[Federal Register Volume 87, Number 233 (Tuesday, December 6, 2022)]
[Proposed Rules]
[Pages 74702-74847]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2022-24675]
[[Page 74701]]
Vol. 87
Tuesday,
No. 233
December 6, 2022
Part II
Environmental Protection Agency
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40 CFR Part 60
Standards of Performance for New, Reconstructed, and Modified Sources
and Emissions Guidelines for Existing Sources: Oil and Natural Gas
Sector Climate Review; Proposed Rule
Federal Register / Vol. 87, No. 233 / Tuesday, December 6, 2022 /
Proposed Rules
[[Page 74702]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 60
[EPA-HQ-OAR-2021-0317; FRL-8510-04-OAR]
RIN 2060-AV16
Standards of Performance for New, Reconstructed, and Modified
Sources and Emissions Guidelines for Existing Sources: Oil and Natural
Gas Sector Climate Review
AGENCY: Environmental Protection Agency (EPA).
ACTION: Supplemental notice of proposed rulemaking.
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SUMMARY: The EPA is issuing this supplemental proposal to update,
strengthen, and expand the standards proposed on November 15, 2021
(November 2021 proposal), which are intended to significantly reduce
emissions of greenhouse gases (GHGs) and other harmful air pollutants
from the Crude Oil and Natural Gas source category. First, the EPA
proposes standards for certain sources that were not addressed in the
November 2021 proposal. Second, the EPA proposes revisions that
strengthen standards for sources of leaks, provide greater flexibility
to use innovative advanced detection methods, and establish a super
emitter response program. Third, the EPA proposes to modify and refine
certain elements of the proposed standards in response to information
submitted in public comments on the November 2021 proposal. Finally,
the EPA proposes details of the timelines and other implementation
requirements that apply to states to limit methane pollution from
existing designated facilities in the source category under the Clean
Air Act (CAA).
DATES:
Comments.
Comments must be received on or before February 13, 2023. Under the
Paperwork Reduction Act (PRA), OMB is required to make a decision
concerning the collections of information contained in the proposed
rule between 30 and 60 days after publication and submission to OMB. A
comment to OMB is best assured of consideration if the Office of
Management and Budget (OMB) receives it on or before January 5, 2023.
Public hearing. The EPA will hold a virtual public hearing on
January 10, 2023, and January 11, 2023. See SUPPLEMENTARY INFORMATION
for information on the hearing.
ADDRESSES: You may send comments, identified by Docket ID No. EPA-HQ-
OAR-2021-0317 by any of the following methods:
Federal eRulemaking Portal: https://www.regulations.gov/
(our preferred method). Follow the online instructions for submitting
comments.
Email: [email protected]. Include Docket ID No. EPA-
HQ-OAR-2021-0317 in the subject line of the message.
Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2021-0317.
Mail: U.S. Environmental Protection Agency, EPA Docket
Center, Docket ID No. EPA-HQ-OAR-2021-0317, Mail Code 28221T, 1200
Pennsylvania Avenue NW, Washington, DC 20460.
Hand/Courier Delivery: EPA Docket Center, WJC West
Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004.
The Docket Center's hours of operation are 8:30 a.m.-4:30 p.m., Monday-
Friday (except Federal holidays).
Instructions. All submissions received must include the Docket ID
No. for this rulemaking. Comments received may be posted without change
to https://www.regulations.gov/, including any personal information
provided. For detailed instructions on sending comments and additional
information on the rulemaking process, see the ``Public Participation''
heading of the SUPPLEMENTARY INFORMATION section of this document. For
further information on EPA Docket Center services and the current
status, please visit us online at https://www.epa.gov/dockets.
FOR FURTHER INFORMATION CONTACT: For questions about this proposed
action, contact Ms. Karen Marsh, Sector Policies and Programs Division
(E143-05), Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina
27711; telephone number: (919) 541-1065; fax number: (919) 541-0516;
and email address: [email protected] or Ms. Amy Hambrick, Sector
Policies and Programs Division (E143-05), Office of Air Quality
Planning and Standards, Environmental Protection Agency, Research
Triangle Park, North Carolina 27711; telephone number: (919) 541-0964;
fax number: (919) 541-0516; email address: [email protected].
SUPPLEMENTARY INFORMATION:
Participation in virtual public hearing. The public hearing will be
held via virtual platform on January 10, 2023, and January 11, 2023,
and will convene at 10:00 a.m. Eastern Time (ET) and conclude at 8:00
p.m. ET each day. On each hearing day, the EPA may close a session 15
minutes after the last pre-registered speaker has testified if there
are no additional speakers. The EPA will announce further details at
https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry. If the EPA receives a high volume of registrations for the
public hearing, we may continue the public hearing on January 12, 2023.
The EPA does not intend to publish a document in the Federal Register
announcing the potential addition of a third day for the public hearing
or any other updates to the information on the hearing described in
this document. Please monitor https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry for any updates to the
information described in this document, including information about the
public hearing. For information or questions about the public hearing,
please contact the public hearing team at (888) 372-8699 or by email at
[email protected].
The EPA will begin pre-registering speakers for the hearing no
later than 1 business day following the publication of this document in
the Federal Register. The EPA will accept registrations on an
individual basis. To register to speak at the virtual hearing, follow
the directions at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry or contact the public hearing team at (888)
372-8699 or by email at [email protected]. The last day to pre-
register to speak at the hearing will be January 5, 2023. Prior to the
hearing, the EPA will post a general agenda that will list pre-
registered speakers in approximate order at: https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry.
The EPA will make every effort to follow the schedule as closely as
possible on the day of the hearing; however, please plan for the
hearings to run either ahead of schedule or behind schedule.
Each commenter will have 4 minutes to provide oral testimony. The
EPA encourages commenters to provide the EPA with a copy of their oral
testimony by submitting the text of your oral testimony as written
comments to the rulemaking docket.
The EPA may ask clarifying questions during the oral presentations
but will not respond to the presentations at that time. Written
statements and supporting information submitted during the comment
period will be considered with the same weight as oral testimony and
supporting information presented at the public hearing.
If you require the services of an interpreter or a special
accommodation
[[Page 74703]]
such as audio description, please pre-register for the hearing with the
public hearing team and describe your needs by December 13, 2022. The
EPA may not be able to arrange accommodations without advanced notice.
Docket. The EPA has established a docket for this rulemaking under
Docket ID No. EPA-HQ-OAR-2021-0317. All documents in the docket are
listed in https://www.regulations.gov/. 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. With the exception of such material, publicly available docket
materials are available electronically in https://www.regulations.gov/.
Instructions. Direct your comments to Docket ID No. EPA-HQ-OAR-
2021-0317. The EPA's policy is that all comments received will be
included in the public docket without change and may be made available
online at https://www.regulations.gov/, including any personal
information provided, unless the comment includes information claimed
to be CBI or other information whose disclosure is restricted by
statute. Do not submit electronically to https://www.regulations.gov/
any information that you consider to be CBI or other information whose
disclosure is restricted by statute. This type of information should be
submitted as discussed below.
The EPA may publish any comment received to its public docket.
Multimedia submissions (audio, video, etc.) must be accompanied by a
written comment. The written comment is considered the official comment
and should include discussion of all points you wish to make. The EPA
will generally not consider comments or comment contents located
outside of the primary submission (i.e., on the Web, cloud, or other
file sharing system). For additional submission methods, the full EPA
public comment policy, information about CBI or multimedia submissions,
and general guidance on making effective comments, please visit https://www.epa.gov/dockets/commenting-epa-dockets.
The https://www.regulations.gov/ website allows you to submit your
comment anonymously, which means the EPA will not know your identity or
contact information unless you provide it in the body of your comment.
If you send an email comment directly to the EPA without going through
https://www.regulations.gov/, your email address will be automatically
captured and included as part of the comment that is placed in the
public docket and made available on the internet. If you submit an
electronic comment, the EPA recommends that you include your name and
other contact information in the body of your comment and with any
digital storage media you submit. If the EPA cannot read your comment
due to technical difficulties and cannot contact you for clarification,
the EPA may not be able to consider your comment. Electronic files
should not include special characters or any form of encryption and be
free of any defects or viruses. For additional information about the
EPA's public docket, visit the EPA Docket Center homepage at https://www.epa.gov/dockets.
Submitting CBI. Do not submit information containing CBI to the EPA
through https://www.regulations.gov/. Clearly mark the part or all of
the information that you claim to be CBI. For CBI information on any
digital storage media that you mail to the EPA, note the docket ID,
mark the outside of the digital storage media as CBI and identify
electronically within the digital storage media the specific
information that is claimed as CBI. In addition to one complete version
of the comments that includes information claimed as CBI, you must
submit a copy of the comments that does not contain the information
claimed as CBI directly to the public docket through the procedures
outlined in the Instructions section of this document. If you submit
any digital storage media that does not contain CBI, mark the outside
of the digital storage media clearly that it does not contain CBI and
note the docket ID. Information not marked as CBI will be included in
the public docket and the EPA's electronic public docket without prior
notice. Information marked as CBI will not be disclosed except in
accordance with procedures set forth in 40 Code of Federal Regulations
(CFR) part 2.
Our preferred method to receive CBI is for it to be transmitted
electronically using email attachments, File Transfer Protocol (FTP),
or other online file sharing services (e.g., Dropbox, OneDrive, Google
Drive). Electronic submissions must be transmitted directly to the
OAQPS CBI Office at the email address [email protected], and as
described in the preceding paragraph, should include clear CBI markings
and note the docket ID. If assistance is needed with submitting large
electronic files that exceed the file size limit for email attachments,
and if you do not have your own file sharing service, please email
[email protected] to request a file transfer link. If sending CBI
information through the postal service, please send it to the following
address: OAQPS Document Control Officer (C404-02), OAQPS, U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina
27711, Attention Docket ID No. EPA-HQ-OAR-2021-0317. The mailed CBI
material should be double wrapped and clearly marked. Any CBI markings
should not show through the outer envelope.
Preamble acronyms and abbreviations. We use multiple acronyms and
terms in this preamble. While this list may not be exhaustive, to ease
the reading of this preamble and for reference purposes, the EPA
defines the following terms and acronyms here:
AMEL alternate means of emissions limitation
ANSI American National Standards Institute
APA Administrative Procedures Act
API American Petroleum Institute
ASME American Society of Mechanical Engineers
ASTM American Society for Testing and Materials
AVO audio, visual, and olfactory
AWP alternative work practice
BMP best management practices
boe barrels of oil equivalents
BSER best system of emission reduction
Btu/scf British thermal unit per standard cubic foot
[deg]C degrees Centigrade
CAA Clean Air Act
CBI Confidential Business Information
CCR Code of Colorado Regulations
CDX EPA's Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CFR Code of Federal Regulations
CH4 methane
CO carbon monoxide
CO2 carbon dioxide
CO2 Eq. carbon dioxide equivalent
CRA Congressional Review Act
CVS closed vent systems
CWA Clean Water Act
D.C. Circuit U.S. Court of Appeals for the District of Columbia
Circuit
DOE Department of Energy
EAV equivalent annual value
EDF Environmental Defense Fund
EG emission guidelines
EIA U.S. Energy Information Administration
EJ environmental justice
E.O. Executive Order
EPA Environmental Protection Agency
ESD emergency shutdown devices
[deg]F degrees Fahrenheit
FEAST Fugitive Emissions Abatement Simulation Toolkit
FR Federal Register
FRFA final regulatory flexibility analysis
g/hr grams per hour
GHG greenhouse gas
GHGI Inventory of U.S. Greenhouse Gas Emissions and Sinks
GHGRP Greenhouse Gas Reporting Program
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HAP hazardous air pollutant(s)
ICR information collection request
IRFA initial regulatory flexibility analysis
IWG Interagency Working Group on the Social Cost of Greenhouse Gases
kg kilograms
low-e low emission
LDAR leak detection and repair
Mcf thousand cubic feet
METEC Methane Emissions Technology Evaluation Center
MW megawatt
NAAQS National Ambient Air Quality Standards
NAICS North American Industry Classification System
NDE no detectable emissions
NESHAP National Emissions Standards for Hazardous Air Pollutants
NGO non-governmental organization
NHV net heating value
NOX nitrogen oxides
NSPS new source performance standards
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality Planning and Standards
OGI optical gas imaging
OMB Office of Management and Budget
PM2.5 particulate matter with a diameter of 2.5
micrometers or less
ppm parts per million
PRA Paperwork Reduction Act
PTE potential to emit
PV present value
REC reduced emissions completion
RFA Regulatory Flexibility Act
RIA regulatory impact analysis
RULOF remaining useful life and other factors
SBAR Small Business Advocacy Review
SC-CH4 social cost of methane
SC-GHG social cost of greenhouse gases
scf standard cubic feet
scfh standard cubic feet per hour
scfm standard cubic feet per minute
SIP state implementation plan
SO2 sulfur dioxide
SPeCS State Planning Electronic Collaborative System
tpy tons per year
the court U.S. Court of Appeals for the District of Columbia Circuit
TAR Tribal Authority Rule
TIP tribal implementation plan
TSD technical support document
UMRA Unfunded Mandates Reform Act
U.S. United States
VCS Voluntary Consensus Standards
VOC volatile organic compounds
VRU vapor recovery unit
Organization of this document. The information in this preamble is
organized as follows:
I. Executive Summary
A. Purpose of the Regulatory Action
B. Summary of the Major Provisions of This Regulatory Action
C. Costs and Benefits
II. General Information
A. Does this action apply to me?
B. How do I obtain a copy of this document, background
information, other related information?
III. Purpose of This Regulatory Action
A. What is the purpose of this supplemental proposal?
B. What date defines a new, modified, or reconstructed source
for purposes of the proposed NSPS OOOOb?
C. What date defines an existing source for purposes of the
proposed EG OOOOc?
D. How will the proposed EG OOOOc impact sources already subject
to NSPS KKK, NSPS OOOO, or NSPS OOOOa?
E. How does the EPA consider costs in this supplemental
proposal?
F. Legal Basis for Rulemaking Scope
G. Inflation Reduction Act
IV. Summary and Rationale for Changes to the Proposed NSPS OOOOb and
EG OOOOc
A. Fugitive Emissions From Well Sites, Centralized Production
Facilities, and Compressor Stations
B. Advanced Methane Detection Technologies
C. Super-Emitter Response Program
D. Pneumatic Controllers
E. Pneumatic Pumps
F. Wells and Associated Operations
G. Centrifugal Compressors
H. Combustion Control Devices
I. Reciprocating Compressors
J. Storage Vessels
K. Covers and Closed Vent Systems
L. Equipment Leaks at Natural Gas Processing Plants
M. Sweetening Units
N. Recordkeeping and Reporting
V. Supplemental Proposal for State, Tribal, and Federal Plan
Development for Existing Sources
A. Overview
B. Establishing Standards of Performance in State Plans
C. Components of State Plan Submission
D. Timing of State Plan Submissions and Compliance Times
VI. Use of Optical Gas Imaging in Leak Detection (Appendix K)
A. Overview of the November 2021 Proposal
B. Significant Changes Since Proposal
C. Summary of Proposed Requirements
VII. Impacts of This Proposed Rule
A. What are the air impacts?
B. What are the energy impacts?
C. What are the compliance costs?
D. What are the economic and employment impacts?
E. What are the benefits of the proposed standards?
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act (NTTAA)
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
I. Executive Summary
A. Purpose of the Regulatory Action
On November 15, 2021, the EPA published a proposed rule (November
2021 proposal) that was intended to mitigate climate-destabilizing
pollution and protect human health by reducing greenhouse gas (GHG) and
VOC emissions from the Oil and Natural Gas Industry,\1\ specifically
the Crude Oil and Natural Gas source category.\2\ A wide range of
stakeholders, as well as state and tribal governments, submitted public
comments on the November 2021 proposal. Over 470,000 public comments
were submitted. Many commenters representing diverse perspectives
expressed general support for the proposal and requested that the EPA
further strengthen the proposed standards and make them more
comprehensive. Other commenters highlighted implementation or cost
concerns related to elements of the November 2021 proposal or provided
specific data and information that the EPA was able to use to refine or
revise several of the standards included in the November 2021 proposal.
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\1\ The EPA characterizes the Oil and Natural Gas Industry
operations as being generally composed of four segments: (1)
Extraction and production of crude oil and natural gas (``oil and
natural gas production''), (2) natural gas processing, (3) natural
gas transmission and storage, and (4) natural gas distribution.
\2\ The EPA defines the Crude Oil and Natural Gas source
category to mean: (1) Crude oil production, which includes the well
and extends to the point of custody transfer to the crude oil
transmission pipeline or any other forms of transportation; and (2)
natural gas production, processing, transmission, and storage, which
include the well and extend to, but do not include, the local
distribution company custody transfer station, commonly referred to
as the ``city-gate.''
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In the November 2021 proposal, the EPA proposed new standards and
emission guidelines under CAA section 111 which would be included in 40
CFR part 60 at subpart OOOOb (NSPS OOOOb) and subpart OOOOc (EG OOOOc).
The purpose of this supplemental proposed rulemaking is to strengthen,
update, and expand the proposed standards for certain emissions
sources, including: (1) To reduce emissions from the source category
more comprehensively by adding proposed standards for certain sources
that were not addressed in the November 2021 proposal, revising the
[[Page 74705]]
proposed requirements for fugitive emissions monitoring and repair, and
establishing a super-emitter response program; (2) to encourage the
deployment of innovative technologies and techniques for detecting and
reducing methane emissions by providing additional options for the use
of advanced monitoring; (3) to modify and refine certain elements of
the proposed standards in response to concerns and information
identified in an initial review of public comments on the November 2021
proposal; and (4) to provide additional information not included in the
November 2021 proposal for public comment, such as the content for the
new subparts that reflects the proposed standards and emission
guidelines, and details of the timelines and other requirements that
apply to states as they develop state plans to implement the emission
guidelines.
In the November 2021 proposal, the EPA performed a comprehensive
analysis of the available data from emission sources in the Crude Oil
and Natural Gas source category and the latest available information on
control measures and techniques to identify achievable, cost-effective
measures to significantly reduce methane and VOC emissions, consistent
with the requirements of section 111 of the CAA.\3\ This supplemental
proposal builds on that analysis to apply additional information and
data provided to the Agency since the November 2021 proposal to
identify areas to further strengthen standards, such as measures to
address large emissions events, commonly referred to as super-emitters.
If finalized and implemented, the proposed actions in this rulemaking,
as detailed in the November 2021 proposal and this supplemental
proposal, would lead to significant and cost-effective reductions in
climate and health-harming pollution and encourage the continued
development and deployment of innovative technologies to further reduce
this pollution in the Crude Oil and Natural Gas source category.
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\3\ 42 U.S.C. 7411.
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This supplemental proposal comprises distinct actions:
Update, strengthen, and/or expand on the standards
proposed in November 2021 under CAA section 111(b) for methane and VOC
emissions from new, modified, and reconstructed facilities that
commenced construction, reconstruction, or modification after November
15, 2021,
Update, strengthen, and/or expand the presumptive
standards proposed in November 2021 as part of the CAA section 111(d)
emission guidelines for methane emissions from existing designated
facilities that commenced construction, reconstruction, or modification
on or before November 15, 2021,
And establish the implementation requirements for states
to limit methane pollution from existing designated facilities in the
source category under CAA section 111(d).
The Oil and Natural Gas Industry is the United States' largest
industrial emitter of methane, a highly potent GHG.\4\ Methane and VOC
emissions from the Crude Oil and Natural Gas source category result
from a variety of industry operations across the supply chain. As
natural gas moves through the necessarily interconnected system of
exploration, production, storage, processing, and transmission that
brings it from wellhead to commerce, emissions primarily result from
intentional venting, unintentional gas carry-through (e.g., vortexing
from separator drain, improper liquid level settings, liquid level
control valve on an upstream separator or scrubber not seating properly
at the end of an automated liquid dumping event, inefficient separation
of gas and liquid phases occurring upstream of tanks allowing some gas
carry-through), routine maintenance, unintentional fugitive emissions,
flaring, malfunctions, abnormal process conditions, and system upsets.
