inlet gas to the enclosed
combustion device or flare at least once every 5 years. The minimum
time of collection for each individual sample must be at least one hour
when technically feasible. When it is not technically feasible to
collect individual samples for at least one hour (e.g., low or
intermittent flow), the collection time must be as long as possible up
to one hour. For samples taken during low or intermittent flow events,
the collection time and the reason for not obtaining a full one hour
sample must be documented and reported with the NHV sampling results.
The samples must be taken during the period with the lowest expected
NHV (i.e., the period with the highest percentage of inerts or other
vent gas streams which may lower the NHV of the combined stream). The
first set of periodic samples must be taken, or continuous monitoring
commenced, no later than 60 calendar months following the last sample
taken under paragraph (d)(8)(iii)(A) of this section. Subsequent
periodic samples must be taken, or continuous monitoring commenced, no
later than 60 calendar months following the previous sample. If any
sample has an NHV value less than 1.2 times the applicable operating
limit specified in Sec. 60.5415c(e)(1)(vii)(B) or (C) (i.e., values
that are less than 240, 360, or 960 Btu/scf, as applicable), you must
conduct the continuous monitoring required by one of the options in
paragraphs (d)(8)(ii)(A) through (D) of this section within 60 days or
receipt of the last sample.
(H) You may request an alternative test method under Sec.
60.5412c(d) to demonstrate that the flare or enclosed combustion device
reduces methane and VOC in the gases vented to the device by 95.0
percent by weight or greater. You must measure data values at the
frequency specified in the alternative test method and conduct the
quality assurance and quality control requirements outlined in the
alternative test method at the frequency outlined in the alternative
test method. You must monitor the combustion efficiency of the flare
continuously for 14 days. If there are no values of the combustion
efficiency measured by the alternative test method that are less than
95.0 percent, the gas stream is considered to consistently exceed the
applicable NHV operating limit, and you are not required to
continuously monitor the NHV of the inlet gas to the flare or enclosed
combustion device.
(iv) Except as noted in paragraphs (d)(8)(iv)(A) through (C) of
this section, a continuous parameter monitoring system for measuring
the flow of gas to the enclosed combustion device or flare. You may use
direct flow meters or other parameter monitoring systems combined with
engineering calculations, such as inlet line pressure, line size, and
burner nozzle dimensions, to satisfy this requirement. The monitoring
instrument must have an accuracy of 10 percent or better at
the maximum expected flow rate.
(A) Pressure-assisted flares and pressure-assisted enclosed
combustion devices are not required to have a continuous parameter
monitoring system for measuring the inlet flow of gas to the device if
you install, calibrate, maintain, and operate a backpressure regulator
valve calibrated to open at the minimum pressure set point
corresponding to the minimum inlet gas flow rate. The set point must be
consistent with manufacturer specifications for minimum flow or
pressure and must be supported by an engineering evaluation. At least
annually, you must confirm that the backpressure regulator valve set
point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(B) Flares are not required to have a continuous parameter
monitoring system for measuring the inlet flow of gas to the device if
you meet the conditions in paragraphs (d)(8)(iv)(B)(1) and (2) of this
section.
(1) You must demonstrate, based on the maximum potential pressure
of units manifolded to the flare and applicable engineering
calculations for the manifolded closed vent system, that the maximum
flow rate to the flare cannot cause the flare tip velocity to exceed
the maximum tip velocity as specified in the applicable provisions in
Sec. 60.18(c) and (f) of this chapter. You must use the minimum
expected value of the NHV of the inlet gas to the flare or enclosed
combustion based on previous sampling results or process knowledge of
the streams sent to the enclosed flare of combustion device in your
demonstration. If there are changes to the process or control device
that can be reasonably expected to increase the maximum flow rate to
the flare, you must conduct a new demonstration to determine whether
the maximum flow rate to the flare is compliant with the applicable
maximum flare tip velocity provisions in Sec. 60.18(c) and (f) of this
chapter.
(2) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an engineering evaluation. At
least annually, you must confirm that the backpressure regulator valve
set point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(C) Enclosed combustion devices are not required to have a
continuous parameter monitoring system for measuring the inlet flow of
gas to the device if you meet the conditions in paragraphs
(d)(8)(iv)(C)(1) and (2) of this section.
(1) You must demonstrate, based on the maximum potential pressure
of units manifolded to the enclosed combustion device and applicable
engineering calculations for the manifolded closed vent system, that
the maximum flow rate to the enclosed combustion device cannot cause
the maximum inlet flow rate established in accordance with paragraph
(f)(1) of this section to be exceeded. If there are changes to the
process or control device that can be reasonably expected to impact the
maximum flow rate to the enclosed combustion device, you must conduct a
new demonstration to determine whether the maximum flow rate to the
enclosed combustor is less than the maximum inlet flow rate
[[Page 18119]]
established in accordance with paragraph (f)(1) of this section.
(2) You must install, calibrate, maintain, and operate a
backpressure regulator valve calibrated to open at the minimum pressure
set point corresponding to the minimum inlet gas flow rate. The set
point must be consistent with manufacturer specifications for minimum
flow or pressure and must be supported by an engineering evaluation. At
least annually, you must confirm that the backpressure regulator valve
set point is correct and consistent with the engineering evaluation and
manufacturer specifications and that the valve fully closes when not in
the open position.
(v) Conduct inspections monthly and at other times as requested by
the Administrator to monitor for visible emissions from the combustion
device using section 11 of Method 22 of appendix A to this part or
conduct visible emissions monitoring according to paragraph (h) of this
section. The observation period shall be 15 minutes or once the amount
of time visible emissions is present has exceeded 1 minute. Devices
must be operated with no visible emissions, except for periods not to
exceed a total of 1 minute during any 15-minute period.
(e) Calculate the value of the applicable monitored parameter in
accordance with paragraphs (e)(1) through (4) of this section.
(1) You must calculate the daily average value for condenser outlet
temperature for each operating day, using the data recorded by the
monitoring system. If the emissions unit operation is continuous, the
operating day is a 24-hour period. If the emissions unit operation is
not continuous, the operating day is the total number of hours of
control device operation per 24-hour period. Valid data points must be
available for 75 percent of the operating hours in an operating day to
compute the daily average.
(2) You must use the 5-minute readings from the heat sensing
devices to assess the presence of a pilot or combustion flame.
(3) You must use the regeneration cycle time (i.e., duration of the
carbon bed steaming cycle) for each regenerative-type carbon adsorption
system to calculate the average parameter to compare with the maximum
steam mass flow or volumetric flow during each carbon bed regeneration
cycle and the maximum carbon bed temperature during the steaming cycle.
The carbon bed temperature after the regeneration cycle should not be
averaged; you must use the carbon bed temperature measured within 15
minutes of completing the cooling cycle to compare with the minimum
carbon bed temperature after the regeneration cycle.
(4) For all operating parameters others than those described in
paragraphs (e)(1) through (3) of this section, you must calculate the
3-hour rolling average of each monitored parameter. For each operating
hour, calculate the hourly value of the operating parameter from your
continuous monitoring system. Average the three most recent hours of
data to determine the 3-hour average. Determine the 3-hour rolling
average by recalculating the 3-hour average each hour.
(f) * * *
(1) * * *
(iv) If you operate an enclosed combustion device where the
combustion zone temperature is not an indicator of destruction
efficiency or a control device where the performance test requirement
was met under Sec. 60.5413c(d), you must maintain the NHV of the gas
sent to the enclosed combustion device above the applicable limits
specified in Sec. 60.5412c(a)(1)(iv)(A) through (C).
* * * * *
(g) * * *
(1) A deviation occurs when the average value of a monitored
operating parameter determined in accordance with paragraph (e) of this
section is less than the minimum operating parameter limit (and, if
applicable, greater than the maximum operating parameter limit)
established in paragraph (f)(1) of this section; for flares, when the
average value of a monitored operating parameter determined in
accordance with paragraph (e) of this section is below the applicable
limits specified in Sec. 60.5415c(e)(1)(vii)(B)(1) through (3) and (5)
or above the limit specified in Sec. 60.5415c(e)(1)(vii)(B)(4); or for
each flare or enclosed combustion device except for boilers and process
heaters meeting the requirements in Sec. 60.5412c(a)(1)(iii) and
catalytic vapor incinerators meeting the requirements in Sec.
60.5412c(a)(1)(v), when the heat sensing device indicates that there is
no pilot or combustion flame present for any time period. If you use a
backpressure regulator valve to maintain the inlet gas flow to an
enclosed combustion device or flare above the minimum value, a
deviation occurs if the annual inspection finds that the backpressure
regulator valve set point is not set correctly or indicates that the
backpressure regulator valve does not fully close when not in the open
position.
* * * * *
(6) For a combustion control device whose model is tested under
Sec. 60.5413c(d), a deviation occurs when the conditions of paragraph
(g)(4), (5), or (6)(i) through (v) of this section are met.
(i) The hourly inlet gas flow rate is less than the minimum inlet
gas flow rate or greater than the maximum inlet gas flow rate
determined by the manufacturer. If you use a backpressure regulator
valve to maintain the inlet gas flow above the minimum value, a
deviation occurs if the annual inspection finds that the backpressure
regulator valve set point is not set correctly or indicates that the
backpressure regulator valve does not fully close when not in the open
position.
(ii) Results of the monthly visible emissions test conducted under
Sec. 60.5413c(e)(3) or monitoring under paragraph (h) of this section
indicate visible emissions exceed 1 minute in any 15-minute period.
(iii) There is no indication of the presence of a pilot or
combustion flame for any 5-minute time period.
(iv) The control device is not maintained in a leak free condition.
(v) The control device is not operated in accordance with the
manufacturer's written operating instructions, procedures and
maintenance schedule.
(7) For an enclosed combustion device or flare subject to paragraph
(d)(8) of this section, a deviation occurs when any of the conditions
described by paragraph (g)(1), (4), or (5) of this section are met or
when the results of the visible emissions monitoring conducted under
paragraph (d)(8)(v) or (h) of this section exceed 1 minute in any 15-
minute period.
* * * * *
(i) * * *
(6) * * *
(i) A deviation occurs if the combustion efficiency is less than
95.0 percent.
* * * * *
0
10. Amend Sec. 60.5420c by revising paragraphs (a)(3),(b), (c), and
(d) introductory text to read as follows:
Sec. 60.5420c What are my notification, reporting, and recordkeeping
requirements?
(a) * * *
(3) Notification to Administrator. An owner or operator who
commences well closure activities must submit the following notices to
the Administrator according to the schedule in paragraphs (a)(3)(i) and
(ii) of this section. The
[[Page 18120]]
notification shall include contact information for the owner or
operator; the United States Well Number; the latitude and longitude
coordinates for each well at the well site in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using the North
American Datum of 1983. You must submit notifications in portable
document format (PDF) following the procedures specified in paragraph
(d) of this section.