These emissions are associated with a range of specific equipment and
practices, including leaking valves, connectors, and other components
at well sites and compressor stations; leaks and vented emissions from
controlled storage vessels; releases from natural gas-driven pneumatic
pumps and controllers; liquids unloading at well sites; and venting or
under-performing flaring of associated gas from oil wells. Technical
innovations have produced a range of technologies and best practices to
monitor, eliminate or minimize these emissions, which in many cases
have the benefit of simultaneously reducing multiple pollutants and
recovering saleable product. These technologies and best practices have
been deployed by individual oil and natural gas companies, required by
state regulations, reflected in regulations issued by the EPA and other
Federal agencies, or utilized by various non-industry groups and
research teams.
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\4\ Emissions from EPA (2022) Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990-2020. U.S. Environmental Protection
Agency, EPA 430-R-22-003. https://www.epa.gov/ghgemissions/draft-inventory-us-greenhouse-gas-emissionsand-sinks-1990-2020.
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In developing this supplemental proposal, the EPA applied the
latest available information to refine or supplement the analyses
presented in the November 2021 proposal. This latest information
provided additional insights into lessons learned from states'
regulatory efforts, the emission reduction efforts of leading
companies, the continued development of new and developing
technologies, and peer-reviewed research from emission measurement
campaigns across the United States (U.S.). As stated in the November
2021 proposal, the EPA solicited comment on all aspects of the proposed
standards and stated its intent to issue a supplemental proposal that
revisited and refined certain provisions of that proposal in response
to information provided by the public. This supplemental proposal does
just that. For instance, the EPA sought input in the November 2021
proposal on multiple aspects of the proposed approach for fugitive
emissions monitoring at well sites, including the baseline emission
threshold and other criteria (such as the presence of specific types of
malfunction-prone equipment) that should be used to determine whether a
well site is required to undertake ongoing fugitive emissions
monitoring. (86 FR 63115; November 15, 2021). After considering the
comments and information received, this supplemental proposal includes
a revised approach for fugitive emissions monitoring at well sites
utilizing modeling to establish the proposed monitoring frequency and
detection method for individual sites based on the presence of specific
types of equipment. In contrast to the November 2021 proposal, this
supplemental proposal would establish an obligation for all well sites
to routinely monitor for fugitive emissions and repair leaks found--
ranging from a quarterly audio, visual, and olfactory (AVO) inspection
for single wellhead-only sites to quarterly optical gas imaging (OGI)
inspections for any site with significant production equipment. This
revised approach to addressing fugitive emissions from well sites also
would carry the monitoring requirements through the entire life of the
well site and would specify the requirements for ceasing monitoring
following well closures when production from the entire well site has
stopped. The EPA is seeking comments about labor requirements to
implement these monitoring requirements.
[[Page 74706]]
Super-emitter emissions events \5\ were another key area in the
November 2021 proposal for which the EPA solicited comment. (86 FR
63177; November 15, 2021). This supplemental proposal includes various
standards that, when implemented by an owner or operator, could reduce
or eliminate the occurrence of super-emitter emissions events, such as
the inclusion of specific compliance assurance measures to ensure that
flares are operating as designed with a continuously lit pilot. In
addition, this supplemental notice proposes a super-emitter response
program to trigger swift mitigation of super-emitter emissions events
when they are identified through credible information provided by
regulatory authorities or approved qualified third-party sources.
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\5\ In the November 2021 proposal, the EPA solicited comment on
the use of information collected by communities and others to
address large emissions events, which this supplemental proposal now
defines as ``super-emitter emissions events.''
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Content for the new subparts reflecting these proposed changes is
available in the docket for this action (Docket ID No. EPA-HQ-OAR-2021-
0317) and supplements the redline versions of NSPS OOOO and NSPS OOOOa
provided in the November 2021 proposal (Docket ID Nos. EPA-HQ-OAR-2021-
0317-0095 and EPA-HQ-OAR-2021-0317-0097). In addition, the EPA is
providing an updated regulatory impact analysis (RIA) that seeks to
account for the full impacts of these proposed actions.
Additionally, the EPA is seeking comment and information on the
proposed provisions for the use of advanced methane measurement
technologies for both periodic screening and continuous monitoring as
an alternative to OGI. The revised proposal includes a matrix that
provides various monitoring frequencies based on specific performance
criteria a technology would need to meet in order to be used for
periodic screening. In addition to this proposed matrix, this
supplemental proposal includes provisions for requesting the use of
alternative test method(s) that, where approved, could be used broadly
for deploying these alternative technologies. Further, the EPA is
proposing a framework for the use of continuous monitoring systems that
provide a mass emissions rate with site-specific action levels based on
changes in quarterly average emissions and on the detection of an acute
large emission spike or event on a shorter term. Diverse stakeholders
expressed strong interest in employing these new tools for methane
identification and quantification, particularly for super-emitters, and
in the EPA's creation of a regime to promote and accommodate their
development and use. This proposal provides an approach for fostering
those alternatives, which could provide a template for future
innovation-conducive regulatory standards. The EPA is also seeking
comment on the detection limits of all monitoring and inspection
requirements.
Throughout this action, unless noted otherwise, the EPA is
requesting comments on all aspects of the supplemental proposal to
enable the EPA to develop a final rule that, consistent with our
responsibilities under section 111 of the CAA, achieves the greatest
possible reductions in methane and VOC emissions while remaining
achievable, cost effective, and conducive to technological innovation.
Because this preamble includes comment solicitations/requests on
several topics and issues, we have prepared a separate memorandum that
presents these comment requests by section and topic as a guide to
assist commenters in preparing comments. This memorandum can be
obtained from the Docket for this action (see Docket ID No. EPA-HQ-OAR-
2021-0317). The title of the memorandum is ``Standards of Performance
for New, Reconstructed, and Modified Sources and Emissions Guidelines
for Existing Sources: Oil and Natural Gas Sector Climate Review--
Supplemental Proposed Rule Summary of Comment Solicitations.'' It is
not necessary to resubmit comments that were submitted for the November
2021 proposal.
B. Summary of the Major Provisions of the Regulatory Action
This supplemental proposal includes two distinct rulemaking actions
under the CAA. First, the EPA is proposing specific changes to
strengthen the proposed requirements under CAA section 111(b) for
methane and VOC emissions from sources that commenced construction,
modification, or reconstruction after November 15, 2021. These proposed
revisions to strengthen the November 15, 2021, proposed standards of
performance will be in a new subpart, NSPS OOOOb, and include proposed
standards for emission sources previously not regulated for this source
category.
Second, pursuant to CAA section 111(d), the EPA is proposing
specific revisions to strengthen the first nationwide emission
guideline (EG) for states to limit methane pollution from existing
designated facilities in the Crude Oil and Natural Gas source category.
The proposed revisions to strengthen the November 15, 2021, proposed
presumptive standards will be in a new subpart, EG OOOOc. The emissions
guidelines (EG) are designed to inform states in the development,
submittal, and implementation of state plans that are required to
establish standards of performance for GHGs (in the form of limitations
on methane) from their designated facilities in the Crude Oil and
Natural Gas source category.
As CAA section 111(a)(1) requires, the standards of performance
under section 111(b) and presumptive standards under section 111(d)
being proposed in this action reflect ``the degree of emission
limitation achievable through the application of the best system of
emission reduction (BSER) which (taking into account the cost of
achieving such reduction and any non-air quality health and
environmental impact and energy requirement) the Administrator
determines has been adequately demonstrated.'' \6\ In this proposed
supplemental rulemaking, we evaluated new data made available to the
EPA and information provided from public comments on the November 2021
proposal to update the analyses and evaluate whether revisions to the
proposed BSER should be considered. For any potential control measure
evaluated in this action, as in the November 2021 proposal, the EPA
evaluated the emission reductions achievable through these measures and
employed multiple approaches to evaluate the reasonableness of control
costs associated with the options under consideration. For example, in
evaluating controls for reducing VOC and methane emissions from new
sources, we considered a control measure's cost-effectiveness under
both a ``single pollutant cost-effectiveness'' approach and a
``multipollutant cost-effectiveness'' approach, to appropriately
reflect that the systems of emission reduction evaluated in this rule
typically achieve reductions in multiple pollutants simultaneously and
secure a multiplicity of climate and public health benefits. We also
[[Page 74707]]
compared: (1) The capital costs that would be incurred through
compliance with the proposed standards against the industry's current
level of capital expenditures and (2) the annualized costs against the
industry's estimated annual revenues. For a detailed discussion of the
EPA's consideration of this and other BSER statutory elements, please
see section III.E of this preamble, 86 FR 63133; November 15, 2021, and
86 FR 63153; November 15, 2021. Table 1 summarizes the applicability
dates for the four subparts that the EPA's November 2021 proposal
included.
---------------------------------------------------------------------------
\6\ The EPA notes that design, equipment, work practice or
operational standards established under CAA section 111(h) (commonly
referred to as ``work practice standards'') reflect the ``best
technological system of continuous emission reduction'' and that
this phrasing differs from the ``best system of emission reduction''
phrase in the definition of ``standard of performance'' in CAA
section 111(a)(1). Although the differences in these phrases may be
meaningful in other contexts, for purposes of evaluating the sources
and systems of emission reduction at issue in this rulemaking, the
EPA has applied these concepts in an essentially comparable manner
because the systems of emission reduction the EPA evaluated are all
technological.
Table 1--Applicable Dates for Proposed Subparts Addressed in This
Proposed Action
------------------------------------------------------------------------
Subpart Source type Applicable dates
------------------------------------------------------------------------
40 CFR part 60, subpart OOOO.... New, modified, or After August 23,
reconstructed 2011, and on or
sources. before September
18, 2015.
40 CFR part 60, subpart OOOOa... New, modified, or After September
reconstructed 18, 2015, and on
sources. or before
November 15,
2021.
40 CFR part 60, subpart OOOOb... New, modified, or After November 15,
reconstructed 2021.\1\
sources.
40 CFR part 60, subpart OOOOc... Existing sources.. On or before
November 15,
2021.\2\
------------------------------------------------------------------------
\1\ The standards for dry seal centrifugal compressors will apply to
those for which construction, reconstruction, or modification
commenced after December 6, 2022.
\2\ The presumptive standards for dry seal centrifugal compressors will
apply to those for which construction, reconstruction, or modification
commenced on or before December 6, 2022.
1. Proposed Standards for New, Modified and Reconstructed Sources After
November 15, 2021 (Proposed NSPS OOOOb)
As described in section IV of this preamble, the EPA is proposing
several changes to the BSER and the standards for certain affected
facilities based on a review of new data made available to the EPA and
information provided in public comments. For the other standards
proposed in the November 2021 proposal that generally remain unchanged
in this action, we have provided further justifications or
clarifications as needed based on the public comments and other
additional information received, as described in section IV of this
preamble. The proposed NSPS would apply to new, modified, and
reconstructed emission sources across the Crude Oil and Natural Gas
source category, including the production, processing, transmission,
and storage segments, for which construction, reconstruction, or
modification commenced after November 15, 2021, which is the date of
publication of the proposed NSPS OOOOb. In addition, the EPA is
proposing methane and VOC standards for one new emission source that is
currently unregulated (i.e., dry seal centrifugal compressors). Because
standards for dry seal centrifugal compressors were not proposed in the
November 2021 proposal, new, modified, and reconstructed dry seal
centrifugal compressors are defined as those for which construction,
reconstruction, or modification commenced after December 6, 2022.
In particular, this action proposes revisions to strengthen the
proposed VOC and methane standards addressing fugitive emissions from
well sites and pneumatic pumps; generally leaves unchanged the proposed
sulfur dioxide (SO2) performance standard for sweetening
units and the proposed VOC and methane performance standards for well
completions, gas well liquids unloading operations, associated gas from
oil wells, wet seal centrifugal compressors, reciprocating compressors,
pneumatic controllers, storage vessels, fugitive emissions from
compressor stations, and equipment leaks at natural gas processing
plants; and proposes new VOC and methane standards for dry seal
centrifugal compressors previously not regulated. A summary of the
proposed BSER determination and proposed NSPS for new, modified, and
reconstructed sources (NSPS OOOOb) is presented in Table 2. See section
IV of this preamble for a complete discussion of the proposed changes
to the BSER determination and proposed NSPS requirements.
This proposal also includes provisions for the use of alternative
test methods using advanced methane detection technologies that allow
for periodic screening or continuous monitoring for fugitive emissions
and emissions from covers and closed vent systems (CVS) used to route
emissions to control devices. These proposed alternatives would allow
for advanced screening technologies, which could be used to identify
large emissions or ``super-emitter emissions events'' sooner than the
proposed use of periodic OGI monitoring for fugitive emissions, covers
on storage vessels, and CVS. Various studies using aerial monitoring
techniques have identified large emissions from these types of sources.
Finally, in order to ensure that super-emitter emissions events are
identified and mitigated as quickly as possible, the EPA is proposing a
super-emitter response program where an owner or operator must
investigate and take appropriate mitigation actions upon receiving
certified notifications of detected emissions that are 100 kg/hr of
methane or greater. See sections IV.A and IV.B of this preamble for a
complete discussion of these proposed provisions.
2. Proposed EG for Sources Constructed Prior to November 15, 2021
(Proposed EG OOOOc)
As described in sections IV and V of this preamble, the EPA is
proposing several changes to the BSER determinations and presumptive
standards that were proposed under the authority of CAA section 111(d)
in the November 2021 proposal. These changes are based on a review of
new data made available to the EPA and information provided in public
comments. In the November 2021 proposal the EPA proposed the first
nationwide EG for GHG (in the form of methane limitations) for the
Crude Oil and Natural Gas source category, including the production,
processing, transmission, and storage segments (EG OOOOc).
This action proposes revisions to strengthen the proposed
presumptive standards for methane addressing fugitive emissions from
well sites, pneumatic controllers, pneumatic pumps, and wet seal
centrifugal compressors; generally leaves unchanged the proposed
methane presumptive standards for associated gas from oil wells,
reciprocating compressors, storage vessels, fugitive emissions from
compressor stations, and equipment leaks at natural gas processing
plants; and proposes new methane presumptive standards for well liquids
unloading operations and dry seal centrifugal compressors previously
[[Page 74708]]
not proposed to be regulated. A summary of the proposed BSER
determination and proposed presumptive standards for EG OOOOc is
presented in Table 3. See section IV of this preamble for a complete
discussion of the proposed changes to the BSER determination and
proposed presumptive standards.
This proposal also includes the same provisions described for NSPS
OOOOb that allow for the use of alternative test methods using advanced
methane detection technologies for periodic screening or continuous
monitoring for fugitive emissions and emissions from covers and CVS
used to route emissions to control devices. Finally, the EPA is also
proposing a super-emitter response program, where an owner or operator
that receives certified notifications of detected emissions that are
100 kg/hr or greater is obligated to take action to address those
emissions. See sections IV.A and IV.B of this preamble for a complete
discussion of these proposed provisions.
As stated in the November 2021 proposal,\7\ when the EPA
establishes NSPS for a source category, the EPA is required to issue EG
to reduce emissions of certain pollutants from existing sources in that
same source category. In such circumstances, under CAA section 111(d),
the EPA must issue regulations to establish procedures under which
states submit plans to establish, implement, and enforce standards of
performance for existing sources for certain air pollutants to which a
Federal NSPS would apply if such existing source were a new source.
Thus, the issuance of CAA section 111(d) final EG does not impose
binding requirements directly on sources but instead provides
requirements for states in developing their plans. Although state plans
bear the obligation to establish standards of performance, under CAA
sections 111(a)(1) and 111(d), those standards of performance must
reflect the degree of emission limitation achievable through the
application of the BSER as determined by the Administrator. As provided
in CAA section 111(d), a state may choose to take into account
remaining useful life and other factors in applying a standard of
performance to a particular source, consistent with the CAA, the EPA's
implementing regulations, and the final EG.
---------------------------------------------------------------------------
\7\ See 86 FR 63117 (November 15, 2021).
---------------------------------------------------------------------------
In this supplemental proposal, the EPA is proposing changes to the
BSER determinations and the degree of limitation achievable through
application of the BSER for certain existing equipment, processes, and
activities across the Crude Oil and Natural Gas source category. Those
changes are discussed in section IV of this preamble. Section V of this
preamble discusses the components of EG, including the steps,
requirements, and considerations associated with the development,
submittal, and implementation of state, tribal, and Federal plans, as
appropriate. For the EG, the EPA is proposing to translate the degree
of emission limitation achievable through application of the BSER
(i.e., level of stringency) into presumptive standards that states may
use in the development of state plans for specific designated
facilities. By doing this, the EPA has formatted the proposed EG such
that if a state chooses to adopt these presumptive standards, once
finalized, as the standards of performance in a state plan, the EPA
could approve such a plan as meeting the requirements of CAA section
111(d) and the finalized EG, if the plan meets all other applicable
requirements. In this way, the presumptive standards included in the EG
serve a function similar to that of a model rule,\8\ because they are
intended to assist states in developing their plan submissions by
providing states with a starting point for standards that are based on
general industry parameters and assumptions. The EPA anticipates that
providing these presumptive standards will create a streamlined
approach for states in developing plans and the EPA in evaluating state
plans. However, the EPA's action on each state plan submission is
carried out via rulemaking, which includes public notice and comment.
Inclusion of presumptive standards in the EG does not seek to pre-
determine the outcomes of any future rulemaking.
---------------------------------------------------------------------------
\8\ The presumptive standards are not the same as a Federal plan
under CAA section 111(d)(2). The EPA has an obligation to promulgate
a Federal plan if a state fails to submit a satisfactory plan. In
such circumstances, the final EG and presumptive standards would
serve as a guide to the development of a Federal plan. See section
VIII.F. for information on Federal plans.
---------------------------------------------------------------------------
Designated facilities located in Indian country would not be
encompassed within a state's CAA section 111(d) plan. Instead, an
eligible tribe that has one or more designated facilities located in
its area of Indian country would have the opportunity, but not the
obligation, to seek authority and submit a plan that establishes
standards of performance for those facilities on its Tribal lands. If a
tribe does not submit a plan, or if the EPA does not approve a tribe's
plan, then the EPA has the authority to establish a Federal plan for
that tribe. A summary of the proposed EG for existing sources (EG
OOOOc) for the oil and natural gas sector is presented in Table 3. See
sections IV and V of this preamble for a complete discussion of the
proposed EG requirements.
Table 2--Summary of Proposed BSER and Proposed Standards of Performance
for GHGs and VOCs
[NSPS OOOOb]
------------------------------------------------------------------------
Proposed standards
Affected source Proposed BSER of performance for
GHGs and VOCs
------------------------------------------------------------------------
Super-Emitters.............. Root cause analysis Root cause analysis
and corrective and corrective
action following action following
notification of notification of
super-emitter super-emitter
emissions event. emissions event.
Fugitive Emissions: Single Quarterly AVO Quarterly AVO
Wellhead Only Well Sites inspections. inspections. Repair
and Small Well Sites. for indications of
potential leaks
within 15 days of
inspection.
Fugitive monitoring
continues for all
well sites until
the site has been
closed, including
plugging the wells
at the site and
submitting a well
closure report.
Fugitive Emissions: Multi- Quarterly AVO Quarterly AVO
wellhead Only Well Sites (2 inspections. inspections. Repair
or more wellheads). AND................. for indications of
potential leaks
within 15 days of
inspection.
[[Page 74709]]
Monitoring and Semiannual OGI
repair based on monitoring
semiannual (Optional
monitoring using semiannual EPA
OGI \2\. Method 21
monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
Fugitive monitoring
continues for all
well sites until
the site has been
closed, including
plugging the wells
at the site and
submitting a well
closure report.
Fugitive Emissions: Well Bimonthly AVO Bimonthly AVO
Sites with Major Production monitoring (i.e., inspections. Repair
and Processing Equipment every other month). for indications of
and Centralized Production AND................. potential leaks
Facilities. Well sites with within 15 days of
specified major inspection.
production and AND
processing Well sites with
equipment: specified major
Monitoring and production and
repair based on processing
quarterly equipment:
monitoring using Quarterly OGI
OGI. monitoring.
(Optional quarterly
EPA Method 21
monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
Fugitive monitoring
continues for all
well sites until
the site has been
closed, including
plugging the wells
at the site and
submitting a well
closure report.
Fugitive Emissions: Monthly AVO Monthly AVO
Compressor Stations. monitoring. monitoring.
AND................. AND
Monitoring and Quarterly OGI
repair based on monitoring.
quarterly (Optional quarterly
monitoring using EPA Method 21
OGI. monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
Fugitive Emissions: Well Monitoring and Annual OGI
Sites and Compressor repair based on monitoring.
Stations on Alaska North annual monitoring (Optional annual
Slope. using OGI. EPA Method 21
monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
Fugitive Emissions: Well (Optional) (Optional)
Sites and Compressor Screening, Alternative
Stations. monitoring, and periodic screening
repair based on with advanced
periodic screening measurement
using an advanced technology instead
measurement of OGI and AVO
technology instead monitoring
of OGI monitoring. according to
minimum detection
sensitivity of
technology.
Fugitive Emissions: Well (Optional) (Optional)
Sites and Compressor Monitoring and Alternative
Stations. repair based on continuous
using a continuous monitoring system
monitoring system instead of OGI and
instead of OGI AVO monitoring.
monitoring.
Storage Vessels: A Single Capture and route to 95 percent reduction
Storage Vessel or Tank a control device. of VOC and methane.
Battery with PTE \4\ of 6
tpy or more of VOC and PTE
of 20 tpy or more of
methane.
Pneumatic Controllers: Use of zero- VOC and methane
Natural gas-driven that emissions emission rate of
Vent to the Atmosphere. controllers. zero.
Pneumatic Controllers: Use of low-bleed Natural gas bleed
Alaska (at sites where pneumatic rate no greater
onsite power is not controllers. than 6 scfh.\5\
available--continuous bleed
natural gas-driven).
Pneumatic Controllers: Monitor and repair OGI monitoring and
Alaska (at sites where through fugitive repair of emissions
onsite power is not emissions program. from controller
available--intermittent malfunctions.
natural gas-driven).
Well Liquids Unloading...... Employ techniques or Perform liquids
technologies that unloading with zero
eliminate methane methane or VOC
and VOC emissions. emissions. If this
If this is not is not feasible for
feasible for safety safety or technical
or technical reasons, employ
reasons, employ best management
best management practices to
practices to minimize venting of
minimize venting of emissions to the
emissions to the maximum extent
maximum extent possible.
possible.
Wet Seal Centrifugal Capture and route 95 percent reduction
Compressors (except for emissions from the of methane and VOC
those located at well wet seal fluid emissions.
sites). degassing system to
a control device.
Dry Seal Centrifugal Conduct preventative Volumetric flow rate
Compressors (except for maintenance and of 3 scfm.
those located at well repair to maintain
sites). flow rate at or
below 3 scfm \7\.
[[Page 74710]]
Reciprocating Compressors Repair or replace Volumetric flow rate
(except for those located the reciprocating of 2 scfm.
at well sites). compressor rod
packing in order to
maintain a flow
rate at or below 2
scfm.
Pneumatic Pumps............. Use of zero-emission Methane and VOC
pumps that are not emission rate of
powered by natural zero.
gas.
Well Completions: Combination of REC Applies to each well
Subcategory 1 (non-wildcat \8\ and the use of completion
and non-delineation wells). a completion operation with
combustion device. hydraulic
fracturing.
REC in combination
with a completion
combustion device;
venting in lieu of
combustion where
combustion would
present
demonstrable safety
hazards.
Initial flowback
stage: Route to a
storage vessel or
completion vessel
(frac tank, lined
pit, or other
vessel) and
separator.
Separation flowback
stage: Route all
salable gas from
the separator to a
flow line or
collection system,
re-inject the gas
into the well or
another well, use
the gas as an
onsite fuel source
or use for another
useful purpose that
a purchased fuel or
raw material would
serve. If
technically
infeasible to route
recovered gas as
specified,
recovered gas must
be combusted. All
liquids must be
routed to a storage
vessel or well
completion vessel,
collection system,
or be re-injected
into the well or
another well.
The operator is
required to have
(and use) a
separator onsite
during the entire
flowback period.
Well Completions: Use of a completion Applies to each well
Subcategory 2 (exploratory, combustion device. completion
wildcat, and delineation operation with
wells and low-pressure hydraulic
wells). fracturing.
The operator is not
required to have a
separator onsite.
Either: (1) Route
all flowback to a
completion
combustion device
with a continuous
pilot flame; or (2)
Route all flowback
into one or more
well completion
vessels and
commence operation
of a separator
unless it is
technically
infeasible for a
separator to
function. Any gas
present in the
flowback before the
separator can
function is not
subject to control
under this section.
Capture and direct
recovered gas to a
completion
combustion device
with a continuous
pilot flame.
For both options (1)
and (2), combustion
is not required in
conditions that may
result in a fire
hazard or
explosion, or where
high heat emissions
from a completion
combustion device
may negatively
impact tundra,
permafrost, or
waterways.
Equipment Leaks at Natural LDAR \9\ with LDAR with OGI
Gas Processing Plants. bimonthly OGI. following
procedures in
appendix K.
Oil Wells with Associated Route associated gas Route associated gas
Gas. to a sales line. If to a sales line. If
access to a sales access to a sales
line is not line is not
available, the gas available, the gas
can be used as an can be used as an
onsite fuel source, onsite fuel source
used for another or used for another
useful purpose that useful purpose that
a purchased fuel or a purchased fuel or
raw material would raw material would
serve, or routed to serve. If
a flare or other demonstrated that a
control device that sales line and
achieves at least beneficial uses are
95 percent not technically
reduction in feasible, the gas
methane and VOC can be routed to a
emissions. flare or other
control device that
achieves at least
95 percent
reduction in
methane and VOC
emissions.
Sweetening Units............ Achieve SO2 emission Achieve required
reduction minimum SO2
efficiency. emission reduction
efficiency.
------------------------------------------------------------------------
\1\ tpy (tons per year).
\2\ OGI (optical gas imaging).
\3\ ppm (parts per million).
\4\ PTE (potential to emit).
[[Page 74711]]
\5\ scfh (standard cubic feet per hour).
\6\ BMP (best management practices).
\7\ scfm (standard cubic feet per minute).
\8\ REC (reduced emissions completion).
\9\ LDAR (leak detection and repair).
Table 3--Summary of Proposed BSER and Proposed Presumptive Standards for
GHGs From Designated Facilities (EG OOOOc)
------------------------------------------------------------------------
Proposed presumptive
Designated facility Proposed BSER standards for GHGs
------------------------------------------------------------------------
Super-Emitters.............. Root cause analysis Root cause analysis
and corrective and corrective
action following action following
notification of notification by an
super-emitter EPA-approved entity
emissions event. or regulatory
authority of a
super-emitter
emissions event.\9\
Fugitive Emissions: Single Quarterly AVO Quarterly AVO
Wellhead Only Well Sites inspections. inspections. Repair
and Small Well Sites. for indications of
potential leaks
within 15 days of
inspection.
Fugitive monitoring
continues for all
well sites until
the site has been
closed, including
plugging the wells
at the site and
submitting a well
closure report.
Fugitive Emissions: Multi- Quarterly AVO Quarterly AVO
wellhead Only Well Sites (2 inspections. inspections. Repair
or more wellheads). AND................. for indications of
Monitoring and potential leaks
repair based on within 15 days of
semiannual inspection.
monitoring using Semiannual OGI
OGI \2\. monitoring
(Optional
semiannual EPA
Method 21
monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
Fugitive monitoring
continues for all
well sites until
the site has been
closed, including
plugging the wells
at the site and
submitting a well
closure report.
Fugitive Emissions: Well Bimonthly AVO Bimonthly AVO
Sites and Centralized monitoring (i.e., inspections. Repair
Production Facilities. every other month). for indications of
AND................. potential leaks
Well sites with within 15 days of
specified major inspection.
production and AND
processing Well sites with
equipment: specified major
Monitoring and production and
repair based on processing
quarterly equipment:
monitoring using Quarterly OGI
OGI. monitoring.
(Optional quarterly
EPA Method 21
monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
Fugitive monitoring
continues for all
well sites until
the site has been
closed, including
plugging the wells
at the site and
submitting a well
closure report.
Fugitive Emissions: Monthly AVO Monthly AVO
Compressor Stations. monitoring. monitoring.
AND................. AND
Monitoring and Quarterly OGI
repair based on monitoring.
quarterly (Optional quarterly
monitoring using EPA Method 21
OGI. monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
Fugitive Emissions: Well Monitoring and Annual OGI
Sites and Compressor repair based on monitoring.
Stations on Alaska North annual monitoring (Optional annual
Slope. using OGI. EPA Method 21
monitoring with 500
ppm defined as a
leak).
First attempt at
repair within 30
days of finding
fugitive emissions.
Final repair within
30 days of first
attempt.
Fugitive Emissions: Well (Optional) (Optional)
Sites and Compressor Screening, Alternative
Stations. monitoring, and periodic screening
repair based on with advanced
periodic screening measurement
using an advanced technology instead
measurement of OGI monitoring.
technology instead
of OGI monitoring.
Fugitive Emissions: Well (Optional) (Optional)
Sites and Compressor Monitoring and Alternative
Stations. repair based on continuous
using a continuous monitoring system
monitoring system instead of OGI
instead of OGI monitoring.
monitoring.
Storage Vessels: Tank Capture and route to 95 percent reduction
Battery with PTE of 20 tpy a control device. of methane.
or More of Methane.
Pneumatic Controllers: Use of zero- Methane emission
Natural gas-driven that emissions rate of zero.
Vent to the Atmosphere. controllers.
[[Page 74712]]
Pneumatic Controllers: Use of low-bleed Natural gas bleed
Alaska (at sites where pneumatic rate no greater
onsite power is not controllers. than 6 scfh.
available--continuous bleed
natural gas-driven).
Pneumatic Controllers: Monitor and repair OGI monitoring and
Alaska (at sites where through fugitive repair of emissions
onsite power is not emissions program. from controller
available--intermittent malfunctions.
natural gas-driven).
Gas Well Liquids Unloading.. Employ techniques or Perform liquids
technologies that unloading with zero
eliminate methane methane emissions.
emissions. If this If this is not
is not feasible for feasible for safety
safety or technical or technical
reasons, employ reasons, employ
best management best management
practices to practices to
minimize venting of minimize venting of
emissions to the emissions to the
maximum extent maximum extent
possible. possible.
Wet Seal Centrifugal Conduct preventative Volumetric flow rate
Compressors (except for maintenance and of 3 scfm.
those located at well repair to maintain
sites). flow rate at or
below 3 scfm \7\.
Dry Seal Centrifugal Conduct preventative Volumetric flow rate
Compressors (except for maintenance and of 3 scfm.
those located at well repair to maintain
sites). flow rate at or
below 3 scfm \7\.
Reciprocating Compressors Repair or replace Volumetric flow rate
(except for those located the reciprocating of 2 scfm.
at well sites). compressor rod
packing in order to
maintain a flow
rate at or below 2
scfm.
Pneumatic Pumps............. Use of zero-emission Methane emission
pumps that are not rate of zero.
powered by natural
gas.
Equipment Leaks at Natural LDAR with bimonthly LDAR with OGI
Gas Processing Plants. OGI. following
procedures in
appendix K.
Oil Wells with Associated Route associated gas Route associated gas
Gas. to a sales line. If to a sales line. If
access to a sales access to a sales
line is not line is not
available, the gas available, the gas
can be used as an can be used as an
onsite fuel source, onsite fuel source
used for another or used for another
useful purpose that useful purpose that
a purchased fuel or a purchased fuel or
raw material would raw material would
serve, or routed to serve. If
a flare or other demonstrated that a
control device that sales line and
achieves at least beneficial uses are
95 percent not technically
reduction in feasible, the gas
methane emissions. can be routed to a
flare or other
control device that
achieves at least
95 percent
reduction in
methane emissions.
------------------------------------------------------------------------
C. Costs and Benefits
In accordance with the requirements of Executive Order (E.O.)
12866, the EPA projected the emissions reductions, costs, and benefits
that may result from this proposed action if finalized as proposed.
These results are presented in detail in the RIA accompanying this
proposal developed in response to E.O. 12866. The RIA focuses on the
elements of the proposed rule that are likely to result in quantifiable
cost or emissions changes compared to a baseline that incorporates
changes to the regulatory requirements induced by the Congressional
Review Act (CRA) resolution \10\ but does not incorporate the proposed
standards. We estimated the cost, emissions, and benefit impacts for
the 2023 to 2035 period. We present the present value (PV) and
equivalent annual value (EAV) of costs, benefits, and net benefits of
this action in 2019 dollars.
---------------------------------------------------------------------------
\9\ As described in section IV.C, the EPA is proposing a super-
emitter response program under the statutory rationale that super-
emitters are a designated facility. The EPA is also proposing the
program under a second rationale that the super-emitter response
program constitutes work practice standards for certain sources and
compliance assurance measures for other sources. Under either
rationale, state plans are generally required to adopt the super-
emitter response program either as presumptive standards or as
measures that provide for the implementation and enforcement of such
standards.
\10\ See November 2021 Proposal, 86 FR at 63116 (discussing the
CRA Resolution and its effect on regulatory requirements).
---------------------------------------------------------------------------
The initial analysis year in the RIA is 2023 as we assume the
proposed rule will be finalized early in 2023. The NSPS will take
effect immediately and impact sources constructed after publication of
the proposed rule. The EG will take longer to go into effect as states
will need to develop implementation plans in response to the rule and
have them approved by the EPA. We assume in the RIA that this process
will take 3 years, and so EG impacts will begin in 2026. The final
analysis year is 2035, which allows us to provide 10 years of projected
impacts after the EG is assumed to take effect.
The cost analysis presented in the RIA reflects a nationwide
engineering analysis of compliance cost and emissions reductions, of
which there are two main components. The first component is a set of
representative or model plants for each regulated facility, segment,
and control option. The characteristics of the model plant include
typical equipment, operating characteristics, and representative
factors including baseline emissions and the costs, emissions
reductions, and product recovery resulting from each control option.
The second component is a set of projections of activity data for
affected facilities, distinguished by vintage, year, and other
necessary attributes (e.g., oil versus natural gas wells). Impacts are
calculated by setting parameters on how and when affected facilities
are assumed to respond to a particular regulatory regime, multiplying
activity data by model plant cost and emissions estimates, differencing
from the baseline scenario, and then summing to the desired level of
aggregation. In addition to emissions reductions, some control options
result in natural gas recovery, which can then be combusted in
production or sold. Where applicable, we present projected compliance
costs with and without the projected revenues from product recovery.
The EPA expects climate and health benefits due to the emissions
reductions projected under this proposed rule. The EPA estimated the
climate benefits of
[[Page 74713]]
methane (CH4) emission reductions expected from this
proposed rule using the social cost of methane (SC-CH4)
estimates presented in the ``Technical Support Document: Social Cost of
Carbon, Methane, and Nitrous Oxide Interim Estimates under E.O. 13990''
(IWG 2021) published in February 2021 by the Interagency Working Group
on the Social Cost of Greenhouse Gases (IWG). As a member of the IWG
involved in the development of the February 2021 TSD, the EPA agrees
that these estimates continue to represent at this time the most
appropriate estimate of the SC-CH4 until revised estimates
have been developed reflecting the latest, peer-reviewed science.
However, as discussed in Section VII.E, the EPA also presents a
sensitivity analysis of the monetized climate benefits using a set of
SC-CH4 estimates that incorporates recent research
addressing recommendations of the National Academies of Sciences,
Engineering, and Medicine (2017). The EPA notes that the benefits
analysis is entirely distinct from the statutory BSER determinations
proposed herein and is presented solely for the purposes of complying
with E.O. 12866.
Under the proposed rule, the EPA expects that VOC emission
reductions will improve air quality and are likely to improve health
and welfare associated with exposure to ozone, particulate matter with
a diameter of 2.5 micrometers or less (PM2.5), and hazardous
air pollutants (HAP). Calculating ozone impacts from VOC emissions
changes requires information about the spatial patterns in those
emissions changes. In addition, the ozone health effects from the
proposed rule will depend on the relative proximity of expected VOC and
ozone changes to population. In this analysis, we have not
characterized VOC emissions changes at a finer spatial resolution than
the national total. In light of these uncertainties, we present an
illustrative screening analysis in appendix C of the RIA based on
modeled oil and natural gas VOC contributions to ozone concentrations
as they occurred in 2017 and do not include the results of this
analysis in the estimate of benefits and net benefits projected from
this proposal.
The projected national-level emissions reductions over the 2023 to
2035 period anticipated under the proposed requirements are presented
in Table 4. Table 5 presents the PV and EAV of the projected benefits,
costs, and net benefits over the 2023 to 2035 period under the proposed
requirements using discount rates of 3 and 7 percent. The estimates
presented in Tables 4 and 5 reflect an updated analysis compared with
the RIA that accompanied the November 2021 proposal. The updated
analysis not only incorporates the new provisions put forth in the
supplemental proposal (in addition to the elements of the November 2021
proposal that are unchanged), but also includes key updates to
assumptions and methodologies that impact both the baseline and policy
scenarios. As such, the estimates presented in the tables are not
directly comparable to corresponding estimates presented in the
November 2021 proposal. Additionally, we note that the estimated
emission reductions in both proposals may not fully characterize the
emissions reductions achieved by this rule because they might not fully
account for the emissions resulting from super-emitter emissions events
that would be prevented or quickly corrected as a result of this rule.
The EPA solicits comments on any relevant data, appropriate
methodologies, or reliable estimates to help quantify the costs,
emissions reductions, benefits, and potential distributional effects
related to super-emitter events, the proposed emissions control
requirements for associated gas from oil wells, and the proposed
storage vessel control requirements at centralized production
facilities and in the gathering and boosting segment.
Table 4--Projected Emissions Reductions Under the Proposed Rule, 2023-
2035 Total
------------------------------------------------------------------------
Emissions reductions
Pollutant (2023-2035 total)
------------------------------------------------------------------------
Methane (million short tons) \a\.................. 36
VOC (million short tons).......................... 9.7
Hazardous Air Pollutant (million short tons)...... 0.39
Methane (million metric tons CO2 Eq.) \b\......... 810
------------------------------------------------------------------------
\a\ To convert from short tons to metric tons, multiply the short tons
by 0.907. Alternatively, to convert metric tons to short tons,
multiply metric tons by 1.102.
\b\ Carbon dioxide equivalent (CO2 Eq.) calculated using a global
warming potential of 25.
Table 5--Benefits, Costs, Net Benefits, and Emissions Reductions of the Proposed Rule, 2023 Through 2035
[Dollar estimates in millions of 2019 dollars] \a\
----------------------------------------------------------------------------------------------------------------
Equivalent annual Equivalent annual
Present value value Present value value
----------------------------------------------------------------------------------------------------------------
3 Percent Discount Rate
--------------------------------------------------------------------------------
Climate Benefits \b\........... $48,000 $4,500 $48,000 $4,500
----------------------------------------------------------------------------------------------------------------
3 Percent Discount Rate
7 Percent Discount Rate
--------------------------------------------------------------------------------
Net Compliance Costs........... $14,000 $1,400 $12,000 $1,400
Compliance Costs............... 19,000 1,800 15,000 1,800
Product Recovery............... 4,600 440 3,300 390
Net Benefits................... 34,000 3,200 36,000 3,100
--------------------------------------------------------------------------------
Non-Monetized Benefits......... Climate and ozone health benefits from reducing 36 million short tons of
methane from 2023 to 2035.
PM2.5 and ozone health benefits from reducing 9.7 million short tons of VOC
from 2023 to 2035.\c\
HAP benefits from reducing 390 thousand short tons of HAP from 2023 to 2035.
[[Page 74714]]
Emissions reductions from the super-emitter response program.
Visibility benefits.
Reduced vegetation effects.
----------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures. Totals may not appear to add correctly due to rounding.
\b\ Climate benefits are based on reductions in methane emissions and are calculated using four different
estimates of the SC-CH4 (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th
percentile at 3 percent discount rate). For the presentational purposes of this table, we show the benefits
associated with the average SC-CH4 at a 3 percent discount rate, but the Agency does not have a single central
SC-CH4 point estimate. We emphasize the importance and value of considering the benefits calculated using all
four SC-CH4 estimates; the present value (and equivalent annual value) of the additional benefit estimates
ranges from $19 billion to $130 billion ($2.1 billion to 12 billion) over 2023 to 2035 for the proposed
option. Please see Table 3-5 and Table 3-8 of the RIA for the full range of SC-CH4 estimates. As discussed in
Section 3 of the RIA, a consideration of climate benefits calculated using discount rates below 3 percent,
including 2 percent and lower, are also warranted when discounting intergenerational impacts. Appendix B of
the RIA presents the results of a sensitivity analysis using a set of SC-CH4 estimates that incorporates
recent research addressing recommendations of the National Academies of Sciences, Engineering, and Medicine
(2017). All net benefits are calculated using climate benefits discounted at 3 percent.