(i) You must submit a well closure plan to the Administrator within
30 days of the cessation of production from all wells located at the
well site.
(ii) You must submit a notification of the intent to close a well
site 60 days before you begin well closure activities.
(b) Reporting requirements. You must submit annual reports
containing the information specified in paragraphs (b)(1) through (13)
of this section following the procedure specified in paragraph (b)(14)
of this section. You must submit performance test reports as specified
in paragraph (b)(11) or (12) of this section, if applicable. The
initial annual report is due no later than 90 days after the end of the
initial compliance period as determined according to Sec. 60.5410c.
Subsequent annual reports are due no later than the same date each year
as the initial annual report. If you own or operate more than one
designated facility, you may submit one report for multiple designated
facilities provided the report contains all of the information required
as specified in paragraphs (b)(1) through (13) of this section. Annual
reports may coincide with title V reports as long as all the required
elements of the annual report are included. You may arrange with the
Administrator a common schedule on which reports required by this part
may be submitted as long as the schedule does not extend the reporting
period. You must submit the information in paragraph (b)(1)(v) of this
section, as applicable, for your well designated facility which
undergoes a change of ownership during the reporting period, regardless
of whether reporting under paragraphs (b)(2) and (3) of this section is
required for the well designated facility.
(1) The general information specified in paragraphs (b)(1)(i)
through (v) of this section is required for all reports.
(i) The company name, facility site name associated with the
designated facility, U.S. Well ID or U.S. Well ID associated with the
designated facility, if applicable, and address of the designated
facility. If an address is not available for the site, include a
description of the site location and provide the latitude and longitude
coordinates of the site in decimal degrees to an accuracy and precision
of five (5) decimals of a degree using the North American Datum of
1983.
(ii) An identification of each designated facility being included
in the annual report.
(iii) Beginning and ending dates of the reporting period.
(iv) A certification by a certifying official of truth, accuracy,
and completeness. This certification shall state that, based on
information and belief formed after reasonable inquiry, the statements
and information in the document are true, accurate, and complete. If
your report is submitted via CEDRI, the certifier's electronic
signature during the submission process replaces the requirement in
this paragraph (b)(1)(iv).
(v) Identification of each well designated facility for which
ownership changed due to sale or transfer of ownership including the
United States Well Number; the latitude and longitude coordinates of
the well designated facility in decimal degrees to an accuracy and
precision of five (5) decimals of a degree using the North American
Datum of 1983; and the information in paragraph (b)(1)(v)(A) or (B) of
this section, as applicable.
(A) The name and contact information, including the phone number,
email address, and mailing address, of the owner or operator to which
you sold or transferred ownership of the well designated facility
identified in this paragraph (b)(1)(v) .
(B) The name and contact information, including the phone number,
email address, and mailing address, of the owner or operator from whom
you acquired the well designated facility identified in this paragraph
(b)(1)(v).
(2) For each well designated facility that is subject to Sec.
60.5390c(a)(1) or (2), your annual report is required to include the
information specified in paragraphs (b)(2)(i) and (ii) of this section,
as applicable.
(i) For each well designated facility where all gas well liquids
unloading operations comply with Sec. 60.5390c(a)(1), your annual
report must include the information specified in paragraphs
(b)(2)(i)(A) through (C) of this section, as applicable.
(A) Identification of each well designated facility (U.S. Well ID
or U.S. Well ID associated with the well designated facility) that
conducts a gas well liquid unloading operation during the reporting
period using a method that does not vent to the atmosphere and the
technology or technique used. If more than one non-venting technology
or technique is used, you must identify all of the differing non-
venting liquids unloading methods used during the reporting period.
(B) Number of gas well liquids unloading operations conducted
during the year where the well designated facility identified in
paragraph (b)(2)(i)(A) of this section had unplanned venting to the
atmosphere and best management practices were conducted according to
your best management practice plan, as required by Sec. 60.5390c(c).
If no venting events occurred, the number would be zero. Other reported
information required to be submitted where unplanned venting occurs is
specified in paragraphs (b)(2)(i)(B)(1) and (2) of this section.
(1) Log of best management practice plan steps used during the
unplanned venting to minimize emissions to the maximum extent possible.
(2) The number of liquids unloading events during the year where
deviations from your best management practice plan occurred, the date
and time the deviation began, the duration of the deviation in hours,
documentation of why best management practice plan steps were not
followed, and what steps, in lieu of your best management practice plan
steps, were followed to minimize emissions to the maximum extent
possible.
(C) The number of liquids unloading events where unplanned
emissions are vented to the atmosphere during a gas well liquids
unloading operation where you complied with best management practices
to minimize emissions to the maximum extent possible.
(ii) For each well designated facility where all gas well liquids
unloading operations comply with Sec. 60.5390c(b) and (c) best
management practices, your annual report must include the information
specified in paragraphs (b)(2)(ii)(A) through (E) of this section.
(A) Identification of each well designated facility that conducts a
gas well liquids unloading during the reporting period.
(B) Number of liquids unloading events conducted during the
reporting period.
(C) Log of best management practice plan steps used during the
reporting period to minimize emissions to the maximum extent possible.
(D) The number of liquids unloading events during the year that
best management practices were conducted according to your best
management practice plan.
(E) The number of liquids unloading events during the year where
deviations from your best management practice
[[Page 18121]]
plan occurred, the date and time the deviation began, the duration of
the deviation in hours, documentation of why best management practice
plan steps were not followed, and what steps, in lieu of your best
management practice plan steps, were followed to minimize emissions to
the maximum extent possible.
(3) For each associated gas well at your well designated facility
that is subject to Sec. 60.5391c, your annual report is required to
include the applicable information specified in paragraphs (b)(3)(i)
through (v) of this section, as applicable.
(i) For each associated gas well at your well designated facility
that complies with Sec. 60.5391c(a)(1), (2), (3), or (4) your annual
report is required to include the information specified in paragraphs
(b)(3)(i)(A) and (B) of this section.
(A) An identification of each existing associated gas well that
complies with Sec. 60.5391c(a)(1), (2), (3), or (4).
(B) The information specified in paragraphs (b)(3)(i)(B)(1) through
(4) of this section for each incident when the associated gas was
temporarily routed to a flare or control device in accordance with
Sec. 60.5391c(c).
(1) The reason in Sec. 60.5391c(c)(1), (2), (3), or (4) for each
incident.
(2) The start date and time of each incident of routing associated
gas to the flare or control device, along with the total duration in
hours of each incident.
(3) Documentation that all CVS requirements specified in Sec.
60.5411c(a) and (c) and all applicable flare or control device
requirements specified in Sec. 60.5412c were met during each period
when the associated gas is routed to the flare or control device.
(4) For each instance where you route associated gas to a flare or
control device beyond 72 hours due to ``exigent circumstances''
according to Sec. 60.5391c(c)(1) or (2), you must include the record
information specified in paragraph (c)(2)(vi) of this section in your
annual report.
(ii) For all instances where you temporarily vent the associated
gas in accordance with Sec. 60.5391c(d), you must report the
information specified in paragraphs (b)(3)(ii)(A) through (D) of this
section. This information is required to be reported if you are
routinely complying with Sec. 60.5391c(a) or (b) or temporarily
complying with Sec. 60.5391c(c). In addition to this information for
each incident, you must report the cumulative duration in hours of
venting incidents and the cumulative VOC and methane emissions in
pounds for all incidents in the calendar year.
(A) The reason in Sec. 60.5391c(d)(1), (2), or (3) for each
incident.
(B) The start date and time of each incident of venting the
associated gas, along with the total duration in hours of each
incident.
(C) The methane emissions in pounds that were emitted during each
incident.
(D) The total duration of venting for all incidents in the year,
along with the cumulative methane emissions in pounds that were
emitted.
(iii) For each associated gas well at your well designated facility
that complies with the requirements of Sec. 60.5391c(b) by routing
your associated gas to a control device that reduces methane emissions
by at least 95.0 percent, your annual report must include the
information specified in paragraphs (b)(3)(iii)(A) through (C), and
paragraph (D) or (E) of this section. The information in paragraphs
(b)(3)(iii)(A) and (B) of this section is only required in the initial
annual report.
(A) Identification of the associated gas well using the control
device and the information in paragraph (b)(10)(v) of this section.
(B) The information specified in paragraphs (b)(10)(i) through (iv)
of this section.
(C) Identification of each instance when associated gas was vented
and not routed to a control device that reduces methane emissions by at
least 95.0 percent in accordance with paragraph (b)(3)(ii) of this
section.
(D) For each associated gas well that complies with the
requirements of Sec. 60.5391c(b) because it has demonstrated that
annual methane emissions are 40 tons per year or less, provide records
of the calculation of annual methane emissions determined in accordance
with Sec. 60.5391c(e)(1).
(E) For each associated gas well facility that complies with the
requirements of Sec. 60.5391c(b) because it has demonstrated that it
is not feasible to comply with Sec. 60.5391c(a)(1), (2), (3), or (4)
due to technical reasons, provide each annual demonstration and
certification of the technical reason that it is not feasible to comply
with Sec. 60.5391c(a)(1) through (4) in accordance with Sec.
60.5391c(b)(2)(i) through (iii).
(iv) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i)
and (ii) of this section, you must provide the information specified in
Sec. 60.5424c.
(v) For each deviation recorded as specified in paragraph
(c)(2)(vi) of this section, the date and time the deviation began, the
duration of the deviation in hours, and a description of the deviation.
If no deviations occurred during the reporting period, you must include
a statement that no deviations occurred during the reporting period.
(4) For each centrifugal compressor that is a designated facility,
the information specified in paragraphs (b)(4)(i) through (ix) of this
section, as applicable.
(i) An identification of each centrifugal compressor.
(ii) For each deviation that occurred during the reporting period
and recorded as specified in paragraph (c)(3) of this section, the date
and time the deviation began, the duration of the deviation in hours,
and a description of the deviation. If no deviations occurred during
the reporting period, you must include a statement that no deviations
occurred during the reporting period.
(iii) If complying with Sec. 60.5392c(a)(1) and (2) wet and dry
seal centrifugal compressor requirements, the cumulative number of
hours of operation since initial startup, since 36 months after the
state plan submittal deadline (as specified in Sec. 60.5362c(c)), or
since the previous volumetric flow rate measurement, as applicable,
which have elapsed prior to conducting your volumetric flow rate
measurement or emissions screening.
(iv) A description of the method used and the results of the
volumetric emissions measurement or emissions screening, as applicable.
(v) If required to comply with Sec. 60.5392c(a)(5), the
information specified in paragraphs (b)(10)(i) through (iv) of this
section.
(vi) If complying with Sec. 60.5392c(a)(4) with a control device,
identification of the centrifugal compressor with the control device
and the information in paragraph (b)(10)(v) of this section.
(vii) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i)
and (ii) of this section, you must provide the information specified in
Sec. 60.5424c.
(viii) Number and type of seals on delay of repair and explanation
for each delay of repair.
(ix) Date of planned shutdown(s) that occurred during the reporting
period if there are any seals that have been placed on delay of repair.
(5) For each reciprocating compressor designated facility, the
information specified in paragraphs (b)(5)(i) through (vii) of this
section, as applicable.
(i) The cumulative number of hours of operation since initial
startup, since 36 months after the state plan submittal deadline (as
specified in Sec. 60.5362c(c)), since the previous volumetric flow
rate measurement, or since the previous
[[Page 18122]]
reciprocating compressor rod packing replacement, as applicable, which
have elapsed prior to conducting your volumetric flow rate measurement
or emissions screening. Alternatively, a statement that emissions from
the rod packing are being routed to a process or control device through
a closed vent system.
(ii) If applicable, for each deviation that occurred during the
reporting period and recorded as specified in paragraph (c)(4)(i) of
this section, the date and time the deviation began, duration of the
deviation in hours and a description of the deviation. If no deviations
occurred during the reporting period, you must include a statement that
no deviations occurred during the reporting period.
(iii) A description of the method used and the results of the
volumetric flow rate measurement or emissions screening, as applicable.
(iv) If complying with Sec. 60.5393c(d)(1) or (2), the information
in paragraphs (b)(10)(i) through (v) of this section.
(v) Number and type of rod packing replacements/repairs on delay of
repair and explanation for each delay of repair.
(vi) Date of planned shutdown(s) that occurred during the reporting
period if there are any rod packing replacements/repairs that have been
placed on delay of repair.
(vii) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i)
and (ii) of this section, you must provide the information specified in
Sec. 60.5424c.
(6) For each process controller designated facility, the
information specified in paragraphs (b)(6)(i) through (iii) of this
section in your initial annual report and in subsequent annual reports
for each process controller designated facility that is constructed,
modified, or reconstructed during the reporting period. Each annual
report must contain the information specified in paragraphs (b)(6)(iv)
through (x) of this section for each process controller designated
facility.
(i) An identification of each existing process controller that is
driven by natural gas, as required by Sec. 60.5394c(d), that allows
traceability to the records required in paragraph (c)(5)(i) of this
section.
(ii) For each process controller in the designated facility
complying with Sec. 60.5394c(a), you must report the information
specified in paragraphs (b)(6)(ii)(A) and (B) of this section, as
applicable.
(A) An identification of each process controller complying with
Sec. 60.5394c(a)(1) by routing the emissions to a process.
(B) An identification of each process controller complying with
Sec. 60.5394c(a)(2) by using a self-contained natural gas-driven
process controller.
(iii) For each process controller designated facility located at a
site in Alaska that does not have access to electrical power and that
complies with Sec. 60.5394c(b), you must report the information
specified in paragraph (b)(6)(iii)(A), (B), or (C) of this section, as
applicable.
(A) For each process controller complying with Sec. 60.5394c(b)(1)
process controller bleed rate requirements, you must report the
information specified in paragraphs (b)(6)(iii)(A)(1) and (2) of this
section.
(1) The identification of process controllers designed and operated
to achieve a bleed rate less than or equal to 6 scfh.
(2) Where necessary to meet a functional need, the identification
and demonstration of why it is necessary to use a process controller
with a natural gas bleed rate greater than 6 scfh.
(B) An identification of each intermittent vent process controller
complying with the requirements in paragraph Sec. 60.5394c(b)(2).
(C) An identification of each process controller complying with the
requirements in Sec. 60.5394c(b) by routing emissions to a control
device in accordance with Sec. 60.5394c(b)(3).
(iv) Identification of each process controller which changes its
method of compliance during the reporting period and the applicable
information specified in paragraphs (b)(6)(v) through (ix) of this
section for the new method of compliance.
(v) For each process controller in the designated facility
complying with the requirements of Sec. 60.5394c(a) by routing the
emissions to a process, you must report the information specified in
paragraphs (b)(10)(i) through (iv) of this section.
(vi) For each process controller in the designated facility
complying with the requirements of Sec. 60.5394c(a) by using a self-
contained natural gas-driven process controller, you must report the
information specified in paragraphs (b)(6)(vi)(A) and (B) of this
section.
(A) Dates of each inspection required under Sec. 60.5416c(b); and
(B) Each defect or leak identified during each natural gas-driven-
self-contained process controller system inspection, and the date of
repair or date of anticipated repair if repair is delayed.
(vii) For each process controller in the designated facility
complying with the requirements of Sec. 60.5394c(b)(2), you must
report the information specified in paragraphs (b)(6)(vii)(A) and (B)
of this section.
(A) Dates and results of the intermittent vent process controller
monitoring required by Sec. 60.5394c(b)(2)(ii).
(B) For each instance in which monitoring identifies emissions to
the atmosphere from an intermittent vent controller during idle
periods, the date of repair or replacement or the date of anticipated
repair or replacement if the repair or replacement is delayed, and the
date and results of the re-survey after repair or replacement.
(viii) For each process controller designated facility complying
with Sec. 60.5394c(b)(3) by routing emissions to a control device, you
must report the information specified in paragraph (b)(10) of this
section.
(ix) For each deviation that occurred during the reporting period,
the date and time the deviation began, the duration of the deviation in
hours, and a description of the deviation. If no deviations occurred
during the reporting period, you must include a statement that no
deviations occurred during the reporting period.
(x) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs
(b)(6)(ii)(B) and (b)(10)(i) and (ii) of this section, you must provide
the information specified in Sec. 60.5424c.
(7) For each storage vessel designated facility, the information in
paragraphs (b)(7)(i) through (x) of this section.
(i) An identification, including the location, of each existing
storage vessel designated facility. The location of the storage vessel
designated facility shall be in latitude and longitude coordinates in
decimal degrees to an accuracy and precision of five (5) decimals of a
degree using the North American Datum of 1983.
(ii) Documentation of the methane emission rate determination
according to Sec. 60.5386c(e)(1) for each tank battery that became a
designated facility during the reporting period or is returned to
service during the reporting period.
(iii) For each deviation that occurred during the reporting period
and recorded as specified in paragraph (c)(6)(iii) of this section, the
date and time the deviation began, duration of the deviation in hours
and a description of the deviation. If no deviations occurred during
the reporting period, you must include a statement that no deviations
occurred during the reporting period.
[[Page 18123]]
(iv) For each storage vessel designated facility complying with
Sec. 60.5396c(a)(2) with a control device, report the identification
of the storage vessel designated facility with the control device and
the information in paragraph (b)(10)(v) of this section.
(v) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i)
and (ii) of this section, you must provide the information specified in
Sec. 60.5424c.
(vi) If required to comply with Sec. 60.5396c(b)(1), the
information in paragraphs (b)(10)(i) through (iv) of this section.
(vii) You must identify each storage vessel designated facility
that is removed from service during the reporting period as specified
in Sec. 60.5396c(c)(1)(ii), including the date the storage vessel
designated facility was removed from service. You must identify each
storage vessel that that is removed from service from a storage vessel
designated facility during the reporting period as specified in Sec.
60.5396c(c)(2)(iii), including identifying the impacted storage vessel
designated facility and the date each storage vessel was removed from
service.
(viii) You must identify each storage vessel designated facility or
portion of a storage vessel designated facility returned to service
during the reporting period as specified in Sec. 60.5396c(c)(4),
including the date the storage vessel designated facility or portion of
a storage vessel designated facility was returned to service.
(ix) You must identify each storage vessel designated facility that
no longer complies with Sec. 60.5396c(a)(3) and instead complies with
Sec. 60.5396c(a)(2). You must identify whether the change in the
method of compliance was due to fracturing or refracturing or whether
the change was due to an increase in the monthly emissions
determination. If the change was due to an increase in the monthly
emissions determination, you must provide documentation of the
emissions rate. You must identify the date that you complied with Sec.
60.5396c(a)(2) and must submit the information in (b)(7)(iii) through
(vii) of this section.
(x) You must submit a statement that you are complying with Sec.
60.112b(a)(1) or (2), if applicable, in your initial annual report.
(8) For the fugitive emissions components designated facility,
report the information specified in paragraphs (b)(8)(i) through (iv)
of this section, as applicable.
(i)(A) Designation of the type of site (i.e., well site,
centralized production facility, or compressor station) at which the
fugitive emissions components designated facility is located.
(B) For the fugitive emissions components designated facility at a
well site or centralized production facility that became a designated
facility during the reporting period, you must include the date of the
startup of production or the date of the first day of production after
modification. For the fugitive emissions components designated facility
at a compressor station that became a designated facility during the
reporting period, you must include the date of startup or the date of
modification.
(C) For the fugitive emissions components designated facility at a
well site, you must specify what type of well site it is (i.e., single
wellhead only well site, small wellsite, multi-wellhead only well site,
or a well site with major production and processing equipment).
(D) For the fugitive emissions components designated facility at a
well site where during the reporting period you complete the removal of
all major production and processing equipment such that the well site
contains only one or more wellheads, you must include the date of the
change to status as a wellhead only well site.
(E) For the fugitive emissions components designated facility at a
well site where you previously reported under paragraph (b)(8)(i)(D) of
this section the removal of all major production and processing
equipment and during the reporting period major production and
processing equipment is added back to the well site, the date that the
first piece of major production and processing equipment is added back
to the well site.
(F) For the fugitive emissions components designated facility at a
well site where during the reporting period you undertake well closure
requirements, the date of the cessation of production from all wells at
the well site, the date you began well closure activities at the well
site, and the dates of the notifications submitted in accordance with
paragraph (a)(3) of this section.
(ii) For each fugitive emissions monitoring survey performed during
the annual reporting period, the information specified in paragraphs
(b)(8)(ii)(A) through (G) of this section.
(A) Date of the survey.
(B) Monitoring instrument or, if the survey was conducted by
visual, audible, or olfactory methods, notation that AVO was used.
(C) Any deviations from the monitoring plan elements under Sec.
60.5397c(c)(1), (2), (7), and (8) or (d) or a statement that there were
no deviations from these elements of the monitoring plan.
(D) Number and type of components for which fugitive emissions were
detected.
(E) Number and type of fugitive emissions components that were not
repaired as required in Sec. 60.5397c(h).
(F) Number and type of fugitive emission components (including
designation as difficult-to-monitor or unsafe-to-monitor, if
applicable) on delay of repair and explanation for each delay of
repair.