\c\ A screening-level analysis of ozone benefits from VOC reductions can be found in appendix C of the RIA,
which is included in the docket.
II. General Information
A. Does this action apply to me?
Categories and entities potentially affected by this action
include:
Table 6--Industrial Source Categories Affected by This Action
----------------------------------------------------------------------------------------------------------------
Category NAICS code \1\ Examples of regulated entities
----------------------------------------------------------------------------------------------------------------
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/local/tribal government...... ................ Not affected.
----------------------------------------------------------------------------------------------------------------
\1\ North American Industry Classification System (NAICS).
This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be affected by 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 the final rule. 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 air
permitting authority, or your EPA Regional representative listed in 40
CFR 60.4 (General Provisions).
B. How do I obtain a copy of this document, background information, and
other related information?
In addition to being available in the docket, an electronic copy of
the proposed action is available on the internet. Following signature
by the Administrator, the EPA will post a copy of this proposed action
at https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-industry. Following publication in the Federal Register, the EPA will
post the Federal Register version of the supplemental proposal and key
technical documents at this same website and at Docket ID No. EPA-HQ-
OAR-2021-0317 located at https://www.regulations.gov/.
III. Purpose of This Regulatory Action
A. What is the purpose of this supplemental proposal?
On November 15, 2021, the EPA published a proposed rulemaking that
included proposed NSPS and EGs to mitigate climate-destabilizing
pollution and to protect human health by reducing GHG and VOC emissions
from the Oil and Natural Gas Industry, specifically the Crude Oil and
Natural Gas source category. The November 2021 proposal included
comprehensive analyses of the available data for methane and VOC
emissions sources in the Crude Oil and Natural Gas source category and
the latest available information on control measures and techniques to
identify achievable, cost-effective measures to significantly reduce
emissions, consistent with the requirements of section 111 of the CAA.
The November 2021 proposal also solicited comment and information on
specific topics.
New information was received and reviewed that was not considered
in the November 2021 proposal. As a result, changes to some of the
standards and other provisions proposed in November 2021 are being
proposed in this supplemental notice.
Some of the new information was provided by commenters during the
November 2021 proposal public comment period. Approximately 470,000
public comment letters were submitted on the November 2021 proposal
representing a wide range of stakeholders and state and tribal
governments. The EPA reviewed and considered the comments received,
including the responses to the specific solicitations for information
and input in the development of this supplemental proposal. Several of
the commenters
[[Page 74715]]
representing diverse stakeholder perspectives expressed general support
for the proposal and requested that the EPA further strengthen the
proposed standards and make them more comprehensive. Other commenters
highlighted implementation or cost concerns related to some of the
elements proposed in the November 2021 proposal. Some commenters also
provided data and information that the EPA was able to use to refine or
revise several of the standards included in the November 2021 proposal.
This supplemental proposal only addresses specific comments that
the EPA determined warranted changes to what was proposed. It does not
address/summarize all of the comments submitted on the November 2021
proposal. The EPA will continue to evaluate all the previously
submitted comments, as well as new comments submitted on this
supplemental action, in the development of a final NSPS OOOOb and EG
OOOOc. All relevant comments submitted on both proposals will be
responded to at that time.
In summary, the purpose of this supplemental proposed rulemaking is
to update, strengthen, and expand the standards proposed in the
November 2021 proposal under CAA section 111(b) for methane and VOC
emissions from new, modified, and reconstructed facilities, and the
presumptive standards proposed under CAA section 111(d) for methane
emissions from existing sources. In addition, this proposal: (1)
Proposes to reduce emissions from the source category more
comprehensively by adding proposed standards for certain sources that
were not addressed in the November 2021 proposal, revising the proposed
requirements for fugitive emissions monitoring and repair, and by
establishing a super-emitter response program to target timely
mitigation of super-emitter emissions events; (2) encourages the
deployment of innovative technologies and techniques for detecting and
reducing methane emissions by providing additional options for the use
of advanced monitoring; (3) modifies and refines certain aspects of the
proposed standards in response to concerns and information submitted in
public comments; and (4) provides additional information not included
in the November 2021 proposal for public comment, such as content for
the new subparts that reflects the proposed standards and emission
guidelines, and details of the timelines and other implementation
requirements that apply to states to limit methane pollution from
existing designated facilities in the source category under CAA section
111(d).
This supplemental notice also includes an updated RIA that accounts
for the full impacts of these proposed actions. If finalized and
implemented, the proposed actions in this rulemaking, as detailed in
the November 2021 proposal and this supplemental proposal, would result
in significant and cost-effective reductions in climate and health-
harming pollution while encouraging the continued development and
deployment of innovative technologies to further reduce this pollution
in the Crude Oil and Natural Gas source category.
The summary and rationale for changes to the November 2021 proposed
NSPS OOOOb and EG OOOOc standards are presented in section IV of this
preamble. For each change, a high-level summary of the relevant points
raised by commenters leading to the change is provided, followed by the
EPA's rationale for the change. In addition to changes from the
November 2021 proposal that are the result of public comments, the EPA
has also included changes made as a result of additional EPA review and
consideration of available information.
Section V of this preamble proposes specific requirements for the
implementation of the proposed EG to provide states with information
needed for purposes of EG state plan development. First, we discuss
changes to the proposed requirements for establishing standards of
performance in state plans. Second, we discuss changes to the proposed
components of an approvable state plan submission. Third, we discuss
the proposed timing for state plan submissions, and changes to the
proposed timeline for designated facilities to come into final
compliance with the state plan.
Section VI of this preamble includes requirements for using optical
gas imaging in leak detection as appendix K to 40 CFR part 60 (appendix
K). It provides an overview of the November 2021 proposal, significant
changes made to the proposal and the basis for those changes, and a
summary of the updated appendix K requirements.
Section VII of this supplemental proposal includes updates to the
impacts of the November 2021 NSPS proposal based on changes discussed
in sections IV and V of this preamble.
The EPA is requesting comments on all aspects of the supplemental
proposal to enable the EPA to develop a final rule that, consistent
with our responsibilities under section 111 of the CAA, achieves the
greatest possible reductions in methane and VOC emissions while
remaining achievable, cost effective, and conducive to technological
innovation. Because this preamble includes comment solicitations/
requests on several topics and issues, we have prepared a separate
memorandum that presents these comment requests by section and topic as
a guide to assist commenters in preparing comments. This memorandum and
supporting materials can be obtained from the Docket for this action
(see Docket ID No. EPA-HQ-OAR-2021-0317). The title of the memorandum
is ``Standards of Performance for New, Reconstructed, and Modified
Sources and Emissions Guidelines for Existing Sources: Oil and Natural
Gas Sector Climate Review--Supplemental Proposed Rule Summary of
Comment Solicitations.''
B. What date defines a new, modified, or reconstructed source for
purposes of the proposed NSPS OOOOb?
For the reasons explained below, NSPS OOOOb would apply to all
emissions sources (``affected facilities'') identified in the proposed
40 CFR 60.5365b, except dry seal centrifugal compressors, that
commenced construction, reconstruction, or modification after November
15, 2021. NSPS OOOOb would apply to dry seal centrifugal compressor
affected facilities that commence construction, reconstruction, or
modification after December 6, 2022.
Pursuant to CAA section 111(b), the EPA proposed new source
performance standards (NSPS) for a wide range of emissions sources in
the Crude Oil and Natural Gas source category (to be codified in 40 CFR
part 60 subpart OOOOb) in a Federal Register notice published November
15, 2021. Some of the proposed standards resulted from the EPA's review
of the current NSPS codified at 40 CFR part 60 subpart OOOOa (NSPS
OOOOa), while others were proposed standards for additional emissions
sources that are currently unregulated. The emissions sources for which
the EPA proposed standards in the November 2021 proposal are as
follows:
Well completions
Gas well liquids unloading operations
Associated gas from oil wells
Wet seal centrifugal compressors
Reciprocating compressors
Pneumatic controllers
Pneumatic pumps
Storage vessels
Collection of fugitive emissions components at well sites,
centralized production facilities, and compressor stations
Equipment leaks at natural gas processing plants
[[Page 74716]]
Sweetening units
These standards of performance would apply to ``new sources.'' CAA
section 111(a)(2) defines a ``new source'' as ``any stationary source,
the construction or modification of which is commenced after the
publication of regulations (or, if earlier, proposed regulations)
prescribing a standard of performance under this section which will be
applicable to such source.'' Because the proposed regulation proposing
the standards for these emission sources was published November 15,
2021, ``new sources'' to which these standards apply are those that
commenced construction, reconstruction, or modification after November
15, 2021.
We received comments on the November 2021 proposal that it lacks
regulatory text and therefore should not be used to define new sources
for purposes of NSPS OOOOb.\11\ The EPA disagrees for the following
reasons. CAA section 307(d)(3) specifies the information that a
proposed rule under the CAA must contain, such as a statement of basis,
supporting data, and major legal and policy considerations; the list of
required information does not include proposed regulatory text.
Similarly, the Administrative Procedures Act (APA), which governs most
Federal rulemaking, does not require publication of the proposed
regulatory text in the Federal Register. Section 553(b)(3) of the APA
provides that a notice of proposed rulemaking shall include ``either
the terms or substance of the proposed rule or a description of the
subjects and issues involved.'' (Emphasis added). Thus, the APA clearly
provides flexibility to describe the ``subjects and issues involved''
as an alternative to inclusion of the ``terms or substance'' of the
proposed rule. See also Rybachek v. EPA, 904 F.2d 1276, 1287 (9th Cir.
1990) (the EPA's ``failure to propose in advance the actual wording''
of a regulation does not make the regulation invalid where the
``proposal . . . clearly describe[s] `the subjects and issues' ''
involved). The EPA solicits comments on whether CAA section 111(a)
provides the EPA discretion to define ``new sources'' based on the
publication date of a supplemental proposal and, if so, whether there
are any unique circumstances here that would warrant the exercise of
such discretion in this rulemaking by the EPA.
---------------------------------------------------------------------------
\11\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0424, EPA-HQ-OAR-
2021-0317-0539, EPA-HQ-OAR-2021-0317-0579, EPA-HQ-OAR-2021-0317-
0598, EPA-HQ-OAR-2021-0317-0599, EPA-HQ-OAR-2021-0317-0815, and EPA-
HQ-OAR-2021-0317-0929.
---------------------------------------------------------------------------
In addition to the proposed standards, this supplemental proposal
includes proposed standards for an additional emissions source,
specifically dry seal centrifugal compressors. Because the EPA is
proposing standards for dry seal centrifugal compressors for the first
time in this supplemental proposal, ``new sources'' to which these
standards apply are dry seal centrifugal compressors that commence
construction, reconstruction, or modification after the date this
supplemental proposal is published, which is December 6, 2022.
C. What date defines an existing source for purposes of the proposed EG
OOOOc?
The November 2021 proposal also included proposed emissions
guidelines for states to follow and develop plans to regulate existing
sources in the Crude Oil and Natural Gas source category under EG
OOOOc. Under CAA section 111, a source is either new, i.e.,
construction, reconstruction, or modification commenced after a
proposed NSPS is published in the Federal Register (CAA section
111(a)(1)), or existing, i.e., any source other than a new source (CAA
section 111(a)(6)). Accordingly, any source that is not subject to the
proposed NSPS OOOOb as described is an existing source subject to EG
OOOOc. As explained, new sources, with the exception of dry seal
centrifugal compressors, are those that commenced construction,
reconstruction, or modification after November 15, 2021; therefore,
existing sources are those that commenced construction, reconstruction,
or modification on or before November 15, 2021. Similarly, because new
dry seal centrifugal compressors are those that commenced construction,
reconstruction, or modification after December 6, 2022, existing dry
seal centrifugal compressors are those that commenced construction,
reconstruction, or modification on or before December 6, 2022.
D. How will the proposed EG OOOOc impact sources already subject to
NSPS KKK, NSPS OOOO, or NSPS OOOOa?
Sources currently subject to 40 CFR part 60, subpart KKK (NSPS
KKK), 40 CFR part 60 subpart OOOO (NSPS OOOO), or NSPS OOOOa would
continue to comply with their respective standards until a state or
Federal plan implementing EG OOOOc becomes effective. For most
designated facilities, the EPA proposes to conclude that compliance
with the implementing state or Federal plan that is consistent with the
presumptive standards in EG OOOOc would constitute compliance with the
older NSPS because the presumptive standards proposed for EG OOOOc
result in the same or greater emission reductions than the current
standards in the older NSPS.
In this rulemaking, the EPA is proposing standards for dry seal
centrifugal compressor and intermittent bleed pneumatic controllers for
the first time in NSPS OOOOb and EG OOOOc. Because these designated
facilities (i.e., dry seal centrifugal compressors and intermittent
bleed pneumatic controllers) are not subject to regulation under a
previous NSPS, they only need to comply with the state or Federal plan
implementing EG OOOOc. The EPA is proposing presumptive standards for
fugitive emissions at compressor stations, pneumatic pumps at natural
gas processing plants, and pneumatic controllers at natural gas
processing plants that are all the same or greater stringency than NSPS
KKK, NSPS OOOO, and NSPS OOOOa, as applicable. Therefore, compliance
with the state or Federal plan implementing EG OOOOc would satisfy
compliance with the respective NSPS regulation. Additionally, the
proposed presumptive standards in EG OOOOc for pneumatic pumps
(excluding processing) and natural gas processing plant equipment leaks
are more stringent than the standards in NSPS OOOOa for pneumatic pumps
and all three NSPS for natural gas processing plant equipment leaks,
and therefore compliance with the state or Federal plan implementing EG
OOOOc would satisfy compliance with the respective NSPS regulation.
For wet seal centrifugal compressors, two different standards are
in place for the older NSPS. NSPS KKK is an equipment standard that
provides several compliance options including: (1) Operating the
compressor with the barrier fluid at a pressure that is greater than
the compressor stuffing box pressure; (2) equipping the compressor with
a barrier fluid system degassing reservoir that is routed to a process
or fuel gas system, or that is connected by a CVS to a control device
that reduces VOC emissions by 95 percent or more; or (3) equipping the
compressor with a system that purges the barrier fluid into a process
stream with zero VOC emissions to the atmosphere. NSPS KKK exempts
compressors from these requirements if it is either equipped with a
closed vent system to capture and transport leakage from the compressor
drive shaft back to a process or fuel gas system or to a control device
[[Page 74717]]
that reduces VOC emissions by 95 percent, or if it is designated for no
detectable emissions. NSPS OOOO and NSPS OOOOa require 95 percent
reduction of emissions from each centrifugal compressor wet seal fluid
degassing system. NSPS OOOO and OOOOa also allow the alternative of
routing the emissions to a process. The proposed presumptive standards
under EG OOOOc would be a numerical emission limit of 3 scfm, as
described in IV.G. of this preamble, and includes an alternative
compliance option to reduce methane emissions by 95 percent by routing
to a control or process. The proposed presumptive standard of 3 scfm is
less stringent than the standards in NSPS OOOO and OOOOa, and
therefore, compliance with a state or Federal plan implementing EG
OOOOc using the 3 scfm presumptive standard would not satisfy
compliance with NSPS OOOO and NSPS OOOOa for wet seal centrifugal
compressor designated facilities. However, the EPA is not aware of any
wet seal centrifugal compressors subject to NSPS OOOO or NSPS OOOOa and
the EPA believes that centrifugal compressors installed since those
rules went into effect (August 2011 and September 2015) are utilizing
dry seals rather than wet seals. For wet seal centrifugal compressors
currently subject to KKK (those designated as new sources between
January 1984 and August 2011), compliance with NSPS KKK would allow for
compliance with the state or Federal plan implementing EG OOOOc because
the zero emissions limit would also achieve the 3 scfm limit proposed
in EG OOOOc. For an owner or operator who uses the alternative
compliance method proposed in EG OOOOc of routing to a control or
process, achieving 95 percent emissions reductions can be accomplished
using the same compressor requirements as required in NSPS OOOOa. Thus,
compliance with a state or Federal plan implementing EG OOOOc using the
95 percent control alternative would satisfy compliance with NSPS OOOO
and NSPS OOOOa for wet seal centrifugal compressor designated
facilities.
The NSPS KKK standard is more stringent than the proposed 3 scfm
presumptive standard in EG OOOOc for methane emissions. Accordingly,
for centrifugal compressors, NSPS KKK would still apply to compressors
at natural gas processing plants for which construction,
reconstruction, or modification commenced after January 20, 1984, and
on or before August 23, 2011.
There are two different standards for reciprocating compressors in
the older NSPS: (1) NSPS KKK requires the use of a seal system and
includes a barrier fluid system that prevents leakage of VOC to the
atmosphere for reciprocating compressors located at natural gas
processing plants, and (2) NSPS OOOO and NSPS OOOOa require changing
out the rod packing every 3 years or routing emissions to a control.
The proposed presumptive standard for EG OOOOc is a volumetric flow
rate of 2 scfm. The proposed BSER is to repair and/or replace the
reciprocating compressor rod packing in order to maintain the flow rate
at or below 2 scfm (based on annual monitoring and additional
preventative or corrective measures) and includes an alternative
compliance option to route emissions to a process, as described in
IV.I. of this preamble.
The NSPS KKK standard is more stringent than the proposed 2 scfm
presumptive standard in EG OOOOc for methane emissions. Accordingly,
for reciprocating compressors subject to NSPS KKK, the NSPS KKK
provisions would still apply to reciprocating compressors at natural
gas processing plants for which construction, reconstruction, or
modification commenced after January 20, 1984, and on or before August
23, 2011. For NSPS KKK, several provisions effectively exempt certain
reciprocating compressors at natural gas processing plants from the
seal system requirements, including: an exemption for reciprocating
compressors in wet gas service, a requirement that reciprocating
compressors must be in VOC service (i.e., at least 10 percent by weight
VOC in the process fluid in contact with the compressor) for standards
to apply, and an exemption for reciprocating compressors designated
with no detectable emissions. If a reciprocating compressor at a
natural gas processing plant was constructed, reconstructed, or
modified between January 20, 1984, and August 23, 2011, is exempt from
the provisions of NSPS KKK due to one of these conditions, it would be
subject to the requirements of the state or Federal plan implementing
EG OOOOc.
As explained in section XII.E.1.d. of the November 2021 proposal
\12\ and section IV.I of this preamble, the EPA finds that the proposed
EG OOOOc standard is more efficient at discovering and reducing any
emissions that may develop than the set 3-year replacement interval
from NSPS OOOO and NSPS OOOOa. Overall, the proposed presumptive
standards would produce more rod packing replacements, thereby reducing
more emissions compared to the 3-year interval. Therefore, the EPA is
proposing that compliance with the state or Federal plan implementing
EG OOOOc will satisfy compliance with the respective NSPS OOOO and
OOOOa regulations for reciprocating compressor designated facilities.
---------------------------------------------------------------------------
\12\ 86 FR 63215 to 63220 (November 15, 2021).
---------------------------------------------------------------------------
The affected facility for storage vessels is defined in the NSPS
OOOO and NSPS OOOOa as a single storage vessel with the potential to
emit greater than 6 tons of VOC per year and the standard that applies
is 95 percent emissions reduction. Under the proposed EG OOOOc, the
designated facility is a tank battery with the potential to emit
greater than 20 tons of methane per year with the same 95 percent
emission reduction standard, as discussed in IV.J. of this preamble.
Affected facilities under NSPS OOOO or OOOOa that are part of a
designated facility under the EG would be required to meet the 95
percent reduction standard, and therefore would satisfy their
respective NSPS requirement to do the same. Affected facilities under
NSPS OOOO or OOOOa that emit 6 tpy or more of VOCs but that do not meet
the potential to emit 20 tons of methane per year definition would
continue to comply with the 95-percent emissions reduction standard in
their respective NSPS. Scenarios regarding further physical or
operational changes in NSPS OOOOb that would reclassify sources from
the older NSPS and/or EG OOOOc into NSPS OOOOb are discussed in section
IV.J.1.b. of this preamble.