(G) Date of planned shutdown(s) that occurred during the reporting
period if there are any components that have been placed on delay of
repair.
(iii) For well closure activities which occurred during the
reporting period, the information in paragraphs (b)(8)(iii)(A) and (B)
of this section.
(A) A status report with dates for the well closure activities
schedule developed in the well closure plan. If all steps in the well
closure plan are completed in the reporting period, the date that all
activities are completed.
(B) If an OGI survey is conducted during the reporting period, the
information in paragraphs (b)(8)(iii)(B)(1) through (3) of this
section.
(1) Date of the OGI survey.
(2) Monitoring instrument used.
(3) A statement that no fugitive emissions were found, or if
fugitive emissions were found, a description of the steps taken to
eliminate those emissions, the date of the resurvey, the results of the
resurvey, and the date of the final resurvey which detected no
emissions.
(iv) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i)
and (ii) of this section, you must provide the information specified in
Sec. 60.5424c.
(9) For each pump designated facility, the information specified in
paragraphs (b)(9)(i) through (iv) of this section in your initial
annual report. Each annual report must contain the information
specified in paragraphs (b)(9)(v) through (ix) of this section for each
pump designated facility.
(i) The identification of each of your pumps that are driven by
natural gas, as required by Sec. 60.5395c(a) that allows traceability
to the records required by paragraph (c)(14)(i) of this section.
(ii) For each pump designated facility for which there is a control
device on site but it does not achieve a 95.0
[[Page 18124]]
percent emissions reduction, the certification that there is a control
device available on site but it does not achieve a 95.0 percent
emissions reduction required under Sec. 60.5395c(b)(5). You must also
report the emissions reduction percentage the control device is
designed to achieve.
(iii) For each pump designated facility for which there is no
control device or vapor recovery unit on site, the certification
required under Sec. 60.5395c(b)(6) that there is no control device or
vapor recovery unit on site.
(iv) For each pump designated facility for which it is technically
infeasible to route the emissions to a process or control device, the
certification of technically infeasibility required under Sec.
60.5395c(b)(7).
(v) For any pump designated facility which has previously reported
as required under paragraphs (b)(9)(i) through (iv) of this section and
for which a change in the reported condition has occurred during the
reporting period, provide the identification of the pump designated
facility and the date that the pump designated facility meets one of
the change conditions described in paragraphs (b)(9)(v)(A) through (C)
of this section.
(A) If you install a control device or vapor recovery unit, you
must report that a control device or vapor recovery unit has been added
to the site and that the pump designated facility now is required to
comply with Sec. 60.5395c(b)(1) or (3), as applicable.
(B) If your pump designated facility previously complied with Sec.
60.5395c(b)(1) or (3), as applicable, by routing emissions to a process
or a control device and the process or control device is subsequently
removed from the site or is no longer available such that there is no
ability to route the emissions to a process or control device at the
location, or that it is not technically feasible to capture and route
the emissions to another control device or process located on site,
report that you are no longer complying with the applicable
requirements of Sec. 60.5395c(b)(1) or (3) and submit the information
provided in paragraph (b)(9)(v)(B)(1) or (2) of this section.
(1) Certification that there is no control device or vapor recovery
unit on site.
(2) Certification of the engineering assessment that it is
technically infeasible to capture and route the emissions to another
control device or process located on site.
(C) If any pump affected facility or individual natural gas-driven
pump changes its method of compliance during the reporting period other
than for the reasons specified in paragraphs (b)(9)(v)(A) and (B) of
this section, identify the new compliance method for each natural gas-
driven pump within the affected facility which changes its method of
compliance during the reporting period and provide the applicable
information specified in paragraphs (b)(9)(ii) through (iv) and (vi)
through (viii) of this section for the new method of compliance.
(vi) For each pump designated facility complying with the
requirements of Sec. 60.5395c(a) or (b)(2) by routing the emissions to
a process, you must report the information specified in paragraphs
(b)(10)(i) through (iv) of this section.
(vii) For each pump designated facility complying with the
requirements of Sec. 60.5395c(b)(3) by routing the emissions to a
control device, you must report the information required under
paragraph (b)(10) of this section.
(viii) For each deviation that occurred during the reporting
period, the date and time the deviation began, the duration of the
deviation in hours, and a description of the deviation. If no
deviations occurred during the reporting period, you must include a
statement that no deviations occurred during the reporting period.
(ix) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs (b)(10)(i)
and (ii) of this section, you must provide the information specified in
Sec. 60.5424c.
(10) For each well, centrifugal compressor, reciprocating
compressor, storage vessel, process controller, pump, or process unit
equipment designated facility which uses a closed vent system routed to
a control device to meet the emissions reduction standard, you must
submit the information in paragraphs (b)(10)(i) through (v) of this
section. For each centrifugal compressor, reciprocating compressor,
process controller, pump, storage vessel, or process unit equipment
which uses a closed vent system to route to a process, you must submit
the information in paragraphs (b)(10)(i) through (iv) of this section.
For each centrifugal compressor, reciprocating compressor, and storage
vessel equipped with a cover, you must submit the information in
paragraphs (b)(10)(i) and (ii).
(i) Dates of each inspection required under Sec. 60.5416c(a) and
(b).
(ii) Each defect or emissions identified during each inspection and
the date of repair or the date of anticipated repair if the repair is
delayed.
(iii) Date and time of each bypass alarm or each instance the key
is checked out if you are subject to the bypass requirements of Sec.
60.5416c(a)(4).
(iv) You must submit the certification signed by the qualified
professional engineer or in-house engineer according to Sec.
60.5411c(c) for each closed vent system routing to a control device or
process in the reporting year in which the certification is signed.
(v) If you comply with the emissions standard for your well,
centrifugal compressor, reciprocating compressor, storage vessel,
process controller, pump, or process unit equipment designated facility
with a control device, the information in paragraphs (b)(10)(v)(A)
through (L) of this section, unless you use an enclosed combustion
device or flare using an alternative test method approved under Sec.
60.5412c(d). If you use an enclosed combustion device or flare using an
alternative test method approved under Sec. 60.5412c(d), the
information in paragraphs (b)(10)(v)(A) through (C) and (L) through (P)
of this section.
(A) Identification of the control device.
(B) Make, model, and date of installation of the control device.
(C) Identification of the designated facility controlled by the
device.
(D) For each continuous parameter monitoring system used to
demonstrate compliance for the control device, a unique continuous
parameter monitoring system identifier and the make, model number, and
date of last calibration check of the continuous parameter monitoring
system.
(E) For each instance where there is a deviation of the control
device in accordance with Sec. 60.5417c(g)(1) through (3) or (5)
through (7) include the date and time the deviation began, the duration
of the deviation in hours, the type of the deviation (e.g., NHV
operating limit, lack of pilot or combustion flame, condenser
efficiency, bypass line flow, visible emissions), and cause of the
deviation.
(F) For each instance where there is a deviation of the continuous
parameter monitoring system in accordance with Sec. 60.5417c(g)(4)
include the date and time the deviation began, the duration of the
deviation in hours, and cause of the deviation.
(G) For each visible emissions test following return to operation
from a maintenance or repair activity, the date of the visible
emissions test or observation of the video surveillance output, the
length of the observation in minutes, and the number of minutes for
which visible emissions were present.
[[Page 18125]]
(H) If a performance test was conducted on the control device
during the reporting period, provide the date the performance test was
conducted. Submit the performance test report following the procedures
specified in paragraph (b)(11) of this section.
(I) An indication of whether the enclosed combustion device or
flare receives inert gases or other vent streams which may lower the
NHV of the combined stream, and if so, a description of the operating
scenario(s) which may lower the NHV of the combined stream through the
introduction of inert gases or other vent gas streams. If a
demonstration of the NHV of the inlet gas to the enclosed combustion
device or flare was conducted during the reporting period in accordance
with Sec. 60.5417c(d)(8)(iii), an indication of whether this is a re-
evaluation of vent gas NHV and the reason for the re-evaluation; the
applicable required minimum vent gas NHV; if twice daily samples of the
vent stream were taken, the number of samples with NHV values that are
less than 1.2 times the applicable required minimum NHV, an indication
of whether full one hour samples were collected or if shorter sampling
times and, if shorter sampling times were used, the collection time(s)
used and the reason for not obtaining a full one hour sample; if
continuous NHV sampling of the vent stream was conducted, the number of
hourly block average NHV values that are less than the required minimum
vent gas NHV; if continuous combustion efficiency monitoring was
conducted using an alternative test method approved under Sec.
60.5412c(d), the number of values of the combustion efficiency that
were less than 95.0 percent; the resulting determination of whether
continuous NHV monitoring is required or not in accordance with Sec.
60.5417c(d)(8)(iii)(D), (E), or (H); and if the enclosed combustion
device or flare received inert gases or other vent streams which may
lower the NHV of the combined stream, whether the sampling included
periods where the highest percentage of inert gases or other vent
streams which may lower the NHV of the combined stream were sent to the
enclosed combustion device or flare.
(J) If a demonstration was conducted in accordance with Sec.
60.5417c(d)(8)(iv) that the maximum potential pressure of units
manifolded to an enclosed combustion device or flare cannot cause the
maximum inlet flow rate established in accordance with Sec.
60.5417c(f)(1) or a flare tip velocity limit of 18.3 meter/second (60
feet/second) to be exceeded, an indication of whether this is a re-
evaluation of the gas flow and the reason for the re-evaluation; the
demonstration conducted; and applicable engineering calculations.
(K) For each periodic sampling event conducted under Sec.
60.5417c(d)(8)(iii)(G), provide the date of the sampling, the required
minimum vent gas NHV, and the NHV value for each vent gas sample.
(L) For each flare and enclosed combustion device, provide the date
each device is observed with OGI in accordance with Sec.
60.5415c(e)(1)(x) and whether uncombusted emissions were present.
Provide the date each device was visibly observed during an AVO
inspection in accordance with Sec. 60.5415c(e)(1)(x), whether the
pilot or combustion flame was lit at the time of observation, and
whether the device was found to be operating properly.
(M) An identification of the alternative test method used.
(N) For each instance where there is a deviation of the control
device in accordance with Sec. 60.5417c(i)(6)(i) or (iii) through (v)
include the date and time the deviation began, the duration of the
deviation in hours, the type of the deviation (e.g., destruction
efficiency below 95 percent, lack of pilot or combustion flame, visible
emissions), and cause of the deviation.
(O) For each instance where there is a deviation of the data
availability in accordance with Sec. 60.5417c(i)(6)(ii) include the
date of each operating day when monitoring data are not available for
at least 75 percent of the operating hours.
(P) If no deviations occurred under paragraph (b)(10)(v)(N) or (O)
of this section, a statement that there were no deviations for the
control device during the annual report period.
(Q) Any additional information required to be reported as specified
by the Administrator as part of the alternative test method approval
under Sec. 60.5412c(d).
(11) Within 60 days after the date of completing each performance
test (see Sec. 60.8) required by this subpart, except testing
conducted by the manufacturer as specified in Sec. 60.5413c(d), you
must submit the results of the performance test following the
procedures specified in paragraph (d) of this section. Data collected
using test methods that are supported by the EPA's Electronic Reporting
Tool (ERT) as listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at
the time of the test must be submitted in a file format generated using
the EPA's ERT. Alternatively, you may submit an electronic file
consistent with the extensible markup language (XML) schema listed on
the EPA's ERT website. Data collected using test methods that are not
supported by the EPA's ERT as listed on the EPA's ERT website at the
time of the test must be included as an attachment in the ERT or
alternate electronic file.
(12) For combustion control devices tested by the manufacturer in
accordance with Sec. 60.5413c(d), an electronic copy of the
performance test results required by Sec. 60.5413c(d) shall be
submitted via email to [email protected] unless the test results
for that model of combustion control device are posted at the following
website: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.
(13) If you had a super-emitter event during the reporting period,
the start date of the super-emitter event, the duration of the super-
emitter event in hours, and the designated facility associated with the
super-emitter event, if applicable.
(14) You must submit your annual report using the appropriate
electronic report template on the Compliance and Emissions Data
Reporting Interface (CEDRI) website for this subpart and following the
procedure specified in paragraph (d) of this section. If the reporting
form specific to this subpart is not available on the CEDRI website at
the time that the report is due, you must submit the report to the
Administrator at the appropriate address listed in Sec. 60.4. Once the
form has been available on the CEDRI website for at least 90 calendar
days, you must begin submitting all subsequent reports via CEDRI. The
date reporting forms become available will be listed on the CEDRI
website. Unless the Administrator or delegated state agency or other
authority has approved a different schedule for submission of reports,
the report must be submitted by the deadline specified in this subpart,
regardless of the method in which the report is submitted.
(c) Recordkeeping requirements. You must maintain the records
identified as specified in Sec. 60.7(f) and in paragraphs (c)(1)
through (14) of this section. All records required by this subpart must
be maintained either onsite or at the nearest local field office for at
least 5 years. Any records required to be maintained by this subpart
that are submitted electronically via the EPA's CEDRI may be maintained
in electronic format. This ability to maintain electronic copies does
not affect the requirement for facilities to make records, data, and
reports available upon request to a delegated air agency
[[Page 18126]]
or the EPA as part of an on-site compliance evaluation.
(1) For each gas well liquids unloading operation at your well
designated facility that is subject to Sec. 60.5390c(a)(1) or (2), the
records of each gas well liquids unloading operation conducted during
the reporting period, including the information specified in paragraphs
(c)(1)(i) through (iii) of this section, as applicable.
(i) For each gas well liquids unloading operation that complies
with Sec. 60.5390c(a)(1) by performing all liquids unloading events
without venting of methane emissions to the atmosphere, comply with the
recordkeeping requirements specified in paragraphs (c)(1)(i)(A) and (B)
of this section.
(A) Identification of each well (i.e., U.S. Well ID or U.S. Well ID
associated with the well designated facility) that conducts a gas well
liquids unloading operation during the reporting period without venting
of methane emissions and the non-venting gas well liquids unloading
method used. If more than one non-venting method is used, you must
maintain records of all the differing non-venting liquids unloading
methods used at the well designated facility complying with Sec.
60.5390c(a)(1).
(B) Number of events where unplanned emissions are vented to the
atmosphere during a gas well liquids unloading operation where you
complied with best management practices to minimize emissions to the
maximum extent possible.
(ii) For each gas well liquids unloading operation that complies
with Sec. 60.5390c(b) and (c) best management practices, maintain
records documenting information specified in paragraphs (c)(1)(ii)(A)
through (D) of this section.
(A) Identification of each well designated facility that conducts
liquids unloading during the reporting period that employs best
management practices to minimize emissions to the maximum extent
possible.
(B) Documentation of your best management practice plan developed
under paragraph Sec. 60.5390c(c). You may update your best management
practice plan to include additional steps which meet the criteria in
Sec. 60.5390c(c).
(C) A log of each best management practice plan step taken to
minimize emissions to the maximum extent possible for each gas well
liquids unloading event.
(D) Documentation of each gas well liquids unloading event where
deviations from your best management practice plan steps occurred, the
date and time the deviation began, the duration of the deviation,
documentation of best management practice plans steps were not
followed, and the steps taken in lieu of your best management practice
plan steps during those events to minimize emissions to the maximum
extent possible.
(iii) For each well designated facility that reduces methane
emissions from well designated facility gas wells that unload liquids
by 95.0 percent by routing emissions to a control device through closed
vent system under Sec. 60.5390c(g), you must maintain the records in
paragraphs (c)(1)(iii)(A) through (E) of this section.
(A) If you comply with the emission reduction standard with a
control device, the information for each control device in paragraph
(c)(10) of this section.
(B) Records of the closed vent system inspection as specified
paragraph in (c)(7) of this section.
(C) Records of the cover inspections as specified in paragraph
(c)(8) of this section.
(D) If applicable, the records of bypass monitoring as specified in
paragraph (c)(9) of this section.
(E) Records of the closed vent system assessment as specified in
paragraph (c)(11) of this section.
(2) For each associated gas well, you must maintain the applicable
records specified in paragraphs (c)(2)(i) or (ii) and (iii), (iv), (v),
(vi) and (vii) of this section, as applicable.
(i) For each associated gas well that complies with the
requirements of Sec. 60.5391c(a)(1), (2), (3), or (4), you must keep
the records specified in paragraphs (c)(2)(i)(A) and (B) of this
section.
(A) Documentation of the specific method(s) in Sec.
60.5391c(a)(1), (2), (3), or (4) that was used.
(B) For instances where you temporarily route the associated gas to
a flare or control device in accordance with Sec. 60.5391c(c), you
must keep the records specified in paragraphs (c)(2)(i)(B)(1) through
(3) of this section.
(1) The reason in Sec. 60.5391c(c)(1), (2), (3), or (4) for each
incident.
(2) The date of each incident, along with the times when routing
the associated gas to the flare or control device started and ended,
along with the total duration of each incident.
(3) Documentation that all CVS requirements specified in Sec.
60.5411c(a) and (c) and all applicable flare or control device
requirements specified in Sec. 60.5412c are met during each period
when the associated gas is routed to the flare or control device.
(ii) For instances where you temporarily vent the associated gas in
accordance with Sec. 60.5391c(d), you must keep the records specified
in paragraphs (c)(2)(ii)(A) through (D) of this section. These records
are required if you are routinely complying with Sec. 60.5391c(a) or
Sec. 60.5391c(b) or temporarily complying with Sec. 60.5391c(c).
(A) The reason in Sec. 60.5391c(d)(1), (2), or (3) for each
incident.
(B) The date of each incident, along with the times when venting
the associated gas started and ended, along with the total duration of
each incident.
(C) The methane emissions that were emitted during each incident.
(D) The cumulative duration of venting incidents and methane
emissions for all incidents in each calendar year.
(iii) For each associated gas well that complies with the
requirements of Sec. 60.5391c(b) because it has demonstrated that
annual methane emissions are 40 tons per year or less at the initial
compliance date, maintain records of the calculation of annual methane
emissions determined in accordance with Sec. 60.5391c(e)(1).
(iv) For each associated gas well at your well that complies with
the requirements of Sec. 60.5391c(b) because it has demonstrated that
it is not feasible to comply with Sec. 60.5391c(a)(1), (2), (3), or
(4) due to technical reasons, records of each annual demonstration and
certification of the technical reason that it is not feasible to comply
with Sec. 60.5391c(a)(1) through (4) in accordance with Sec.
60.5391c(b)(2)(i) through (iii), as well as the records required by
paragraph (c)(2)(v) of this section.
(v) For each associated gas well that complies with the
requirements of Sec. 60.5391c(b) by routing your associated gas to a
flare or control device that achieves a 95.0 reduction in methane
emissions, the records in paragraphs (c)(2)(v)(A) through (E) of this
section.
(A) Identification of each instance when associated gas was vented
and not routed to a control device that reduces methane emissions by at
least 95.0 percent in accordance with paragraph (c)(2)(iii) of this
section.
(B) If you comply with the emission reduction standard in Sec.
60.5391c with a control device, the information for each control device
in paragraph (c)(10) of this section.
(C) Records of the closed vent system inspection as specified in
paragraph (c)(7) of this section. If you comply with an alternative GHG
standard under Sec. 60.5398c, in lieu of the information specified in
paragraphs (c)(7) of this section, you must maintain records of the
information specified in Sec. 60.5424c.
[[Page 18127]]
(D) If applicable, the records of bypass monitoring as specified in
paragraph (c)(9) of this section.
(E) Records of the closed vent system assessment as specified in
paragraph (c)(11) of this section.
(vi) For each instance where you route associated gas to a flare or
control device for beyond 72 hours due to an ``exigent circumstance''
according to Sec. 60.5391c(c)(1) or (2), you must maintain the records
specified in paragraphs (c)(2)(vi)(A) through (D) of this section.
(A) A written description of the ``exigent circumstance'' requiring
the need to flare or route to a control device beyond 72 hours.
(B) A description of steps taken to resolve the need for temporary
flaring/routing to a control device;
(C) The dates and times an identified ``exigent circumstance''
started and ended (e.g., when owners or operators are able to access
site, when personnel and/or equipment are available) and the total
duration of each ``exigent circumstance''; and
(D) The dates and times temporary flaring/routing to a control
device started and ended and the total duration of temporary flaring/
routing to a control device due to the identified ``exigent
circumstance.''
(vii) Records of each deviation, the date and time the deviation
began, the duration of the deviation, and a description of the
deviation.
(3) For each centrifugal compressor designated facility, you must
maintain the records specified in paragraphs (c)(3)(i) through (iii) of
this section.
(i) For each centrifugal compressor designated facility, you must
maintain records of deviations in cases where the centrifugal
compressor was not operated in compliance with the requirements
specified in Sec. 60.5392c, including a description of each deviation,
the date and time each deviation began and the duration of each
deviation.
(ii) For each wet seal compressor complying with the emissions
reduction standard in Sec. 60.5392c(a)(3) and (4), you must maintain
the records in paragraphs (c)(3)(ii)(A) through (E) of this section.
For each wet seal compressor complying with the alternative standard in
Sec. 60.5392c(a)(3) and (5) by routing the closed vent system to a
process, you must maintain the records in paragraphs (c)(3)(ii)(B)
through (E) of this section.