Similarly, pneumatic controller affected facilities not located at
natural gas processing plants are defined as single high-bleed
controllers with a low-bleed standard under NSPS OOOO and NSPS OOOOa,
while the designated facility under EG OOOOc is defined as a collection
of natural gas-driven pneumatic controllers at a site with a zero
emissions standard (discussed further in Section IV.D. of this
preamble). The proposed zero-emissions presumptive standard in EG OOOOc
is more stringent than the low-bleed standard found in the older NSPS,
therefore the EPA is proposing that compliance with the state or
Federal plan implementing EG OOOOc would satisfy compliance with the
respective NSPS regulation for pneumatic controllers not located at a
natural gas processing plant.
Lastly, standards for fugitive emissions from well sites under NSPS
OOOOa require semiannual OGI monitoring on all components at the well
site except for wellhead only well sites (which are not affected
facilities), while the presumptive standards under the proposed EG
OOOOc would require quarterly OGI monitoring at well sites
[[Page 74718]]
with major production and processing equipment, semiannual OGI combined
with quarterly AVO inspections at multi-wellhead only well sites,\13\
and quarterly AVO inspections for small sites and single wellhead well
sites, as described in section IV.A of this preamble. It is clear that
the proposed presumptive standards for well sites with major production
and processing equipment and the proposed presumptive standards for
multi-wellheads only well sites are both more stringent than the
semiannual OGI monitoring standard under NSPS OOOOa because one would
require more frequent OGI monitoring while the other would require AVO
inspections in addition to semiannual OGI monitoring; therefore, for
these existing wellsites that are also subject to NSPS OOOOa,
compliance with proposed presumptive standards would be deemed in
compliance with the semiannual OGI monitoring standard in NSPS OOOOa.
With respect to existing single wellhead only well sites and small
sites that are also subject to the semiannual monitoring under NSPS
OOOOa, the EPA is proposing that compliance with the proposed
presumptive standards, specifically quarterly AVO, would satisfy NSPS
OOOOa for the following reasons. First, as explained in more detail in
section IV.A, AVO is effective, and therefore OGI is unnecessary, for
detecting fugitive emissions from many of the fugitive emissions
components at these sites. Second, by requiring more frequent visits to
the sites, the proposed presumptive standard would allow earlier
detection and repair of fugitive emissions, in particular large
emissions from components such as thief hatches on uncontrolled storage
vessels. In light of the above, the EPA finds that the presumptive
standards under the proposed EG OOOOc would effectively address the
fugitive emissions at these well sites, and that semiannual OGI
monitoring would no longer be necessary for these well sites that are
also subject to NSPS OOOOa. For the reasons stated above, the EPA is
proposing to conclude that compliance with the state or Federal plan
implementing the presumptive fugitive emissions standards in the
proposed EG OOOOc may be deemed to satisfy compliance with monitoring
standards (i.e., semiannual monitoring using OGI) in NSPS OOOOa for all
well sites.
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\13\ Because of a difference in the definition of a wellhead
only well site in NSPS OOOOa and the proposed EG OOOOc, some single
and multi-wellhead only well sites could be subject to the
semiannual OGI monitoring under NSPS OOOOa.
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The EPA is soliciting comment on all aspects of the proposed
comparison of standards in the older NSPS to the proposed presumptive
standards in EG OOOOc. Specifically, the EPA is requesting comment
relevant to the comparison of stringency for compressors (both
centrifugal and reciprocating) to NSPS KKK and for fugitive emissions
monitoring at small well sites.
E. How does the EPA consider costs in this supplemental proposal?
In the November 2021 proposal, the EPA described the various
approaches for evaluating control costs in its BSER analyses. 86 FR
63154-63157 (November 15, 2021). As described in that document, in
considering the costs of the control options evaluated in this action,
the EPA estimated the control costs under various approaches, including
annual average cost-effectiveness and incremental cost-effectiveness of
a given control. In its cost-effectiveness analyses, the EPA recognized
and took into account that these multi-pollutant controls reduce both
VOC and methane emissions in equal proportions, as reflected in the
single-pollutant and multipollutant cost effectiveness approaches for
the proposed NSPS OOOOb. The EPA also considered cost saving from the
natural gas recovered instead of vented due to the proposed controls.
In both the November 2021 proposal \14\ and this supplemental
proposal,\15\ the EPA proposes to find that cost-effectiveness values
up to $5,540/ton of VOC reduction are reasonable for controls that we
have identified as BSER and within the range of what the EPA has
historically considered to represent cost effective controls for the
reduction of VOC emissions. Similarly, for methane, the EPA finds the
cost-effectiveness values up to $1,970/ton of methane reduction to be
reasonable for controls that we have identified as BSER in both the
November 2021 proposal and this supplemental proposal, well below the
$2,185/ton \16\ of methane reduction that EPA has previously found to
be reasonable for the industry.
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\14\ 86 FR 63155 (November 15, 2021).
\15\ See November 2021 TSD at Document ID No. EPA-HQ-OAR-2021-
0317-0166 and Supplemental TSD for this action located at Docket ID
No. EPA-HQ-OAR-2021-0317.
\16\ 80 FR 56627 (June 6, 2016). See also, ``Background
Technical Support Document for the New Source Performance Standards
40 CFR part 60 subpart OOOOa (May 2016)'', at page 93, Table 6-7
located at Document ID No. EPA-HQ-OAR-2010-0505-7631.
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For this supplemental proposal, we also updated the two additional
analyses that the EPA performed for the November 2021 proposal to
further inform our determination of whether the cost of control of the
collection of proposed standards would be reasonable, similar to
compliance cost analyses we have completed for other NSPS.\17\ The two
additional analyses include: (1) A comparison of the capital costs
incurred by compliance with the proposed rules to the industry's
estimated new annual capital expenditures, and (2) a comparison of the
annualized costs that would be incurred by compliance with the proposed
standards to the industry's estimated annual revenues. In this section,
the EPA provides updated information regarding these cost analyses
based on the proposed standards described in this notice. See 86 FR
63156 (November 15, 2021) for additional discussion on these two
analyses.
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\17\ For example, see our compliance cost analysis in
``Regulatory Impact Analysis (RIA) for Residential Wood Heaters NSPS
Revision. Final Report.'' U.S. Environmental Protection Agency,
Office of Air Quality Planning and Standards. EPA- 452/R-15-001,
February 2015.
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First, for the capital expenditures analysis, the EPA divided the
nationwide capital expenditures projected to be spent to comply with
the proposed standards by an estimate of the total sector-level new
capital expenditures for a representative year to determine the
percentage that the nationwide capital cost requirements under the
proposal represent of the total capital expenditures by the sector. We
combine the compliance-related capital costs under the proposed
standards for the NSPS and for the presumptive standards in the
proposed EG to analyze the potential aggregate impact of the proposal.
The EAV of the projected compliance-related capital expenditures over
the 2023 to 2035 period is projected to be about $1.4 billion in 2019
dollars. We obtained new capital expenditure data for relevant NAICS
codes for 2019 from the U.S. Census 2020 Annual Capital Expenditures
Survey.\18\ While Census data on capital expenditures are available for
2020, these figures were heavily influenced by COVID-19-related impacts
such that 2020 does is not an appropriate representative year to use in
this analysis. According to these data, new capital expenditures for
the sector in 2019 were about $156 billion in 2019
[[Page 74719]]
dollars.\19\ Note that new capital expenditures for pipeline
transportation of natural gas (NAICS 4862) includes only expenditures
on structures as data on expenditures on equipment data are withheld to
avoid disclosing data for individual enterprises. As a result, the
capital expenditures used here represent an underestimate of the
sector's expenditures. Comparing the EAV of the projected compliance-
related capital expenditures under the proposal with the 2019 total
sector-level new capital expenditures yields a percentage of about 0.9
percent, which is well below the percentage increase previously upheld
by the courts.
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\18\ U.S. Census Bureau, 2020 Annual Capital Expenditures
Survey, Table 4b. Capital Expenditures for Structures and Equipment
for Companies with Employees by Industry: 2019 Revised, https://www.census.gov/data/tables/2020/econ/aces/2020-aces-summary.html,
accessed 7/12/2022.
\19\ The total capital expenditures for the same NAICS codes
during COVID 19-impacted 2020 were about $90 billion.
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Second, for the comparison of compliance costs to revenues, we use
the EAV of the projected compliance costs without and with projected
revenues from product recovery under the proposal for the 2023 to 2035
period then divided the nationwide annualized costs by the annual
revenues for the appropriate NAICS code(s) for a representative year to
determine the percentage that the nationwide annualized costs represent
of annual revenues. Like we do for capital expenditures, we combine the
costs projected to be expended to comply with the standards for NSPS
and the presumptive standards in the proposed EG to analyze the
potential aggregate impact of the proposal. The EAV of the associated
increase in compliance cost over the 2023 to 2035 period is projected
to be about $1.7 billion without revenues from product recovery and
about $1.2 billion with revenues from product recovery (in 2019
dollars). Revenue data for relevant NAICS codes were obtained from the
U.S. Census 2017 County Business Patterns and Economic Census, the most
recent revenue figures available.\20\ According to these data, 2017
receipts for the sector were about $358 billion in 2019 dollars.
Comparing the EAV of the projected compliance costs under the proposal
with the sector-level receipts figure yields a percentage of about 0.5
percent without revenues from product recovery and about 0.4 percent
with revenues from product recovery. More data and analysis supporting
the comparison of capital expenditures and annualized costs projected
to be incurred under the rule and the sector-level capital expenditures
and receipts is presented in the TSD for this action, which is in the
public docket.
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\20\ 2017 County Business Patterns and Economic Census. The
Number of Firms and Establishments, Employment, Annual Payroll, and
Receipts by Industry and Enterprise Receipts Size: 2017, https://www.census.gov/programs-surveys/susb/data/tables.2017.html, accessed
September 4. 2021. Note receipts data are available only for
Economic Census years (years ending in 2 and 7) so 2017 data remains
the most recent data available.
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In considering the costs of the control options evaluated in this
action, the EPA estimated the control costs under various approaches,
including annual average cost-effectiveness and incremental cost-
effectiveness of a given control. In its cost-effectiveness analyses,
the EPA recognized and took into account that these multi-pollutant
controls reduce both VOC and methane emissions in equal proportions, as
reflected in the single-pollutant and multipollutant cost effectiveness
approaches for the proposed NSPS OOOOb. The EPA also considered cost
saving from the natural gas recovered instead of vented due to the
proposed controls. Based on all of the considerations described, the
EPA concludes that the costs of the controls that serve as the basis of
the standards proposed in this action are reasonable. The EPA solicits
comment on its approaches for considering control costs, as well as the
resulting analyses and conclusions.
F. Legal Basis for Rulemaking Scope
In the November 2021 proposal, the EPA described the regulatory
history of its authority to regulate methane emissions from the oil and
gas source category under CAA section 111. The EPA explained that the
2016 Rule, 81 FR 35823 (June 3, 2016), established the agency's
authority to regulate these methane emissions; the 2020 Policy Rule, 85
FR 57018 (September 14, 2020) had rescinded certain parts of the 2016
Rule, including its authorization to regulate methane; and a joint
resolution under the Congressional Review Act (CRA), signed into law by
President Biden on June 30, 2021, had rescinded the 2020 Policy Rule,
and thereby reinstated the 2016 Rule's authorization to regulate
methane. 86 FR 63135-36 (November 15, 2021).
In describing this history, the EPA noted that in the 2016 Rule, in
response to comments, the EPA had explained that once it had listed a
source category for regulation under section 111(b)(1)(A), it was not
required to make, as a predicate to regulating GHG emissions from the
source category, an additional pollutant-specific finding that those
GHG emissions contribute significantly to dangerous air pollution
(termed, a pollutant-specific significant contribution finding).
However, in the alternative, the 2016 Rule did make such a finding,
relying on information concerning the large amounts of methane
emissions from the source category. 86 FR 63135 (November 15, 2021)
(citing 81 FR 35843; June 3, 2016). The November 2021 proposal further
noted that in the legislative history of the CRA resolution, Congress
made clear its intent that section 111 did not require or authorize a
pollutant-specific significant contribution finding, and the EPA
confirmed that it agreed with that interpretation. 86 FR 63148
(November 15, 2021).
Some commenters on the November 2021 proposal reiterated the
argument that the EPA is required to make a pollutant-specific
significant contribution finding for GHG emissions from the oil and gas
source category and stated that in order to make such a finding, the
EPA must identify a standard or criteria for when a contribution is
significant.\21\ We may respond further to these comments in the final
rule, but the November 2021 proposal notes that the legislative history
of the CRA joint resolution rejected the position that a standard or
criteria is necessary for determining significance, and explained, ``It
is fully appropriate for EPA to exercise its discretion to employ a
facts-and-circumstances approach, particularly in light of the wide
range of source categories and the air pollutants they emit that EPA
must regulate under section 111.'' 86 FR 63151 (November 15, 2021)
(quoting House Report at 11). That continues to be the EPA's view and
is consistent with decades of practice under section 111. The EPA has
listed dozens of source categories, beginning in 1971,\22\ in many
cases on the basis of multiple pollutants emitted by the particular
source category,\23\ and has never identified a standard or criteria
for determining significance.
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\21\ Comments of Permian Basin Petroleum Ass'n, Document ID No.
EPA-HQ-OAR-2021-0317-0793 at 3-4 (citing 85 FR 57018, 57038
(September 14, 2020).
\22\ List of Categories of Stationary Sources, 36 FR 5931 (March
31, 1971); see 40 CFR part 60.
\23\ For example, when it listed ``stationary gas turbines'' as
a source category, EPA considered emissions of particulates,
nitrogen oxides, sulfur dioxide, carbon monoxide, and hydrocarbons.
Addition to the List of Categories of Stationary Sources, 42 FR
53657 (October 3, 1977); Standards of Performance for New Stationary
Sources: Proposed rule, 42 FR 53782, 53783 (October 3, 1977).
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If the EPA were required to develop a standard or criteria to
determine significance, any reasonable set of criteria would
necessarily focus on the amount of emissions from the source category
and the harmfulness of the pollutant emitted. In the case of the oil
and gas source category, the ``massive quantities of methane
emissions''
[[Page 74720]]
contributed by the sector to the levels of well-mixed GHG in the
atmosphere, as described in the November 2021 proposal, 86 FR 63148
(November 15, 2021), coupled with the potency of methane (with a global
warming potential (GWP) of almost 30 or more than 80, depending on the
time period of the impacts, 86 FR 63130; November 15, 2021),
demonstrate that the source category's GHG emissions would be
significant under any rational criteria-based approach. More
specifically, as the EPA stated in the November 2021 proposal, as
illustrated by the domestic and global GHGs comparison data summarized
in that notice, the collective GHG emissions from the Crude Oil and
Natural Gas source category are significant, whether the comparison is
domestic (where this sector is the largest source of methane emissions,
accounting for 28 percent of U.S. methane and 3 percent of total U.S.
emissions of all GHGs), global (where this sector, accounting for 0.4
percent of all global GHG emissions, emits more than the total national
emissions of over 160 countries, and combined emissions of over 60
countries), or when both the domestic and global GHG emissions
comparisons are viewed in combination. See 86 FR 63131 (November 15,
2021).
The large quantity of methane emitted by the oil and gas source
category is brought into sharp relief by the fact that, as the November
2021 proposal further stated, no single GHG source category dominates
on the global scale. While the Crude Oil and Natural Gas source
category, like many (if not all) individual GHG source categories,
could appear small in comparison to total emissions, in fact, it is a
very important contributor in terms of both absolute emissions, and in
comparison, to other source categories globally or within the U.S. See
86 FR 63131 (November 15, 2021).
Importantly, the oil and gas source category is the largest emitter
of methane of any source category in the United States. 86 FR 63129
(November 15, 2021). As described in the November 2021 proposal,
methane is a potent greenhouse gas; over a 100-year timeframe, it is
nearly 30 times more powerful at trapping climate warming heat than
CO2, and over a 20-year timeframe, it is 83 times more
powerful. Because methane is a powerful greenhouse gas and is emitted
in large quantities, reductions in methane emissions provide a
significant benefit in reducing near-term warming. Indeed, one third of
the warming due to GHGs that we are experiencing today is due to human
emissions of methane. See 86 FR 63129 (November 15, 2021).
The large amounts of methane emissions from the oil and gas source
category in relation to other domestic and global sources of methane,
coupled with the harmfulness of methane, should be considered more than
sufficient to satisfy any criterion or standard for evaluating
significant contribution. In particular, in the context of a problem
like climate change that is caused by the collective contribution of
many different sources, the fact that the oil and gas source category
has the largest amount of methane emissions in the United States
confirms that those emissions would meet a criterion or standard for
significance.\24\
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\24\ The EPA acknowledges that the collective nature of the
climate change problem means it will likely also be appropriate to
regulate other source categories of methane emissions that are not
necessarily as large as the oil and gas source category, cf. EPA v.
EME Homer City, 572 U.S. 489, 514 (2014) (affirming framework to
address ``the collective and interwoven contributions of multiple
upwind States'' to ozone nonattainment), as indicated by the fact
that EPA has long regulated landfill gas, which consists of methane
in 50 percent part. ``Emission Guidelines and Compliance Times for
Municipal Solid Waste Landfills; Final Rule,'' 81 FR 59276, 59281
(August 29, 2016). But this does not mean that it would be
appropriate to regulate all other types of sources, even ones with
few emissions. In the past, the EPA has declined to regulate air
pollutants emitted from source categories in quantities too small to
be worrisome and because regulation would have produced little
environmental benefit. See Nat'l Lime Ass'n. v. EPA, 627 F.2d 416,
426 & n.27 (D.C. Cir. 1980) (small amounts of emissions of nitrogen
oxides and carbon monoxide from lime kilns was a key factor in EPA
decision not to promulgate new source performance standards for
those pollutants; citing Standards of Performance for New Stationary
Sources Lime Manufacturing Plants--Proposed Rule, 42 FR 22506, 22507
(May 3, 1977)).
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G. Inflation Reduction Act
The Inflation Reduction Act (IRA) was signed into law on August 16,
2022. Section 60113 of the IRA amended the CAA by adding section 136,
``Methane Emissions and Waste Reduction Incentive Program for Petroleum
and Natural Gas Systems.'' Under this new section of the CAA,
subsection 136(c), ``Waste Emission Charge,'' requires the
Administrator to ``impose and collect a charge on methane emissions
that exceed an applicable waste emissions threshold under subsection
(f) from an owner or operator of an applicable facility that reports
more than 25,000 metric tons of carbon dioxide equivalent of greenhouse
gases emitted per year pursuant to subpart W of part 98 of title 40,
Code of Federal Regulations (40 CFR part 98), regardless of the
reporting threshold under that subpart.'' An ``applicable facility'' is
defined under CAA section 136(d) by reference to specific industry
segments as defined in the Greenhouse Gas Reporting Program (GHGRP)
petroleum and natural gas systems source category (40 CFR part 98,
subpart W, also referred to as ``GHGRP subpart W''). Pursuant to CAA
section 136(g), the charge is to be imposed and collected beginning
with respect to emissions reported for calendar year 2024 and for each
year thereafter.
CAA section 136(f) identifies several circumstances under which the
charges shall not be imposed on an owner or operator of an affected
facility. In particular, CAA section 136(f)(6)(A) states that ``charges
shall not be imposed pursuant to subsection (c) on an applicable
facility that is subject to and in compliance with methane emissions
requirements pursuant to subsections (b) and (d) of section 111 upon a
determination by the Administrator that:
(i) Methane emissions standards and plans pursuant to subsections
(b) and (d) of section 111 have been approved and are in effect in all
States with respect to the applicable facilities; and
(ii) compliance with the requirements described in clause (i) will
result in equivalent or greater emissions reductions as would be
achieved by the proposed rule of the Administrator entitled `Standards
of Performance for New, Reconstructed, and Modified Sources and
Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector
Climate Review' (86 FR 63110 (November 15, 2021)), if such rule had
been finalized and implemented.''
Per section 136(c)(6)(B) ``if the conditions in clause (i) or (ii)
of subparagraph (A) cease to apply after the Administrator has made the
determination in that subparagraph, the applicable facility will again
be subject to the charge under subsection (c) beginning in the first
calendar year in which the conditions in either clause (i) or (ii) of
that subparagraph are no longer met.''
The EPA intends to take one or more separate actions in the future
to implement the Methane Emissions and Waste Reduction Incentive
Program, including revisions to certain requirements of GHGRP subpart
W, and will provide an opportunity for public comment on the
implementation of the Methane Emissions and Waste Reduction Incentive
Program in those actions. Accordingly, the EPA considers the
implementation of the Methane Emissions and Waste Reduction Incentive
Program to be outside the scope of this supplemental proposed rule.