(A) If you comply with the emission reduction standard in Sec.
60.5392c(a)(3) and (4) with a control device, the information for each
control device in paragraph (c)(10) of this section.
(B) Records of the closed vent system inspection as specified in
paragraph (c)(7) of this section. If you comply with an alternative GHG
standard under Sec. 60.5398c, in lieu of the information specified in
paragraphs (c)(7) of this section, you must maintain records of the
information specified in Sec. 60.5424c.
(C) Records of the cover inspections as specified in paragraph
(c)(8) of this section. If you comply with an alternative GHG standard
under Sec. 60.5398c, in lieu of the information specified in paragraph
(c)(8) of this section, you must maintain the information specified in
Sec. 60.5424c.
(D) If applicable, the records of bypass monitoring as specified in
paragraph (c)(9) of this section.
(E) Records of the closed vent system assessment as specified in
paragraph (c)(11) of this section.
(iii) For each centrifugal compressor designated facility using dry
seals or wet seals and each self-contained wet seal centrifugal
compressor and complying with the standard in Sec. 60.5392c(a)(1) and
(2), you must maintain the records specified in paragraphs
(c)(3)(iii)(A) through (H) of this section.
(A) Records of the cumulative number of hours of operation since
initial startup, since 36 months after the state plan submittal
deadline (as specified in Sec. 60.5362c(c)), or since the previous
volumetric flow rate measurement, as applicable.
(B) A description of the method used and the results of the
volumetric flow rate measurement or emissions screening, as applicable.
(C) Records for all flow meters, composition analyzers and pressure
gauges used to measure volumetric flow rates as specified in paragraphs
(c)(3)(iii)(C)(1) through (6) of this section.
(1) Description of standard method published by a consensus-based
standards organization or industry standard practice.
(2) Records of volumetric flow rate emissions calculations
conducted according to Sec. 60.5392c(a)(2), as applicable.
(3) Records of manufacturer operating procedures and measurement
methods.
(4) Records of manufacturer's recommended procedures or an
appropriate industry consensus standard method for calibration and
results of calibration, recalibration and accuracy checks.
(5) Records which demonstrate that measurements at the remote
location(s) can, when appropriate correction factors are applied,
reliably and accurately represent the actual temperature or total
pressure at the flow meter under all expected ambient conditions. You
must include the date of the demonstration, the data from the
demonstration, the mathematical correlation(s) between the remote
readings and actual flow meter conditions derived from the data, and
any supporting engineering calculations. If adjustments were made to
the mathematical relationships, a record and description of such
adjustments.
(6) Record of each initial calibration or a recalibration which
failed to meet the required accuracy specification and the date of the
successful recalibration.
(D) Date when performance-based volumetric flow rate is exceeded.
(E) The date of successful repair of the compressor seal, including
follow-up performance-based volumetric flow rate measurement to confirm
successful repair.
(F) Identification of each compressor seal placed on delay of
repair and explanation for each delay of repair.
(G) For each compressor seal or part needed for repair placed on
delay of repair because of replacement seal or part unavailability, the
operator must document: the date the seal or part was added to the
delay of repair list, the date the replacement seal or part was
ordered, the anticipated seal or part delivery date (including any
estimated shipment or delivery date provided by the vendor), and the
actual arrival date of the seal or part.
(H) Date of planned shutdowns that occur while there are any seals
or parts that have been placed on delay of repair.
(4) For each reciprocating compressor designated facility, you must
maintain the records in paragraphs (c)(4)(i) through (x) and (c)(7)
through (12) of this section, as applicable. If you comply with an
alternative GHG standard under Sec. 60.5398c, in lieu of the
information specified in paragraph (c)(7) of this section, you must
provide the information specified in Sec. 60.5424c.
(i) For each reciprocating compressor designated facility, you must
maintain records of deviations in cases where the reciprocating
compressor was not operated in compliance with the requirements
specified in Sec. 60.5393c, including a description of each deviation,
the date and time each deviation began and the duration of each
deviation in hours.
(ii) Records of the date of installation of a rod packing emissions
collection system and closed vent system as specified in Sec.
60.5393c(d), where applicable.
(iii) Records of the cumulative number of hours of operation since
initial startup, since 36 months after the state plan submittal
deadline (as specified in Sec. 60.5362c(c)), or since the
[[Page 18128]]
previous volumetric flow rate measurement, as applicable.
Alternatively, a record that emissions from the rod packing are being
routed to a process through a closed vent system.
(iv) A description of the method used and the results of the
volumetric flow rate measurement or emissions screening, as applicable.
(v) Records for all flow meters, composition analyzers and pressure
gauges used to measure volumetric flow rates as specified in paragraphs
(c)(4)(v)(A) through (F) of this section.
(A) Description of standard method published by a consensus-based
standards organization or industry standard practice.
(B) Records of volumetric flow rate calculations conducted
according to Sec. 60.5393c(b) or (c), as applicable.
(C) Records of manufacturer's operating procedures and measurement
methods.
(D) Records of manufacturer's recommended procedures or an
appropriate industry consensus standard method for calibration and
results of calibration, recalibration and accuracy checks.
(E) Records which demonstrate that measurements at the remote
location(s) can, when appropriate correction factors are applied,
reliably and accurately represent the actual temperature or total
pressure at the flow meter under all expected ambient conditions. You
must include the date of the demonstration, the data from the
demonstration, the mathematical correlation(s) between the remote
readings and actual flow meter conditions derived from the data, and
any supporting engineering calculations. If adjustments were made to
the mathematical relationships, a record and description of such
adjustments.
(F) Record of each initial calibration or a recalibration which
failed to meet the required accuracy specification and the date of the
successful recalibration.
(vi) Date when performance-based volumetric flow rate is exceeded.
(vii) The date of successful replacement or repair of reciprocating
compressor rod packing, including follow-up performance-based
volumetric flow rate measurement to confirm successful repair.
(viii) Identification of each reciprocating compressor placed on
delay of repair because of rod packing or part unavailability and
explanation for each delay of repair.
(ix) For each reciprocating compressor that is placed on delay of
repair because of replacement rod packing or part unavailability, the
operator must document: the date the rod packing or part was added to
the delay of repair list, the date the replacement rod packing or part
was ordered, the anticipated rod packing or part delivery date
(including any estimated shipment or delivery date provided by the
vendor), and the actual arrival date of the rod packing or part.
(x) Date of planned shutdowns that occur while there are any
reciprocating compressors that have been placed on delay of repair due
to the unavailability of rod packing or parts to conduct repairs.
(5) For each process controller designated facility, you must
maintain the records specified in paragraphs (c)(5)(i) through (vii) of
this section.
(i) Records identifying each process controller that is driven by
natural gas and that does not function as an emergency shutdown device.
(ii) For each process controller designated facility complying with
Sec. 60.5394c(a), you must maintain records of the information
specified in paragraphs (c)(5)(ii)(A) and (B) of this section, as
applicable.
(A) If you are complying with Sec. 60.5394c(a) by routing process
controller vapors to a process through a closed vent system, you must
report the information specified in paragraphs (c)(5)(ii)(A)(1) and (2)
of this section.
(1) An identification of all the natural gas-driven process
controllers in the process controller designated facility for which you
collect and route vapors to a process through a closed vent system.
(2) The records specified in paragraphs (c)(7), (9), and (11) of
this section. If you comply with an alternative GHG standard under
Sec. 60.5398c, in lieu of the information specified in paragraph
(c)(7) of this section, you must provide the information specified in
Sec. 60.5424c.
(B) If you are complying with Sec. 60.5394c(a) by using a self-
contained natural gas-driven process controller, you must report the
information specified in paragraphs (c)(5)(ii)(B)(1) through (3) of
this section.
(1) An identification of each process controller complying with
Sec. 60.5394c(a) by using a self-contained natural gas-driven process
controller;
(2) Dates of each inspection required under Sec. 60.5416c(b); and
(3) Each defect or leak identified during each natural gas-driven-
self-contained process controller system inspection, and date of repair
or date of anticipated repair if repair is delayed.
(iii) For each process controller designated facility complying
with Sec. 60.5394c(b)(1) process controller bleed rate requirements,
you must maintain records of the information specified in paragraphs
(c)(5)(iii)(A) and (B) of this section.
(A) The identification of process controllers designed and operated
to achieve a bleed rate less than or equal to 6 scfh and records of the
manufacturer's specifications indicating that the process controller is
designed with a natural gas bleed rate of less than or equal to 6 scfh.
(B) Where necessary to meet a functional need, the identification
of the process controller and demonstration of why it is necessary to
use a process controller with a natural gas bleed rate greater than 6
scfh.
(iv) For each intermittent vent process controller in the
designated facility complying with the requirements in Sec.
60.5394c(b)(2), you must keep records of the information specified in
paragraphs (c)(5)(iv)(A) through (C) of this section.
(A) The identification of each intermittent vent process
controller.
(B) Dates and results of the intermittent vent process controller
monitoring required by Sec. 60.5394c(b)(2)(ii).
(C) For each instance in which monitoring identifies emissions to
the atmosphere from an intermittent vent controller during idle
periods, the date of repair or replacement, or the date of anticipated
repair or replacement if the repair or replacement is delayed and the
date and results of the re-survey after repair or replacement.
(v) For each process controller designated facility complying with
Sec. 60.5394c(b)(3), you must maintain the records specified in
paragraphs (c)(5)(v)(A) and (B) of this section.
(A) An identification of each process controller for which
emissions are routed to a control device.
(B) Records specified in paragraphs (c)(7) and (9) through (12) of
this section. If you comply with an alternative GHG standard under
Sec. 60.5398c, in lieu of the information specified in paragraphs
(c)(7) of this section, you must provide the information specified in
Sec. 60.5424c.
(vi) Records of each change in compliance method, including
identification of each natural gas-driven process controller which
changes its method of compliance, the new method of compliance, and the
date of the change in compliance method.
(vii) Records of each deviation, the date and time the deviation
began, the duration of the deviation, and a description of the
deviation.
(6) For each storage vessel designated facility, you must maintain
the records identified in paragraphs (c)(6)(i) through (vii) of this
section.
[[Page 18129]]
(i) You must maintain records of the identification and location in
latitude and longitude coordinates in decimal degrees to an accuracy
and precision of five (5) decimals of a degree using the North American
Datum of 1983 of each storage vessel designated facility.
(ii) Records of each methane emissions determination for each
storage vessel designated facility made under Sec. 60.5386c(e)
including identification of the model or calculation methodology used
to calculate the methane emission rate.