However, the EPA is requesting comments on the criteria and approaches
that the Administrator
[[Page 74721]]
should consider in making the CAA section 136(f)(6)(A)(ii)
determination (``IRA equivalence determination'') because the EPA
expects that the public and regulated industry will be interested in
how the scope of the final oil and gas standards and emission
guidelines may influence the applicability of the statutory exemption.
With respect to CAA section 136(f)(6)(A)(ii), the Administrator
must determine that the methane emission standards in effect pursuant
to CAA sections 111(b) and (d) ``will result in equivalent or greater
emissions reductions as would be achieved'' by the EPA's November 2021
proposed rule. As a general matter, the EPA believes that the changes
being proposed in today's action do not reduce expected methane
emission reductions relative to the November 2021 proposal. Instead,
the EPA anticipates that most, if not all, of the proposed changes
contained in this supplemental proposal would likely lead to greater
methane emissions reductions when fully implemented. For this reason,
the Agency further anticipates that promulgation of Federal and state
standards consistent with this supplemental proposal would result in
methane emissions reductions at least as great as the November 2021
proposal. However, at this point, the EPA's analysis is purely
qualitative. The EPA does not believe that it is appropriate to
quantitatively compare the emission reductions from the November 2021
proposal and this supplemental proposal because, as is discussed in
section 1.3 of the RIA, the analysis of this supplemental proposal
includes key updates to assumptions and methodologies that impact both
the baseline and policy scenarios. As such, the estimated impacts
presented in the RIA of this supplemental proposal are not directly
comparable to corresponding estimates presented in the RIA of the
November 2021 proposal.
Moreover, the statutory language in CAA section 136(f)(6)(A)(ii)
does not indicate how the EPA should conduct this equivalency
evaluation and what factors should influence how the EPA conducts the
comparison. Because of this ambiguity in the statutory language, the
EPA is requesting comments on how to best conduct this evaluation and
on factors and assumptions the EPA should consider in conducting such
an evaluation.
First, the EPA seeks comments on temporal elements of the
evaluation. The EPA believes that the appropriate temporal comparison
should be based on when requirements are fully implemented by the
sources (i.e., if a state phases in installation of zero-emitting
pneumatic controllers over more than one year, the comparison should be
made at the point that the emission guidelines require full use of
zero-emitting controllers). The EPA seeks comment on this approach
versus an alternative such as making a multi-year comparison beginning
with the effective date of the rule. In either case, as discussed
below, such a determination could be made prospectively based either on
the rule finalized by the EPA or when state plans have been approved.
As discussed in section V.D. of the supplemental proposal, the EPA is
proposing to require the submission of state plans under EG OOOOc
within 18 months after publication of the final EG. In addition, the
EPA is proposing to require that state plans impose a compliance
timeline on designated facilities to require final compliance with the
standards of performance as expeditiously as practicable, but no later
than 36 months following the state plan submittal deadline.
Second, the EPA seeks comments on geographical elements of the
evaluation. Per the statutory language in CAA section 136(f)(6)(A)(i),
the EPA's evaluation is to be done with respect to all states. The EPA
requests comments on whether we should consider making a national
evaluation of equivalency or whether we should consider a state-by-
state evaluation instead. Under a national evaluation, the EPA
envisions conducting an assessment of the reductions achieved across
all states and then evaluating those reductions collectively against
the collective reductions anticipated from implementation of the
November 2021 proposal. Under a state-by-state evaluation, the EPA
envisions needing to analyze whether every state is achieving
equivalent or greater reductions than that state would have achieved
under the November 2021 proposal.
Third, the EPA requests comments on whether the EPA should make the
evaluation and the IRA equivalency determination in advance of states
having submitted fully approvable plans or instead make the evaluation
and IRA equivalency determination at a later date once the standards of
performance pursuant to CAA section 111(b) and 111(d) are fully
promulgated (e.g., the EPA has approved state plans and/or developed a
Federal Plan). In particular, the EPA request comments on whether the
EPA's analysis should compare the November 2021 EG proposal and final
EG OOOOc by assuming designated facilities would be subject to their
corresponding EG presumptive standards once state plans are
implemented, or whether we should compare the November 2021 EG proposal
to the actual state plans that are approved. As to the latter approach,
the EPA seeks comments on how a state's invocation of RULOF to apply a
less stringent standard to a designated facility might affect the
equivalency evaluation and IRA equivalency determination. In
establishing standards of performance for individual sources, CAA
section 111(d) and the EPA's regulations provide that states may invoke
RULOF for the application of less stringent standards provided they
meet the certain requirements established in the EPA's regulations and
the EG (see section V.B.3 below). As a result, it is possible that
those state plans (individually or collectively) may not result in
equivalent or greater emissions reductions as would be achieved by full
implementation of the presumptive standards in the November 2021
proposal, unless the state plans require other sources to overperform
to compensate for the less stringent RULOF standards or the EPA's
geographical evaluation is national in scope and national emissions
result in equivalent or greater emissions reductions, even taking into
account RULOF. The EPA requests comments on whether and how to account
for the potential application of RULOF in state plans in the IRA
equivalency determination and whether it would be appropriate to
conduct any evaluation without considering the application of RULOF.
The EPA notes that nothing in the new CAA section 136 supersedes
the EPA's statutory obligations under CAA section 111. The Methane
Emission and Waste Reduction Incentive Program does not supersede the
EPA's statutory obligation, under CAA section 111, to regulate methane
emissions from the Crude Oil and Natural Gas source category. The EPA
first regulated GHG emissions from new, reconstructed, and modified
sources through limitations on methane emissions in its 2016 NSPS OOOOa
rulemaking. Therefore, the Agency is obligated to review those
standards at least every 8 years pursuant to CAA section 111(b)(1)(B).
Moreover, CAA section 111(d) requires the EPA to establish emission
guidelines to regulate methane emissions from any existing sources in
the sector to which a standard of performance would apply if it were a
new source. Although CAA section 136(f)(6) provides that facilities may
be exempted from the obligation to pay methane charges if they are
[[Page 74722]]
compliant with applicable CAA section 111(b) and (d) standards meeting
certain criteria after the Administrator makes the IRA equivalency
determination in CAA section 136(f)(6)(A), CAA section 136 does not
provide that the Methane Emission and Waste Reduction Incentive Program
may, in the alternative, serve as a compliance alternative for any
applicable CAA section 111 standards for methane. Accordingly, affected
facilities subject to the final NSPS OOOOb must continue to comply with
the final standards of performance regardless of whether they are
subject to or exempted from the waste emissions charge. Likewise,
designated facilities subject to standards of performance pursuant to
either an approved state plan or a federal plan according to the
requirements in CAA section 111(d) and the final EG OOOOc must continue
to comply with those standards regardless of whether they are subject
to or exempted from the waste emissions charge. The EPA acknowledges
the potential interplay between the provisions in this proposed rule
and the Methane Emissions and Waste Reduction Incentive Program and
invites comment on approaches for examining the economic impacts of
these programs individually and collectively.
IV. Summary and Rationale for Changes to the Proposed NSPS OOOOb and EG
OOOOc
A. Fugitive Emissions From Well Sites, Centralized Production
Facilities, and Compressor Stations
As discussed in section XI.A of the November 2021 proposal preamble
(86 FR 63169; November 15, 2021), fugitive emissions are unintended
emissions that can occur from a range of components at any time. The
magnitude of these emissions can also vary widely. The EPA has
historically addressed fugitive emissions from the Crude Oil and
Natural Gas source category through ground-based component level
monitoring using OGI or Method 21 of appendix A-7 to 40 CFR part 60
(EPA Method 21).
This section presents a summary of the November 2021 proposal, the
rationales for making certain changes to the proposed standards and
requirements, and the resulting NSPS standards and EG presumptive
standards the EPA is proposing via this supplemental proposal for
fugitive emissions from well sites and compressor stations. For
proposed standards and requirements that have not changed since the
November 2021 proposal, their supporting rationales are not reiterated
in this supplemental proposal. Rationale included in the November 2021
proposal for these standards and requirements can be found in that
proposal preamble (86 FR 63110; November 15, 2021) and in the technical
support document (TSD) for the November 2021 proposal located at (EPA-
HQ-OAR-2017-0166).
1. Fugitive Emissions at Well Sites and Centralized Production
Facilities
a. NSPS OOOOb
i. Summary of November 2021 Proposal
Affected Facility. The November 2021 proposal defined the affected
facility as the collection of fugitive emissions components located at
well sites and centralized production facilities. The November 2021
proposal excluded ``wellhead only well sites'' as affected facilities
under NSPS OOOOb, which were defined as well sites with one or more
wellheads and no major production and processing equipment. Major
production and processing equipment was defined as reciprocating or
centrifugal compressors, glycol dehydrators, heater/treaters,
separators, and storage vessels.
Definition of fugitive emissions component. The November 2021
proposal included an expanded definition of fugitive emissions
component that was intended to capture the known sources of large
emission events. Specifically, the proposed definition in the November
2021 proposal defined a fugitive emissions component as ``any component
that has the potential to emit fugitive emissions of methane and VOC at
a well site or compressor station, including valves, connectors,
pressure relief devices, open-ended lines, flanges, all covers and CVS,
all thief hatches or other openings on a controlled storage vessel,
compressors, instruments, meters, natural gas-driven pneumatic
controllers, or natural gas-driven pneumatic pumps. However, natural
gas discharged from natural gas-driven pneumatic controllers or natural
gas-driven pumps are not considered fugitive emissions if the device is
operating properly and in accordance with manufacturers specifications.
Control devices, including flares, with emissions resulting from the
device operating in a manner that is not in full compliance with any
Federal rule, state rule, or permit, are also considered fugitive
emissions components.'' (86 FR 63170; November 15, 2021).
Summary of November 2021 Proposal BSER Analysis. The methodology
used to determine BSER for the November 2021 proposal was presented in
the section X.II.A of that proposal preamble (86 FR 63186; November 15,
2021). In the November 2021 proposal, the EPA proposed new work
practice standards for the collection of fugitive emissions components
located at well sites. The EPA proposed that well sites with total
site-level baseline methane emissions less than 3 tpy would
demonstrate, based on a one-time site-specific survey, that actual
emissions are reflected in the baseline methane emissions calculation.
For well sites with total site-level baseline methane emissions of 3
tpy or greater, the EPA proposed quarterly OGI or EPA Method 21
monitoring. The EPA also co-proposed an alternative set of work
practice standards: for well sites with total site-level baseline
methane emissions of 3 tpy or greater and less than 8 tpy semiannual
OGI or EPA Method 21 monitoring would apply; and for well sites with
total site-level baseline methane emissions of 8 tpy or greater,
quarterly OGI or EPA Method 21 monitoring would apply. For sites using
OGI to detect fugitive emissions under any of these proposed work
practice standards, the EPA proposed that surveys would be conducted
according to the procedures proposed as appendix K. See section VI of
this preamble for more information regarding appendix K.
ii. Changes to Proposal and Rationale
The EPA is proposing certain changes to the November 2021 proposal
standards for NSPS OOOOb. Specifically, the EPA is proposing: (1) To
require OGI monitoring for well sites and centralized production
facilities following the monitoring plan required in proposed 40 CFR
60.5397b instead of requiring the procedures being proposed in appendix
K for these sites; (2) to expand the affected facility definition to
include wellhead only well sites, which were previously exempt, and add
a subcategory for small well sites; (3) to revise the definition of
fugitive emissions component; (4) to require periodic AVO or other
detection methods for all well sites and centralized production
facilities (except those located on the Alaskan North Slope) at
frequencies based on the subcategory of well site; (5) to require
periodic OGI fugitive emissions monitoring based on the number and type
of equipment located at the well site, in lieu of the baseline
emissions calculations required in the November 2021 proposal; and (6)
to include requirements for well closures that would indicate when
fugitive emissions monitoring could stop.
Appendix K. The EPA is not including a requirement to conduct OGI
[[Page 74723]]
monitoring according to the proposed appendix K for well sites or
centralized production facilities, as was proposed in the November 2021
proposal. Instead, the EPA is proposing to require OGI surveys
following the procedures specified in the proposed regulatory text for
NSPS OOOOb (at 40 CFR 60.5397b) or according to EPA Method 21. The EPA
received extensive comments \25\ from oil and gas operators and other
groups on the numerous complexities associated with following the
proposed appendix K, especially considering the remoteness and size of
many of these sites. In addition, commenters pointed out that OGI has
always been the BSER for fugitive monitoring at well sites and was
never designed as a replacement for EPA Method 21, while appendix K was
designed for use at more complex processing facilities that have
historically been subject to monitoring following EPA Method 21. The
EPA agrees with the commenters and is proposing requirements within
NSPS OOOOb at 40 CFR 60.5397b in lieu of the procedures in appendix K
for fugitive emissions monitoring at well sites or centralized
production facilities. See section VI of this preamble for additional
information on what the EPA is proposing for appendix K related to
other sources (e.g., natural gas processing plants).
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\25\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0579, EPA-HQ-OAR-
2021-0317-0743, EPA-HQ-OAR-2021-0317-0764, EPA-HQ-OAR-2021-0317-
0777, EPA-HQ-OAR-2021-0317-0782, EPA-HQ-OAR-2021-0317-0786, EPA-HQ-
OAR-2021-0317-0793, EPA-HQ-OAR-2021-0317-0802, EPA-HQ-OAR-2021-0317-
0807, EPA-HQ-OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-0810, EPA-HQ-
OAR-2021-0317-0814, EPA-HQ-OAR-2021-0317-0817, EPA-HQ-OAR-2021-0317-
0820, EPA-HQ-OAR-2021-0317-0831, EPA-HQ-OAR-2021-0317-0834, and EPA-
HQ-OAR-2021-0317-0938.
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Affected facility and subcategorization of well sites. The EPA is
proposing to expand the affected facility definition to include the
collection of fugitive emissions components at all well sites,
including the previously excluded wellhead only well sites. Various
studies, including a recent U.S. Department of Energy funded study on
quantifying methane emissions from marginal wells,\26\ demonstrate that
fugitive emissions do occur from wellheads, and in some cases can be
significant. As discussed in detail later in this section, the EPA
evaluated emissions reductions resulting from the implementation of a
fugitive emissions monitoring and repair program for a range of well
site and centralized production facility configurations, ranging from
the single wellhead only well site, to sites with specific major
production and processing equipment present. While different types of
monitoring techniques were found appropriate at the various site
configurations evaluated, the EPA did not find support for an exemption
of any site from the standards. Therefore, the EPA is proposing to
define the affected facility as the collection of fugitive emissions
components located at a well site or centralized production facility
with no exemptions.
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\26\ Bowers, Richard L. Quantification of Methane Emissions from
Marginal (Low Production Rate) Oil and Natural Gas Wells. United
States. https://doi.org/10.2172/1865859.
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Further, the EPA is proposing monitoring and repair programs
specific to four distinct subcategories of well sites: (1) Single
wellhead only well sites,\27\ (2) wellhead only well sites with two or
more wellheads, (3) well sites and centralized production facilities
\28\ with major production and processing equipment, and (4) small well
sites. The third subcategory includes well sites and centralized
production facilities that have: (1) One or more controlled storage
vessels, (2) one or more control devices, (3) one or more natural gas-
driven pneumatic controllers or pumps, or (4) two or more other major
production and processing equipment. The fourth subcategory, small well
sites, are single wellhead well sites that do not contain any
controlled storage vessels, control devices, pneumatic controller
affected facilities, or pneumatic pump affected facilities, and include
only one other piece of major production and processing equipment.
Major production and processing equipment that would be allowed at a
small well site would include a single separator, glycol dehydrator,
centrifugal and reciprocating compressor,\29\ heater/treater, and
storage vessel that is not controlled. By this definition, a small well
site could only potentially contain a well affected facility (for well
completion operations or gas well liquids unloading operations that do
not utilize a CVS to route emissions to a control device) and a
fugitive emissions components affected facility. No other affected
facilities, including those utilizing CVS (such as pneumatic pumps
routing to control) can be present for a well site to meet the
definition of a small well site. The proposed monitoring requirements
for each of these subcategories is described in more detail later in
this section.
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\27\ The EPA defines a wellhead only well site as a well site
that contains one or more wellheads and no major production and
processing equipment.
\28\ Centralized production facilities include one or more
storage vessels and all equipment at a single surface site used to
gather, for the purpose of sale or processing to sell, crude oil,
condensate, produced water, or intermediate hydrocarbon liquid from
one or more offsite natural gas or oil production wells. This
equipment includes, but is not limited to, equipment used for
storage, separation, treating, dehydration, artificial lift,
combustion, compression, pumping, metering, monitoring, and
flowline. Process vessels and process tanks are not considered
storage vessels or storage tanks. A centralized production facility
is located upstream of the natural gas processing plant or the crude
oil pipeline breakout station and is a part of producing operations.
\29\ The EPA is proposing to exclude compressors that are
located at well sites from the definition of a centrifugal affected
facility and reciprocating affected facility, consistent with the
November 2021 proposal. See 86 FR 63180 (November 15, 2021).
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Definition of fugitive emissions component. The EPA is proposing
specific revisions to the definition of fugitive emissions component
that was included in the November 2021 proposal. First, the EPA is
proposing to add yard piping as one of the specifically enumerated
components in the definition of a fugitive emissions component. While
not common, pipes can experience cracks or holes, which can lead to
fugitive emissions. The EPA is proposing to include yard piping in the
definition of fugitive emissions component to ensure that when fugitive
emissions are found from the pipe itself the necessary repairs are
completed accordingly.
Second, the EPA is correcting an error made in the November 2021
proposal. The EPA had proposed that all thief hatches and other
openings on all controlled storage vessels would be considered fugitive
emissions components. This definition inadvertently included storage
vessels that would already be subject to control as storage vessel
affected facilities/designated facilities, including regular
inspections of thief hatches and other sources of fugitive emissions
that are separately required as part of the proposed standards for
storage vessel affected facilities/designated facilities (see section
IV.I of this preamble). The EPA is correcting that error in this
supplemental proposal to avoid establishing redundant or duplicative
requirements. Instead, the EPA is defining fugitive emissions
components to include all thief hatches and other openings on storage
vessels that are constructed, reconstructed, or modified after November
15, 2021, and not also subject to control as storage vessel affected
facilities. This would include thief hatches and other openings on both
uncontrolled storage vessels and storage vessels that are controlled
for other purposes but not subject to NSPS OOOOb control requirements
because fugitive emissions can occur from these components.
Third, the EPA is not defining control devices as fugitive
emissions
[[Page 74724]]
components. One commenter stated that emissions resulting from
noncompliance with control device requirements should not also be
defined as fugitive emissions.\30\ This commenter opined that since
control devices are inherently designed to have emissions, even when
well operated, it should be expected that some amount of methane and
VOC would be detected during an OGI survey for fugitive emissions. The
EPA agrees that control devices should not be treated as fugitive
emissions components and is therefore revising the definition in this
proposal to not include those devices. Further, as discussed in more
detail in section IV.H of this preamble, the EPA anticipates that
control devices are used to meet at least one of the emissions
standards in the proposed rules, and as such, they would be subject to
the control device requirements in NSPS OOOOb or EG OOOOc. See section
IV.H of this preamble for additional discussion on proposed
requirements specific to control devices.
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\30\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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Finally, the EPA is not maintaining the inclusion of natural gas-
driven pneumatic controllers or natural gas-driven pneumatic pumps as
fugitive emissions components. These devices are both separate affected
facilities with separate standards identified as BSER.\31\ See sections
IV.D and IV.E of this preamble for information about the proposed BSER
for natural gas-driven pneumatic controllers and natural gas-driven
pneumatic pumps, respectively.
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\31\ As explained in sections IV.D for pneumatic controllers and
IV.E for pneumatic pumps, only natural gas-driven pneumatic
controllers and pumps are defined as affected facilities. For a
controller or pump to not be an affected facility, it would need to
be electric or solar, which would not have the potential to emit
methane or VOC emissions. Therefore, the EPA does not consider
pneumatic controllers or pneumatic pumps part of the fugitive
emissions components when they are not affected facilities as
controllers or pumps.
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The EPA is proposing specific requirements throughout this
supplemental proposal that will address emissions from controlled
storage vessels and natural gas-driven pneumatic controllers and pumps,
including requirements for quarterly OGI monitoring. These monitoring
requirements provide compliance assurance that the proposed performance
standards for these sources are being complied with and obviate any
need to include these sources in the definition of a fugitive emissions
component. For control devices, the EPA is proposing additional initial
and continuous compliance measures to ensure the required emissions
reductions are being achieved. See sections IV.D for discussion on
pneumatic controllers, IV.E for discussion on pneumatic pumps, IV.H for
discussion on combustion control devices, IV.J for discussion on
storage vessels, and IV.K for discussion on covers and CVS.\32\
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\32\ The EPA notes quarterly OGI monitoring will also be
performed to demonstrate compliance with specific standards for
controlled storage vessels, natural gas-driven pneumatic
controllers, natural gas-driven pneumatic pumps, and CVS associated
with any affected facilities at well sites. This quarterly OGI
monitoring would take place during the same quarterly OGI monitoring
of the fugitive emissions components affected facility located at
the same well site.
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Comments received on monitoring requirements. As discussed in the
November 2021 proposal, the EPA proposed to require fugitive emissions
monitoring using OGI based on the site-level methane baseline
emissions, as determined, in part, through equipment and component
count emissions factors. Further, the EPA solicited comment on adding
routine AVO monitoring in addition to periodic OGI monitoring to help
identify potential large emission events. Several comments, mostly from
small businesses, were received regarding the use of AVO inspections
because these are low cost and simple inspections that would identify
indications of leaks, such as open thief hatches on storage vessels.
These comments ranged from requiring monthly to annual AVO inspections
in lieu of OGI monitoring, to requests to minimize the complexity of
any associated recordkeeping and reporting requirements should the EPA
require this type of inspection.\33\
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\33\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0585, EPA-HQ-OAR-
2021-0317-0814, EPA-HQ-OAR-2021-0317-0822, EPA-HQ-OAR-2021-0317-
0929, and EPA-HQ-OAR-2021-0317-0935.
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The EPA received substantive comments from several commenters on
the November 2021 proposal regarding OGI monitoring arguing that the
proposed requirements for well sites were unreasonable and would be
difficult to implement, especially for well sites with total site-level
baseline methane emissions less than 3 tpy. Specifically, these
commenters \34\ asserted that there would be challenges around
calculating the site-level baseline emissions and that this task would
be burdensome, while other commenters \35\ asserted the calculations
would result in no regular monitoring at sites that have leak-prone
equipment. Further, commenters noted that it would be difficult to
verify the emissions calculations, which could result in compliance
and/or enforcement challenges. According to industry commenters,\36\
the requirement to repeat the calculation when equipment is added or
removed from the site would be especially burdensome. One of the
commenters further stated this requirement would force owners and
operators to constantly maintain an inventory of equipment, with some
operators carrying this burden for hundreds to thousands of sites.\37\
Moreover, the commenter indicated that the EPA has not explained the
need for the proposed recalculation of site-level methane emissions
based on equipment changes and how this would have an environmental
benefit. Another commenter argued that the EPA did not properly explain
the basis for the emissions thresholds and disagreed with the
components and equipment included in the calculation, as well as the
use of the GHGRP emissions factors.\38\
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\34\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808 and EPA-HQ-
OAR-2021-0317-0814.
\35\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
\36\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808 and EPA-HQ-
OAR-2021-0317-0814.
\37\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
\38\ See Document ID No. EPA-HQ-OAR-2021-0317-0814.
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In response to the proposed site-specific survey to demonstrate
that actual emissions are reflected in the baseline emissions
calculation, some commenters asserted that well sites with emissions
less than 3 tpy should not be exempt from regular monitoring. According
to commenters, even small sites can have leaks with significant
emissions.\39\ For this reason, the commenters made the case that
regular monitoring should be required for all sites. Some commenters
also expressed that the requirement to calculate site-level methane
baseline emissions and conduct an initial survey was confusing. As
explained by one commenter, ``[the] EPA states well sites with site-
level baseline methane emissions [less than] 3 tpy are not required to
conduct OGI monitoring.'' \40\ See 86 FR 63171 (November 15, 2021);
however, since the EPA also proposed that well sites would be required
to perform a survey to confirm that the actual emissions are less than
3 tpy, the commenter viewed this as a contradiction within the rule,
thus making it unclear what the EPA was proposing.
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\39\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0568, EPA-HQ-OAR-
2021-0317-0769, EPA-HQ-OAR-2021-0317-0844, and EPA-HQ-OAR-2021-0317-
1267.
\40\ See Document ID No. EPA-HQ-OAR-2021-0317-0727.
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One commenter indicated that monitoring should also be required for
[[Page 74725]]
wellhead only well sites because, even though less equipment (and so
fewer components) is present at a wellhead only well site, the wellhead
itself is a source of emissions, which should be inspected for fugitive
emissions.\41\ Other commenters provided similar comments and urged the
EPA to remove the exemption for wellhead only well sites because these
well sites have other smaller equipment that leaks and
malfunctions,\42\ with large emissions having been observed from these
sites,\43\ even though these sites do not have major production and
processing equipment. Further, commenters noted that well sites with
equipment with potentially significant emissions should not be
considered a wellhead only well site or excluded from regular
monitoring. The commenter urged the EPA that, if the wellhead only well
site exemption is retained, it must only apply to single wellhead
sites. Even if no associated equipment is located at a wellhead only
well site, sites with multiple wellheads can have a number of
components and subsequently potential sources of fugitive
emissions.\44\ This same commenter, who opposes the 3 tpy threshold,
noted that ``failure prone equipment'' such as storage vessels,
separators, flares, and natural gas-driven pneumatic controllers often
operate incorrectly and can cause significant emissions.\45\ This
commenter argued that sites with this type of equipment should be
required to monitor on a frequent basis.
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\41\ See Document ID No. EPA-HQ-OAR-2021-0317-0769.
\42\ See Document ID No. EPA-HQ-OAR-2021-0317-0586.
\43\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
\44\ Id.
\45\ Id.
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Another commenter noted that the one-time survey for sites less
than 3 tpy does not address the problem of future leaks or
malfunctions.\46\ The commenter indicated that malfunctions account for
a large amount of methane emissions and the commenter, therefore,
recommended at least annual monitoring. Comments urging the EPA to
exempt small, low producing wells were also received.\47\ Specifically,
one commenter argued that low producing wells are not
disproportionately large emitters.\48\ This commenter asked that the
EPA exempt these wells, asserting that these sources can least afford
monitoring and have relatively small emissions. The commenter further
asked that the rule exempt wells defined by states as stripper wells.
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\46\ See Document ID No. EPA-HQ-OAR-2021-0317-1267.
\47\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0425 and EPA-HQ-
OAR-2021-0317-0814.
\48\ See Document ID No. EPA-HQ-OAR-2021-0317-0425.
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As illustrated by the comments, which specifically highlight many
potential challenges related to implementation, compliance assurance,
and efficacy in reducing emissions, the EPA agrees that the fugitive
emissions monitoring program that was proposed in the November 2021
proposal should be clarified and improved in order to address the
issues identified by the various commenters. As explained below, after
considering the comments, additional data, and a revised analysis, the
EPA is proposing revised fugitive emissions applicability criteria,
monitoring frequencies, and detection methods at well sites and
centralized production facilities.
Fugitive emissions monitoring and repair modeling. In the November
2021 proposal, the EPA also solicited comment on other thresholds that
could be used to set monitoring requirements for well sites, in lieu of
using self-reported baseline emissions as a threshold. One of these
options included an equipment-based approach, in which well sites with
specific leak-prone equipment would have one set of requirements, while
well sites with other equipment (or that lack leak-prone equipment)
would have a different set of requirements. In comparison to a self-
reported baseline emissions threshold, such an approach would ensure
routine OGI monitoring takes place at sites that have equipment that is
most likely to have fugitive emissions more frequently, while also
being more straightforward for owners and operators to implement and
for the EPA and state regulators to verify and enforce. The EPA
received feedback and additional information in response to this
solicitation and used that information to develop a new analysis based
on this equipment-based concept.
To evaluate an equipment-based program, the EPA developed three
distinct model plants. These model plants were designed to account for
various equipment types located at sites and ranged from single
wellhead only well sites to complex sites with various known sources of
large emissions present. Specifically, these model plants include: (1)
Single wellhead only well sites,\49\ (2) wellhead only well sites with
two or more wellheads, and (3) well sites or centralized production
facilities \50\ with major production and processing equipment. For the
reasons explained later in this section, the EPA finds that small well
sites have component counts, and thus emissions distributions, that are
more comparable to single wellhead only well sites and less than multi-
wellhead only well sites. The EPA has not modeled this small well site
subcategory. Fugitive emissions from small well sites would originate
from the same types of components (e.g., valves, connectors, open-ended
lines, or pressure relief devices) modeled with emissions for single
wellhead only well sites, and the available data suggests that the
single piece of equipment at the site would be of smaller size, and
thus have fewer individual components, than those summarized for well
sites and centralized production facilities with major production and
processing equipment. However, for purposes of summarizing the
component counts, the EPA is including small well sites in Table 7
along with the details of the number and type of equipment included in
each of the model plants used for emissions modeling. The EPA finds
that evaluating several types of model plants based on equipment and
component counts is consistent with the empirical literature on
fugitive emissions, including the conclusion from the U.S. Department
of Energy's (DOE) recent marginal well study that a strong correlation
was observed between the major equipment count and the frequency of
fugitive emissions.51 52 The
[[Page 74726]]
EPA is soliciting comment on the proposed model plants described in
Table 7. The EPA is also seeking information on how to refine its
approach to modeling fugitive emissions in the model plants developed
for this analysis.
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\49\ The EPA defines a wellhead only well site as a well site
that contains one or more wellheads and no major production and
processing equipment. Major production and processing equipment
includes reciprocating or centrifugal compressors, glycol
dehydrators, heater/treaters, separators, and storage vessels
collecting crude oil, condensate, intermediate hydrocarbon liquids,
or produced water. The EPA does not consider meters and yard piping
as major production and processing equipment for purposes of
determining if a well site is a wellhead only well site.
\50\ Centralized production facilities include one or more
storage vessels and all equipment at a single surface site used to
gather, for the purpose of sale or processing to sell, crude oil,
condensate, produced water, or intermediate hydrocarbon liquid from
one or more offsite natural gas or oil production wells. This
equipment includes, but is not limited to, equipment used for
storage, separation, treating, dehydration, artificial lift,
combustion, compression, pumping, metering, monitoring, and
flowline. Process vessels and process tanks are not considered
storage vessels or storage tanks. A centralized production facility
is located upstream of the natural gas processing plant or the crude
oil pipeline breakout station and is a part of producing operations.
\51\ Bowers, Richard L. Quantification of Methane Emissions from
Marginal (Low Production Rate) Oil and Natural Gas Wells. United
States. https://doi.org/10.2172/1865859.
\52\ The U.S. DOE marginal well study did not collect
information on individual component counts on major equipment but
did find a strong correlation to emissions based on the size of the
site (defined by the major equipment count). Thus, the proposed
definition of a small well site is limited to inclusion of a single
piece of specific major production and processing equipment.
Table 7--Well Site Model Plant Component Counts
----------------------------------------------------------------------------------------------------------------
Number of components at well site
---------------------------------------------------------------
Major equipment at well site Count Open ended Pressure
Valves Connectors lines relief valves
----------------------------------------------------------------------------------------------------------------
Single Wellhead Only Well Sites
----------------------------------------------------------------------------------------------------------------
Gas Wellheads................... 1 10 38 1 0
Meter/Piping.................... 1 13 48 1 1
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Total # of Components:...... 112
----------------------------------------------------------------------------------------------------------------
Small Well Sites
----------------------------------------------------------------------------------------------------------------
Gas Wellheads................... 1 10 38 1 0
Meter/Piping.................... 1 13 48 1 1
Other Equipment \a\............. 1 9 34 1 1
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Total # of Components:...... 157
----------------------------------------------------------------------------------------------------------------
Wellhead Only Well Sites with Two or More Wellheads
----------------------------------------------------------------------------------------------------------------
Gas Wellheads................... 2 19 75 2 0
Meter/Piping.................... 2 26 96 1 1
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Total # of Components:...... 220
----------------------------------------------------------------------------------------------------------------
Well Sites and Centralized Production Facilities with Major Production and Processing Equipment
----------------------------------------------------------------------------------------------------------------
Gas Wellheads................... 2 19 75 2 0
Meter/Piping.................... 2 26 96 1 1
Separators...................... 2 44 137 8 3
In-Line Heaters................. 1 14 65 2 1
Dehydrators..................... 1 24 90 2 2
Storage Vessel Thief Hatch...... 1 0 0 0 0
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Total # of Components:...... 612
----------------------------------------------------------------------------------------------------------------
\a\ Major production and processing equipment that could be at a small well site includes compressors, glycol
dehydrators, heater/treaters, separators, and uncontrolled storage vessels collecting crude oil, condensate,
intermediate hydrocarbon liquids, or produced water. Small well sites cannot include one or more controlled
storage vessels, control device, natural gas-driven pneumatic controllers, or natural gas-driven pneumatic
pumps. The component counts provided in this table are based on the average number of valves identified in
industry provided data for a small well site (34 valves) and assuming 3.8 connectors per valve, 1 open-ended
line, and 1 pressure relief device consistent with component counts provided for other equipment.\53\
In previous rulemakings, the EPA used component-level emissions
factors that commenters on previous actions have stated are dated and
not reflective of emissions detected through various recent measurement
studies to determine baseline emissions and emissions reductions at
various OGI monitoring frequencies.\54\ In contrast, several comments
on the November 2021 proposal identified various modeling simulation
tools that can be utilized for this same purpose and that build in
emissions data from various emissions measurement campaigns providing
empirical emissions data.
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\53\ See Document ID No. EPA-HQ-OAR-2017-0483-1006.
\54\ See EPA Responses to Public Comments on Reconsideration of
New Source Performance Standards (NSPS) Oil and Natural Gas Sector:
Emission Standards for New, Reconstructed, and Modified Sources
Reconsideration 40 CFR part 60, subpart OOOOa, located at Document
ID No. EPA-HQ-OAR-2017-0483-2291.
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One such modeling simulation tool is the Fugitive Emissions
Abatement Simulation Toolkit (FEAST). FEAST is an open-source modeling
framework developed to evaluate the effectiveness of fugitive emissions
programs at oil and gas facilities by simulating various scenarios of
leaks (and subsequent repairs) occurring over time using an empirical
leak dataset according to a randomized process. FEAST supports a
variety of detection technologies, including OGI, aerial surveys, drone
surveys, and continuous monitoring systems and can model hybrid
programs (e.g., aerial surveys followed by ground-level OGI surveys).
The effects of fugitive emissions monitoring and repair are simulated
based on probability of detection (PoD) curves (or surfaces) for each
monitoring method, which indicate the probability that a leak of a
given size will be detected within a given survey (or time period for
continuous monitoring technologies), and survey times (frequencies) are
accounted for as finite time periods. The emissions present at the site
during the modeled period of time are quantified, accounting for leak
generation, identification, and repair, and emissions reductions can be
calculated by comparing the simulated fugitive emissions program
against a baseline scenario where no program is implemented.
The EPA recognizes there are several options to identify fugitive
emissions,
[[Page 74727]]
ranging from simple sensory methods to advanced detection technologies.
The EPA solicited comment on the inclusion of simple AVO checks that
could be performed in conjunction with periodic OGI monitoring surveys
to identify large emissions between OGI monitoring surveys in the
November 2021 proposal. The EPA maintains that it is imperative to
ensure that well sites and centralized production facilities are
operated in a manner such that emissions are minimized. Further, OGI or
other detection technologies are not necessary for identifying fugitive
emissions from certain fugitive emissions components, such as open
thief hatches. Therefore, the EPA examined the use of regular AVO
inspections to provide for potential additional emissions reductions
associated with fugitive emissions components, and to compel operators
to address issues whenever they find indications of a potential leak
during regular visits to sites.
One factor that can lead to fugitive emissions is a lack of
maintenance, and it has been shown that when sites are not regularly
visited, fugitive emissions can occur for long periods of time without
any mitigation. For example, in comments provided on the October 15,
2018 proposed reconsideration for NSPS OOOOa, it was reported that some
sites can be operating in a state of disrepair, including rusty well
shafts, broken valves, or fallen trees on equipment.\55\ While OGI and
other monitoring technologies can be useful in identifying emissions
from individual components, such as valves and connectors, these
technologies require expensive equipment and specialized training of
operators for identifying indications of fugitive emissions resulting
from broken equipment or open thief hatches. On the other hand, AVO
inspections are a useful tool for identifying when there are
indications of a potential leak without the need for expensive
equipment or specialized training of operators. For example, at sites
that lack extensive background noise, a person would be able to hear if
a high-pressure leak is present, which could present as a hissing
sound. Field gas produced at well sites contains a mixture of methane
and various VOCs, which have the potential to be detected by smell.
Where the field gas contains a lot of condensate or other produced
liquids, any resulting leaks would present as indications of liquids
dripping or potentially puddles forming on the ground. In cold
climates, ice formation on components could also indicate a potential
leak. Finally, an open thief hatch on a storage vessel is easily
identified with visual inspection.
---------------------------------------------------------------------------
\55\ See Document ID No. EPA-HQ-OAR-2017-0483-2240.
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The EPA is proposing a revised approach to address fugitive
emissions at well sites and centralized production facilities that
establishes the monitoring frequency and detection method (AVO and/or
OGI) based on results obtained from using FEAST \56\ to model various
programs at the three model plants presented in this preamble. First,
the EPA determined baseline methane emissions from each of the model
plants using two leak generation rates, 0.5 and 1.0 percent. These leak
generation rates represent the percentage of components leaking at any
particular time at the site. The EPA chose these leak generation rates
as a starting point for modeling to compare against measured emissions
documented in credible empirical studies, such as the August 2021 paper
by Rutherford, et al.\57\ This proposed approach is responsive to
feedback from commenters indicating that the emissions factors we
relied upon in the November 2021 proposal undercount fugitive
emissions, and recommending that we utilize models based on recent
measured data that is more representative of fugitive emissions in the
field. The results of the FEAST simulations for AVO and OGI monitoring
are presented in the remainder of this section for each of the model
plants. For ground based OGI, the EPA used a minimum detection limit of
60 g/hr consistent with the proposed camera specifications in 40 CFR
60.5397b(c)(7)(i)(B) \58\ and assumed all leaks identified by OGI would
be repaired within 30 days, consistent with the average repair time
that would be required for fugitive emissions components.\59\ The
results of these models provide an estimate of the number of leaks
identified during an inspection and the potential emissions reductions,
which the EPA then applied to its cost-effectiveness analysis to
determine the BSER for each well site model plant. The EPA is seeking
information on its estimates of repair costs associated with identified
leaks.
---------------------------------------------------------------------------
\56\ The EPA used FEAST version 3.1 to model the various
programs. While the EPA used FEAST in this modeling exercise, the
EPA would expect other available modeling simulation tools to
produce similar results.
\57\ Rutherford, J.S., Sherwin, E.D., Ravikumar, A.P. et al.
Closing the methane gap in US oil and natural gas production
emissions inventories. Nat Commun 12, 4715 (2021). https://doi.org/10.1038/s41467-021-25017-4.
\58\ The EPA is adopting the same OGI camera specifications for
fugitive emissions components as those in NSPS OOOOa.
\59\ The EPA is proposing to require a first attempt at repair
within 30 days of identifying fugitive emissions, with final repair
required within 30 days of the first attempt.
---------------------------------------------------------------------------
For purposes of evaluating the costs of the AVO inspections and OGI
monitoring surveys, the EPA incorporated specific revisions into the
cost analysis presented in the November 2021 proposal.\60\ The capital
and annual costs associated with each type of inspection or monitoring
program are presented in Tables 8 and 9.
---------------------------------------------------------------------------
\60\ See November 2021 TSD for additional information on costs
of OGI monitoring at Document ID No. EPA-HQ-OAR-2021-0317-0166.
Table 8--Well Site Model Plant Costs Associated With OGI Monitoring
------------------------------------------------------------------------
Description of item Costs ($)
------------------------------------------------------------------------
Capital Costs for OGI Inspections
------------------------------------------------------------------------
Read rule and instructions (per 22 well $260.
sites).
Develop monitoring plan (per 22 well sites) $2,600.