(iii) For each instance where the storage vessel was not operated
in compliance with the requirements specified in Sec. 60.5396c, a
description of the deviation, the date and time each deviation began,
and the duration of the deviation.
(iv) If complying with the emissions reduction standard in Sec.
60.5396c(a)(1), you must maintain the records in paragraphs
(c)(6)(iv)(A) through (E) of this section.
(A) If you comply with the emission reduction standard with a
control device, the information for each control device in paragraph
(c)(10) of this section.
(B) Records of the closed vent system inspection as specified in
paragraph (c)(7) of this section. If you comply with an alternative GHG
standard under Sec. 60.5398c, in lieu of the information specified in
paragraph (c)(7) of this section, you must provide the information
specified in Sec. 60.5424c.
(C) Records of the cover inspections as specified in paragraph
(c)(8) of this section. If you comply with an alternative GHG standard
under Sec. 60.5398c, in lieu of the information specified in paragraph
(c)(8) of this section, you must provide the information specified in
Sec. 60.5424c.
(D) If applicable, the records of bypass monitoring as specified in
paragraph (c)(9) of this section.
(E) Records of the closed vent system assessment as specified in
paragraph (c)(11) of this section.
(v) For storage vessels that are skid-mounted or permanently
attached to something that is mobile (such as trucks, railcars, barges,
or ships), records indicating the number of consecutive days that the
vessel is located at a site in the crude oil and natural gas source
category. If a storage vessel is removed from a site and, within 30
days, is either returned to the site or replaced by another storage
vessel at the site to serve the same or similar function, then the
entire period since the original storage vessel was first located at
the site, including the days when the storage vessel was removed, will
be added to the count towards the number of consecutive days.
(vi) Records of the date that each storage vessel designated
facility or portion of a storage vessel designated facility is removed
from service and returned to service, as applicable.
(vii) Records of the date that liquids from the well following
fracturing or refracturing are routed to the storage vessel designated
facility; or the date that you comply with paragraph Sec.
60.5396c(a)(2), following a monthly emissions determination which
indicates that methane emissions increase to 14 tpy or greater and the
increase is not associated with fracturing or refracturing of a well
feeding the storage vessel designated facility, and records of the
methane emissions rate and the model or calculation methodology used to
calculate the methane emission rate.
(7) Records of each closed vent system inspection required under
Sec. 60.5416c(a)(1) and (2) and (b) for your well, centrifugal
compressor, reciprocating compressor, process controller, pump, storage
vessel, and process unit equipment designated facility as required in
paragraphs (c)(7)(i) through (iv) of this section.
(i) A record of each closed vent system inspection or no
identifiable emissions monitoring survey. You must include an
identification number for each closed vent system (or other unique
identification description selected by you), the date of the
inspection, and the method used to conduct the inspection (i.e.,
visual, AVO, OGI, Method 21 of appendix A-7 to this part).
(ii) For each defect or emissions detected during inspections
required by Sec. 60.5416c(a)(1) and (2), or (b) you must record the
location of the defect or emissions; a description of the defect; the
maximum concentration reading obtained if using Method 21 of appendix
A-7 to this part; the indication of emissions detected by AVO if using
AVO; the date of detection; the date of each attempt to repair the
emissions or defect; the corrective action taken during each attempt to
repair the defect; and the date the repair to correct the defect or
emissions is completed.
(iii) If repair of the defect is delayed as described in Sec.
60.5416c(b)(6), you must record the reason for the delay and the date
you expect to complete the repair.
(iv) Parts of the closed vent system designated as unsafe to
inspect as described in Sec. 60.5416c(b)(7) or difficult to inspect as
described in Sec. 60.5416c(b)(8), the reason for the designation, and
written plan for inspection of that part of the closed vent system.
(8) A record of each cover inspection required under Sec.
60.5416c(a)(3) for your centrifugal compressor, reciprocating
compressor, or storage vessel as required in paragraphs (c)(8)(i)
through (iv) of this section.
(i) A record of each cover inspection. You must include an
identification number for each cover (or other unique identification
description selected by you), the date of the inspection, and the
method used to conduct the inspection (i.e., AVO, OGI, Method 21 of
appendix A-7 to this part).
(ii) For each defect detected during the inspection you must record
the location of the defect; a description of the defect; the date of
detection; the maximum concentration reading obtained if using Method
21 of appendix A-7 to this part; the indication of emissions detected
by AVO if using AVO; the date of each attempt to repair the defect; the
corrective action taken during each attempt to repair the defect; and
the date the repair to correct the defect is completed.
(iii) If repair of the defect is delayed as described in Sec.
60.5416c(b)(5), you must record the reason for the delay and the date
you expect to complete the repair.
(iv) Parts of the cover designated as unsafe to inspect as
described in Sec. 60.5416c(b)(7) or difficult to inspect as described
in Sec. 60.5416c(b)(8), the reason for the designation, and written
plan for inspection of that part of the cover.
(9) For each bypass subject to the bypass requirements of Sec.
60.5416c(a)(4), you must maintain a record of the following, as
applicable: readings from the flow indicator; each inspection of the
seal or closure mechanism; the date and time of each instance the key
is checked out; date and time of each instance the alarm is sounded.
(10) Records for each control device used to comply with the
emission reduction standard in Sec. 60.5391c(b) for associated gas
wells, Sec. 60.5392c(a)(4) for centrifugal compressor designated
facilities, Sec. 60.5393c(d)(2) for reciprocating compressor
designated facilities, Sec. 60.5394c(b)(3) for your process controller
designated facility in Alaska, Sec. 60.5395c(b)(3) for your pump
designated facility, Sec. 60.5396c(a)(2) for your storage vessel
designated facility, Sec. 60.5390c(g) for well designated facility gas
well liquids unloading, or Sec. 60.5400c(f) or 60.5401c(e) for your
process equipment designated facility, as required in paragraphs
(c)(10)(i) through (viii) of this section. If you use
[[Page 18130]]
an enclosed combustion device or flare using an alternative test method
approved under Sec. 60.5412c(d), keep records of the information in
paragraph (c)(10)(ix) of this section, in lieu of the records required
by paragraphs (c)(10)(i) through (iv) and (vi) through (viii) of this
section.
(i) For a control device tested under Sec. 60.5413c(d) which meets
the criteria in Sec. 60.5413c(d)(11) and (e), keep records of the
information in paragraphs (c)(10)(i)(A) through (E) of this section, in
addition to the records in paragraphs (c)(10)(ii) through (ix) of this
section, as applicable.
(A) Serial number of purchased device and copy of purchase order.
(B) Location of the designated facility associated with the control
device in latitude and longitude coordinates in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using the North
American Datum of 1983.
(C) Minimum and maximum inlet gas flow rate specified by the
manufacturer.
(D) Records of the maintenance and repair log as specified in Sec.
60.5413c(e)(4), for all inspection, repair, and maintenance activities
for each control device failing the visible emissions test.
(E) Records of the manufacturer's written operating instructions,
procedures, and maintenance schedule to ensure good air pollution
control practices for minimizing emissions.
(ii) For all control devices, keep records of the information in
paragraphs (c)(10)(ii)(A) through (G) of this section, as applicable.
(A) Make, model, and date of installation of the control device,
and identification of the designated facility controlled by the device.
(B) Records of deviations in accordance with Sec. 60.5417c(g)(1)
through (7), including a description of the deviation, the date and
time the deviation began, the duration of the deviation, and the cause
of the deviation.
(C) The monitoring plan required by Sec. 60.5417c(c)(2).
(D) Make and model number of each continuous parameter monitoring
system.
(E) Records of minimum and maximum operating parameter values,
continuous parameter monitoring system data (including records that the
pilot or combustion flame is present at all times), calculated averages
of continuous parameter monitoring system data, and results of all
compliance calculations.
(F) Records of continuous parameter monitoring system equipment
performance checks, system accuracy audits, performance evaluations, or
other audit procedures and results of all inspections specified in the
monitoring plan in accordance with Sec. 60.5417c(c)(2). Records of
calibration gas cylinders, if applicable.
(G) Periods of monitoring system malfunctions, repairs associated
with monitoring system malfunctions and required monitoring system
quality assurance or quality control activities. Records of repairs on
the monitoring system.
(iii) For each carbon adsorption system, records of the schedule
for carbon replacement as determined by the design analysis
requirements of Sec. 60.5413c(c)(2) and (3) and records of each carbon
replacement as specified in Sec. Sec. 60.5412c(c)(1) and
60.5415c(e)(1)(viii).
(iv) For enclosed combustion devices and flares, records of visible
emissions observations as specified in paragraph (c)(10)(iv)(A) or (B)
of this section.
(A) Records of observations with Method 22 of appendix A-7 to this
part, including observations required following return to operation
from a maintenance or repair activity, which include: company,
location, company representative (name of the person performing the
observation), sky conditions, process unit (type of control device),
clock start time, observation period duration (in minutes and seconds),
accumulated emission time (in minutes and seconds), and clock end time.
You may create your own form including the above information or use
Figure 22-1 in Method 22 of appendix A-7 to this part.
(B) If you monitor visible emissions with a video surveillance
camera, location of the camera and distance to emission source, records
of the video surveillance output, and documentation that an operator
looked at the feed daily, including the date and start time of
observation, the length of observation, and length of time visible
emissions were present.
(v) For enclosed combustion devices and flares, video of the OGI
inspection conducted in accordance with Sec. 60.5415c(e)(1)(x).
Records documenting each enclosed combustion device and flare was
visibly observed during each inspection conducted under Sec. 60.5397c
using AVO in accordance with Sec. 60.5415c(e)(1)(x).
(vi) For enclosed combustion devices and flares, an indication of
whether the enclosed combustion device or flare receives inert gases or
other vent streams which may lower the NHV of the combined stream, and
if so, a description of the operating scenario(s) which may lower the
NHV of the combined stream through the introduction of inert gases or
other vent gas streams. Records of each demonstration of the NHV of the
inlet gas to the enclosed combustion device or flare conducted in
accordance with Sec. 60.5417c(d)(8)(iii), including the sampling
approach used (continuous NHV, twice daily sampling, alternative
method), the date, time and results of each analysis, and, if shorter
sampling times were used with twice daily sampling, the collection
time(s) used and the reason for not obtaining a full one hour sample.
For each re-evaluation of the NHV of the inlet gas, records of process
changes and explanation of the conditions that led to the need to re-
evaluation the NHV of the inlet gas. For each demonstration where the
enclosed combustion device or flare received inert gases, record the
highest percentage of inert gases that can be sent to the enclosed
combustion device or flare and the highest percent of inert gases sent
to the enclosed combustion device or flare during the NHV
demonstration. Records of periodic sampling conducted under Sec.
60.5417c(d)(8)(iii)(G).
(vii) For enclosed combustion devices and flares, if you use a
backpressure regulator valve, the make and model of the valve, date of
installation, and record of inlet flow rating. Maintain records of the
engineering evaluation and manufacturer specifications that identify
the pressure set point corresponding to the minimum inlet gas flow
rate, the annual confirmation that the backpressure regulator valve set
point is correct and consistent with the engineering evaluation and
manufacturer specifications, and the annual confirmation that the
backpressure regulator valve fully closes when not in open position.
(viii) For enclosed combustion devices and flares, records of each
demonstration required under Sec. 60.5417c(d)(8)(iv).
(ix) If you use an enclosed combustion device or flare using an
alternative test method approved under Sec. 60.5412c(d), keep records
of the information in paragraphs (c)(10)(ix)(A) through (H) of this
section, in lieu of the records required by paragraphs (c)(10)(i)
through (iv) and (vi) through (viii) of this section.
(A) An identification of the alternative test method used.
(B) Data recorded at the intervals required by the alternative test
method.
(C) Monitoring plan required by Sec. 60.5417c(i)(2).
(D) Quality assurance and quality control activities conducted in
[[Page 18131]]
accordance with the alternative test method.
(E) If required by Sec. 60.5412c(d)(4) to conduct visible
emissions observations, records required by paragraph (c)(10)(iv) of
this section.
(F) If required by Sec. 60.5412c(d)(5) to conduct pilot or
combustion flame monitoring, record indicating the presence of a pilot
or combustion flame and periods when the pilot or combustion flame is
absent.
(G) For each instance where there is a deviation of the control
device in accordance with Sec. 60.5417c(i)(6)(i) through (v), the date
and time the deviation began, the duration of the deviation in hours,
and cause of the deviation.
(H) Any additional information required to be recorded as specified
by the Administrator as part of the alternative test method approval
under Sec. 60.5412c(d).
(11) For each closed vent system routing to a control device or
process, the records of the assessment conducted according to Sec.
60.5411c(c):
(i) A copy of the assessment conducted according to Sec.
60.5411c(c)(1); and
(ii) A copy of the certification according to Sec.
60.5411c(c)(1)(i) and (ii).
(12) A copy of each performance test submitted under paragraph
(b)(11) or (12) of this section.
(13) For the fugitive emissions components designated facility,
maintain the records identified in paragraphs (c)(13)(i) through (vii)
of this section.
(i) The date of the startup of production or the date of the first
day of production after modification for the fugitive emissions
components designated facility at a well site and the date of startup
or the date of modification for the fugitive emissions components
designated facility at a compressor station.
(ii) For the fugitive emissions components designated facility at a
well site, you must maintain records specifying what type of well site
it is (i.e., single wellhead only well site, small wellsite, multi-
wellhead only well site, or a well site with major production and
processing equipment).
(iii) For the fugitive emissions components designated facility at
a well site where you complete the removal of all major production and
processing equipment such that the well site contains only one or more
wellheads, record the date the well site completes the removal of all
major production and processing equipment from the well site, and, if
the well site is still producing, record the well ID or separate tank
battery ID receiving the production from the well site. If major
production and processing equipment is subsequently added back to the
well site, record the date that the first piece of major production and
processing equipment is added back to the well site.
(iv) The fugitive emissions monitoring plan as required in Sec.
60.5397c(b) through (d).
(v) The records of each monitoring survey as specified in
paragraphs (c)(13)(v)(A) through (I) of this section.
(A) Date of the survey.
(B) Beginning and end time of the survey.
(C) Name of operator(s), training, and experience of the
operator(s) performing the survey.
(D) Monitoring instrument or method used.
(E) Fugitive emissions component identification when Method 21 of
appendix A-7 to this part is used to perform the monitoring survey.
(F) Ambient temperature, sky conditions, and maximum wind speed at
the time of the survey. For compressor stations, operating mode of each
compressor (i.e., operating, standby pressurized, and not operating-
depressurized modes) at the station at the time of the survey.
(G) Any deviations from the monitoring plan or a statement that
there were no deviations from the monitoring plan.
(H) Records of calibrations for the instrument used during the
monitoring survey.
(I) Documentation of each fugitive emission detected during the
monitoring survey, including the information specified in paragraphs
(c)(13)(v)(I)(1) through (9) of this section.
(1) Location of each fugitive emission identified.
(2) Type of fugitive emissions component, including designation as
difficult-to-monitor or unsafe-to-monitor, if applicable.
(3) If Method 21 of appendix A-7 to this part is used for
detection, record the component ID and instrument reading.
(4) For each repair that cannot be made during the monitoring
survey when the fugitive emissions are initially found, a digital
photograph or video must be taken of that component or the component
must be tagged for identification purposes. The digital photograph must
include the date that the photograph was taken and must clearly
identify the component by location within the site (e.g., the latitude
and longitude of the component or by other descriptive landmarks
visible in the picture). The digital photograph or identification
(e.g., tag) may be removed after the repair is completed, including
verification of repair with the resurvey.
(5) The date of first attempt at repair of the fugitive emissions
component(s).
(6) The date of successful repair of the fugitive emissions
component, including the resurvey to verify repair and instrument used
for the resurvey.
(7) Identification of each fugitive emission component placed on
delay of repair and explanation for each delay of repair.
(8) For each fugitive emission component placed on delay of repair
for reason of replacement component unavailability, the operator must
document: the date the component was added to the delay of repair list,
the date the replacement fugitive component or part thereof was
ordered, the anticipated component delivery date (including any
estimated shipment or delivery date provided by the vendor), and the
actual arrival date of the component.
(9) Date of planned shutdowns that occur while there are any
components that have been placed on delay of repair.
(vi) For well closure activities, you must maintain the information
specified in paragraphs (c)(13)(vi)(A) through (G) of this section.
(A) The well closure plan developed in accordance with Sec.
60.5397c(l) and the date the plan was submitted.
(B) The notification of the intent to close the well site and the
date the notification was submitted.
(C) The date of the cessation of production from all wells at the
well site.
(D) The date you began well closure activities at the well site.
(E) Each status report for the well closure activities reported in
paragraph (b)(8)(iv)(A) of this section.
(F) Each OGI survey reported in paragraph (b)(8)(iv)(B) of this
section including the date, the monitoring instrument used, and the
results of the survey or resurvey.
(G) The final OGI survey video demonstrating the closure of all
wells at the site. The video must include the date that the video was
taken and must identify the well site location by latitude and
longitude.
(vii) If you comply with an alternative GHG standard under Sec.
60.5398c, in lieu of the information specified in paragraphs
(c)(13)(iv) and (v) of this section, you must maintain the records
specified in Sec. 60.5424c.
(14) For each pump designated facility, you must maintain the
records identified in paragraphs (c)(14)(i) through (ix) of this
section, as applicable.
[[Page 18132]]
(i) Identification of each pump that is driven by natural gas and
that is in operation 90 days or more per calendar year.
(ii) If you are complying with Sec. 60.5395c(a) or (b)(1) by
routing pump vapors to a process through a closed vent system,
identification of all the natural gas-driven pumps in the pump
designated facility for which you collect and route vapors to a process
through a closed vent system and the records specified in paragraphs
(c)(7), (9), and (11) of this section. If you comply with an
alternative GHG and VOC standard under Sec. 60.5398c, in lieu of the
information specified in paragraph (c)(7) of this section, you must
provide the information specified in Sec. 60.5424c.
(iii) If you are complying with Sec. 60.5395c(b)(1) by routing
pump vapors to control device achieving a 95.0 percent reduction in
methane emissions, you must keep the records specified in paragraphs
(c)(7) and (9) through (12) of this section. If you comply with an
alternative GHG and VOC standard under Sec. 60.5398c, in lieu of the
information specified in paragraph (c)(7), you must provide the
information specified in Sec. 60.5424c.
(iv) If you are complying with Sec. 60.5395c(b)(3) by routing pump
vapors to a control device achieving less than a 95.0 percent reduction
in methane emissions, you must maintain records of the certification
that there is a control device on site but it does not achieve a 95.0
percent emissions reduction and a record of the design evaluation or
manufacturer's specifications which indicate the percentage reduction
the control device is designed to achieve.
(v) If you have less than three natural gas-driven diaphragm pumps
in the pump designated facility, and you do not have a vapor recovery
unit or control device installed on site by the compliance date, you
must retain a record of your certification required under Sec.
60.5395c(b)(4), certifying that there is no vapor recovery unit or
control device on site. If you subsequently install a control device or
vapor recovery unit, you must maintain the records required under
paragraphs (c)(14)(ii) and (iii) or (iv) of this section, as
applicable.
(vi) If you determine, through an engineering assessment, that it
is technically infeasible to route the pump designated facility
emissions to a process or control device, you must retain records of
your demonstration and certification that it is technically infeasible
as required under Sec. 60.5395c(b)(7).
(vii) If the pump is routed to a process or control device that is
subsequently removed from the location or is no longer available such
that there is no option to route to a process or control device, you
are required to retain records of this change and the records required
under paragraph (c)(14)(vi) of this section.
(viii) Records of each change in compliance method, including
identification of each natural gas-driven pump which changes its method
of compliance, the new method of compliance, and the date of the change
in compliance method.
(ix) Records of each deviation, the date and time the deviation
began, the duration of the deviation, and a description of the
deviation.
(d) Electronic reporting. If you are required to submit
notifications or reports following the procedure specified in this
paragraph (d), you must submit notifications or reports to the EPA via
CEDRI, which can be accessed through the EPA's Central Data Exchange
(CDX) (https://cdx.epa.gov/). The EPA will make all the information
submitted through CEDRI available to the public without further notice
to you. Do not use CEDRI to submit information you claim as CBI.
Although we do not expect persons to assert a claim of CBI, if you wish
to assert a CBI claim for some of the information in the report or
notification, you must submit a complete file in the format specified
in this subpart, including information claimed to be CBI, to the EPA
following the procedures in paragraphs (d)(1) and (2) of this section.
Clearly mark the part or all of the information that you claim to be
CBI. Information not marked as CBI may be authorized for public release
without prior notice. Information marked as CBI will not be disclosed
except in accordance with procedures set forth in 40 CFR part 2. All
CBI claims must be asserted at the time of submission. Anything
submitted using CEDRI cannot later be claimed CBI. Furthermore, under
CAA section 114(c), emissions data is not entitled to confidential
treatment, and the EPA is required to make emissions data available to
the public. Thus, emissions data will not be protected as CBI and will
be made publicly available. You must submit the same file submitted to
the CBI office with the CBI omitted to the EPA via the EPA's CDX as
described in this paragraph (d).
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[FR Doc. 2026-06808 Filed 4-8-26; 8:45 am]
BILLING CODE 6560-50-P