Setup recordkeeping system (per well site). $900.
------------------------------------------------------------------------
Costs for OGI Inspections (per well site)
------------------------------------------------------------------------
OGI surveys................................ $142/hr.
Repairs.................................... $146 to $330/yr.
Resurvey................................... $3 to $20/yr.
Annual licensing fees of recordkeeping $870/yr.
system.
Annual administrative costs for $325/yr.
recordkeeping/data management.
[[Page 74728]]
Prepare and submit information in annual $195/yr.
report.
------------------------------------------------------------------------
Table 9--Well Site Model Plant Costs Associated With AVO Inspections
(Assumes No OGI Monitoring)
------------------------------------------------------------------------
Description of item Costs ($)
------------------------------------------------------------------------
Capital Costs for AVO Inspections
------------------------------------------------------------------------
Read rule and instructions (per 22 well $260.
sites).
Develop monitoring plan (per 22 well sites) $260.
Setup recordkeeping system (per well site). $65.
------------------------------------------------------------------------
Costs for AVO Inspections (per well site)
------------------------------------------------------------------------
AVO inspection, including preparation and $65/hr.
documentation.
Repairs.................................... $89/yr to $178/yr.
Resurvey................................... $5/yr to $11/yr.
Prepare and submit information in annual $65/yr.
report.
------------------------------------------------------------------------
For OGI monitoring at well sites, the capital costs presented in
Table 8 remain unchanged from the November 2021 proposal. The capital
costs associated with the fugitive emissions program are expected to be
the same for each model plant because these capital costs include the
cost of developing a fugitive emission monitoring plan and purchasing
or developing a recordkeeping data management system specific to
fugitive emissions monitoring and repair. More discussion about the
capital costs, which remain unchanged in this proposal, can be found in
section XII.A.1.a of the November 2021 proposal (86 FR 63189; November
15, 2021).
When evaluating the annual costs of the fugitive emissions
monitoring and repair requirements (i.e., monitoring, repair, repair
verification, data management licensing fees, recordkeeping, and
reporting), the EPA considers costs at the individual site level.
Estimates for these costs for OGI monitoring were mostly retained and
consistent with the November 2021 proposal. However, the EPA
incorporated the results of FEAST modeling for the newly developed
model plants to include the modeled number of components identified as
leaking, thus requiring repairs.\61\ Even though the leak generation
rate used in the FEAST model was set to 0.5 and 1.0 percent for
purposes of emissions reduction analyses, the empirical dataset used
includes all leaks measured across numerous studies, many of which are
below the expected mass detection limit of OGI cameras. As such, only a
portion of the leaks generated are identified and repaired via the OGI
monitoring program (approximately 57 percent in this analysis).
Specifically, the estimated annual number of components requiring
repair resulting from an OGI survey, as modeled by FEAST, were 0.62 for
single wellhead only and small well sites, 1.25 for multi-wellhead only
well sites, and 3.7 for well sites and centralized production
facilities with major production and processing equipment. The EPA
utilized the same repair costs and resurvey costs as in the November
2021 proposal for OGI monitoring. All other inputs to the annual costs
remain unchanged from the November 2021 proposal as well.
---------------------------------------------------------------------------
\61\ Assumes an average of 0.62, 1.25, and 3.7 leaks found
annually, for model plants 1-3, respectively.
---------------------------------------------------------------------------
The estimated annual costs of the OGI-based fugitive emissions
program at well sites and centralized production facilities range from
$2,100 for annual monitoring to $6,000 for monthly monitoring for
single wellhead only well sites. For multi-wellhead only well sites,
the estimated annual costs of the fugitive emissions program range from
$2,000 for annual monitoring to $5,900 for monthly monitoring. For well
sites with major production and processing equipment, including those
with controlled tanks, the estimated annual costs of the fugitive
emissions program are estimated to range from $2,300 for annual
monitoring to $7,000 for monthly monitoring. More detailed information
on the capital and annual costs estimated for the fugitive emissions
program can be found in the November 2021 TSD \62\ and in the
Supplemental TSD for this action located at Docket ID No. EPA-HQ-OAR-
2021-0317.
---------------------------------------------------------------------------
\62\ See Document ID No. EPA-HQ-OAR-2021-0317-0166.
---------------------------------------------------------------------------
For this supplemental proposal, the EPA separately evaluated the
costs associated with AVO monitoring. The EPA assumed capital and
annual costs for each individual well site and evaluated the costs in
two ways: (1) Assuming an operator visits the site at least as
frequently as the inspection (no additional travel costs), and (2)
assuming additional travel costs because the site is not visited at the
same frequency as the inspection. When accounting for the second
scenario, the EPA assumed a travel time of 1.25 hours round trip and
applied the same hourly rate for operators as is used for the
development of a monitoring plan and other actions. Further, the EPA
assumes an inspection time ranging from 15 minutes (single wellhead
only well sites) to 1 hour (centralized production facilities) to
account for the added complexity at larger sites. The EPA also assumed
1 repair per year for the single wellhead only, multi-wellhead only,
and small well sites, and 2 repairs per year for larger well sites and
centralized production facilities. While there is a lack of information
on the emissions reductions achieved through an AVO inspection, the EPA
is confident that specific indications of potential leaks (e.g., open
valves or thief hatches) would be obvious to any operator performing
these inspections and discusses these in more detail below for each
model plant.
The estimated annual costs of the AVO inspections at single
wellhead only well sites and small well sites that are visited at least
as frequently as the
[[Page 74729]]
AVO inspection frequency range from $214 for annual inspections to $660
for monthly inspections. These estimates range from $300 for annual
inspections to $1,630 for monthly inspections if additional travel
costs are incorporated for these sites. For multi-wellhead only well
sites, the estimated annual costs range from $265 for annual
inspections to $1,150 for monthly inspections, and these costs range
from $350 for annual inspections to $2,120 for monthly inspections when
additional travel costs are added. For well sites with major production
and processing equipment, the estimated annual costs range from $480
for annual inspections to $2,650 for monthly inspections, and this
range increases to $560 for annual inspections to $3,620 for monthly
inspections when additional travel costs are incorporated. More
detailed information on the capital and annual costs estimated for the
AVO inspections can be found in the Supplemental TSD for this action
located at Docket ID No. EPA-HQ-OAR-2021-0317. The EPA is soliciting
comment on all aspects of the estimated costs of the AVO inspection
program, including labor rates and the costs of repair.
Single wellhead only well sites. The EPA has not previously defined
single wellhead only well sites as fugitive emissions components
affected facilities. For a single wellhead only well site, the most
likely cause of emissions would be from an open valve allowing venting
from the wellhead. In the U.S. DOE marginal well study, two of the top
10 largest leaks found were located at the wellhead and were the result
of an open valve on the well surface casing, which allowed venting to
the atmosphere. These two sources resulted in emissions of 6.9 kg/hr
methane (66 tpy) and 7.8 kg/hr methane (76 tpy).\63\ A third leak, also
located at the wellhead, was identified as a hole in the side of the
surface casing, resulting in emissions of 2.9 kg/hr methane (28 tpy)
from this source. The other top 10 leak sources identified in the U.S.
DOE marginal well study were on equipment that is not present at a
single wellhead only well site (e.g., separators or storage vessels).
The types of emissions sources located at the wellhead, including these
large emissions sources found in the U.S. DOE marginal well study, can
be easily identified using AVO inspections and would not require the
use of OGI for identification. Therefore, the EPA evaluated a periodic
AVO inspection and repair program for addressing fugitive emissions
from single wellhead only well sites.
---------------------------------------------------------------------------
\63\ Bowers, Richard L. Quantification of Methane Emissions from
Marginal (Low Production Rate) Oil and Natural Gas Wells. United
States. https://doi.org/10.2172/1865859. See Table 2 of the study
for details on the top 10 emissions sources identified.
---------------------------------------------------------------------------
First, the EPA modeled an AVO program at two leak generation rates
(1.0 percent and 0.5 percent) to compare the resulting baseline methane
emissions against empirical emissions data and identify which model
results more closely reflect real-world emissions measurement campaign
results. A comparison of the baseline methane emissions estimated at
both of these leak generation rates to empirical data suggest that the
0.5 percent leak generation rate is more likely to be indicative of the
actual average emissions from single wellhead only well sites. Various
studies indicate that, while these sites can occasionally experience
large emissions events, such events are not as frequent as at more
complex sites, and thus do not warrant application of a higher average
emissions baseline for purposes of determining the BSER for these
sites.\64\ The U.S. DOE marginal well study \65\ measured methane
average population emissions ranging from 0.26 to 0.56 tpy from
wellheads examined during the study, with negligible emissions reported
from meters. Similarly, the 2021 Rutherford et al. study estimated an
average emissions factor for a single wellhead of 3.4 kg/day (0.95 tpy)
and a single meter of 2.7 kg/day (0.75 tpy) for a total of 1.70 tpy
from a single wellhead only well site.\66\ Using the average emissions
between these 2 studies, the baseline methane emissions are 1.13 tpy,
which is consistent with the 0.5 percent leak generation rate results
for our single wellhead only well sites, for which the FEAST model
estimated a methane emissions baseline of 1.27 tpy (see Table 8). By
contrast, the 1.0 percent leak generation rate baseline (2.97 tpy) is
more than five times higher than the high end of the U.S. DOE marginal
well study and 50 percent higher than the estimates from the
Rutherford, et al. study. Therefore, the EPA is evaluating the cost of
control for AVO inspections based on the modeled results for a 0.5
percent leak generation rate at single wellhead only well sites.
Additional details of the model results, including those for the 1.0
percent leak generation rate, are included in the Supplemental TSD for
this action located at Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------
\64\ See https://pubs.acs.org/doi/10.1021/acs.est.0c02927,
https://data.permianmap.org/pages/flaring, and https://www.edf.org/sites/default/files/documents/PermianMapMethodology_1.pdf.
\65\ Bowers, Richard L. Quantification of Methane Emissions from
Marginal (Low Production Rate) Oil and Natural Gas Wells. United
States. https://doi.org/10.2172/1865859. Marginal wells are defined
in this study as producing less than 15 barrels of oil equivalent
per day (boe/day) of combined oil and natural gas.
\66\ Rutherford, J.S., Sherwin, E.D., Ravikumar, A.P. et al.
Closing the methane gap in US oil and natural gas production
emissions inventories. Nat Commun 12, 4715 (2021). https://doi.org/10.1038/s41467-021-25017-4.
Table 10--Summary of Emissions Reductions and Cost-Effectiveness: AVO Inspections at Single Wellhead Only Well Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost-effectiveness Incremental cost-
Methane VOC -------------------------- effectiveness
Monitoring frequency Annual cost emission emission -------------------------
($/yr/site) reduction reduction Methane ($/ VOC ($/ton) Methane ($/
(tpy/site) (tpy/site) ton) ton) VOC ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single Wellhead Well Sites: Includes additional travel costs Single Pollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual....................................................... $296 0.11 0.03 $2,579 $9,278
Semiannual................................................... 417 0.40 0.11 1,048 3,769 $429 $1,543
Quarterly.................................................... 660 0.56 0.16 1,181 4,249 1,511 5,436
Bimonthly.................................................... 904 0.63 0.17 1,443 5,190 3,618 13,017
Monthly...................................................... 1,633 0.69 0.19 2,367 8,515 11,455 41,208
--------------------------------------------------------------------------------------------------------------------------------------------------------
Single Wellhead Well Sites: Includes additional travel costs Multipollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Annual....................................................... 296 0.11 0.03 1,289 4,639
[[Page 74730]]
Semiannual................................................... 417 0.40 0.11 524 1,885 214 771
Quarterly.................................................... 660 0.56 0.16 591 2,124 756 2,718
Bimonthly.................................................... 904 0.63 0.17 721 2,595 1,809 6,509
Monthly...................................................... 1,633 0.69 0.19 1,183 4,257 5,727 20,604
--------------------------------------------------------------------------------------------------------------------------------------------------------
It is the EPA's understanding that single wellhead only well sites
are not regularly visited. Instead, these sites are expected to only be
visited when specific operations are necessary that require the
presence of an operator on the site (e.g., well workovers). Thus, the
EPA finds it more appropriate to base decisions related to whether an
AVO inspection frequency is reasonable on the analysis that includes
additional travel costs to the site. Based on the information
summarized in Table 10, which include additional travel costs, under
the single pollutant approach where all costs are assigned to methane
and zero cost to VOC, the semiannual, quarterly, and bimonthly (i.e.,
every other month) frequencies are reasonable for methane emissions;
similarly, where all costs are assigned to VOC and zero cost to
methane, the semiannual, quarterly, and bimonthly frequencies are
reasonable for VOC emissions. Under the multipollutant approach where
the costs are divided equally between the two pollutants, all of the
frequencies appear reasonable, including monthly monitoring.
The EPA next evaluated the incremental cost associated with
advancing to each more frequent monitoring schedule to determine which
frequencies would be reasonable for AVO inspections. As shown in Table
10 where additional travel costs are included, the incremental cost of
going from semiannual to quarterly inspections is reasonable under both
the single pollutant approach (for both methane and VOC individually)
and the multipollutant approach. Under the single pollutant approach,
the incremental cost of going from quarterly to bimonthly is not
reasonable for either methane or VOC emissions. Under the
multipollutant approach, the incremental cost of going from quarterly
to bimonthly is not reasonable for VOC ($6,500/ton VOC), which means it
is not cost-effective under the multipollutant approach. Therefore, the
EPA finds it is not reasonable to require bimonthly AVO inspections.
In summary, the EPA finds that the BSER for single wellhead only
well sites is quarterly AVO inspections for indications of potential
leaks, with specific attention given to ensuring surface casing valves
are closed to prevent the venting of emissions. The EPA is soliciting
comment and additional data related to the costs and other potential
causes of emissions on a single wellhead that could easily be
identified using AVO inspections.
Small well sites. As stated in the November 2021 proposal, the EPA
remains mindful about how the fugitive emissions monitoring
requirements will affect small businesses. The EPA solicited comment in
the November 2021 proposal on regulatory alternatives and additional
information that would warrant considering a subset of sites
differently based on a potentially different emissions profile,
production levels, equipment onsite, or other factors. (86 FR 63173;
November 15, 2021). The EPA examined data provided through an
information collection request (ICR) distributed in 2016, data provided
on equipment/component counts in relation to the October 15, 2018,
proposed reconsideration of NSPS OOOOa from independent producers (many
of whom are small businesses), data provided through comments on the
November 2021 proposal from independent producers, and data contained
in the U.S. DOE marginal well study to determine if a subset of well
sites with major production and processing equipment should be
considered differently.
Consistent with comments received on previous rulemakings, the EPA
received comments on the November 2021 proposal requesting
consideration of production volumes as a factor when establishing the
BSER for well sites.\67\ One commenter stated that the EPA has
emphasized component counts instead of considering the significantly
more important role that production rates and operating pressure play
on the amount of fugitive emissions.\68\ This commenter then referenced
the U.S. DOE marginal well study as showing that most low production
well sites (many of which are owned or operated by small businesses)
emit less than 3 tpy of methane. However, that marginal well study
concludes that the frequency and magnitude of emissions from well sites
are more strongly correlated with equipment counts, not production
rates.\69\ Further, this study broke down emissions by site size and
production levels and found that the smallest emissions rates were from
the second production level bin (2 barrels of oil equivalent per day
(boe/day) to 6 boe/day) and not the sites with production less than 2
boe/day. Another study issued in April 2022 by Omara, et al. concludes
that approximately half of the methane emissions emitted from well
sites in the U.S. comes from low production well sites (15 boe/day or
less production rates).70 71 However, the EPA notes that
this study is not limited to
[[Page 74731]]
fugitive emissions, and the overall impacts on emissions reductions
achieved if these rules are finalized as proposed, would target the
emissions reported in that study as a whole. Therefore, the EPA does
not have compelling information that suggests production levels should
provide the basis for consideration of different fugitive emissions
requirements for well sites.
---------------------------------------------------------------------------
\67\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0425 and EPA-HQ-
OAR-2021-0317-0814.
\68\ See Document ID No. EPA-HQ-OAR-2021-0317-0814.
\69\ Section 5.2.1 of the study concludes, ``The correlation
between major equipment counts and site emission frequency
(expressed as the number of detected emissions per piece of major
equipment, i.e., not absolute count of emissions), was strong with
the categorical site `size' variable and moderate (positive) with
the numeric equipment count. Among evaluated numeric variables, site
equipment counts also exhibited the strongest associations with both
frequency and magnitude of sitewide emissions, exhibiting only a
moderate positive correlation with detection frequency and weak
associations with whole gas and methane emission rates. Weak
correlations were also consistently detected among both the
frequency and magnitude of emissions, total oil and gas production,
and gas production rates.'' See Bowers, Richard L. Quantification of
Methane Emissions from Marginal (Low Production Rate) Oil and
Natural Gas Wells. United States. https://doi.org/10.2172/1865859.
page 19.
\70\ Omara, M., Zavala-Araiza, D., Lyon, D.R. et al. Methane
emissions from US low production oil and natural gas well sites. Nat
Commun 13, 2085 (2022). https://doi.org/10.1038/s41467-022-29709-3.
\71\ The EPA notes that Omara et al. analyzed data from offsite
measurements of methane emissions from well sites. These
measurements would include methane from any leak, venting, flaring,
or other source onsite and, therefore, conclusions from this study
cannot be directly applied to the specific fugitive sources covered
by this action.
---------------------------------------------------------------------------
While the EPA does not find that production rates correlate to the
amount of fugitive emissions and therefore should not be used as a
basis for establishing different fugitive emissions monitoring
requirements among well sites, we do find that the empirical data
described supports distinguishing among well sites based on equipment
and component counts. As explained earlier in this section, the EPA
utilized model plants, with different equipment and component counts to
differentiate fugitive emissions monitoring programs using AVO and OGI
through FEAST modeling simulations.
Based on comments received on the October 15, 2018, reconsideration
proposal, the EPA has evaluated if certain well sites with major
production and processing equipment are more comparable in total
component counts to either of the wellhead only model plants. For
example, one commenter in 2018 provided average equipment and/or
component counts for sites in various states that are owned and
operated by independent producers, many of whom are small businesses.
These counts included the number of storage vessels, wellheads, and
valves, specifically.\72\ That information suggests that there are well
sites owned and operated by small businesses that are predominantly
composed of single wellheads, with 1 to 2 storage vessels and 11 to 53
valves. These component counts are significantly lower than those
estimated for the model plants developed for this supplemental proposal
that include major production and processing equipment, which include
127 total valves. This suggests that certain well sites are smaller
than our model facilities, and that as a result the model may overstate
emissions reductions, and thus cost-effectiveness, for fugitive
emissions programs at such small sites. In fact, the EPA anticipates
that there are well sites with major production and processing
equipment that are of similar component counts as the single wellhead
only well site (total components equal to 112, with 23 total valves).
Therefore, the EPA does find that a separate BSER determination is
warranted for certain small sites.
---------------------------------------------------------------------------
\72\ See Document ID No. EPA-HQ-OAR-2017-0483-1006.
---------------------------------------------------------------------------
The EPA is proposing to define a small well site, for purposes of
the fugitive emissions monitoring requirements, as a well site that
contains a single wellhead, no more than one piece of certain major
production and processing equipment, and associated meters and yard
piping. The major production and processing equipment could include a
single separator, glycol dehydrator, heater/treater, compressor,\73\ or
uncontrolled storage vessel. It cannot include controlled storage
vessels, control devices, or natural gas-driven pneumatic controllers,
as those are known to be sources of large emissions events. Further,
the equipment allowed at these small sites would not include any
affected/designated facilities, nor would it include a CVS which is
subject to quarterly OGI monitoring as explained in section IV.K. The
EPA is proposing this narrow definition to ensure that sites with leak-
prone equipment that requires OGI (or other advanced technology)
monitoring are not present at the site. Based on the EPA's analysis of
data collected from an ICR distributed in 2016 and applied to the
universe of wells operating in 2019, it is estimated that approximately
95,000 well sites would meet this definition (nationwide), or
approximately 12 percent of the total nationwide well site count.
---------------------------------------------------------------------------
\73\ The EPA has proposed to exclude compressors located at well
sites from being affected facilities because these are generally
small compressors that do not have significant emissions.
Compressors have been excluded from being affected facilities in
NSPS OOOO and NSPS OOOOa as well.
---------------------------------------------------------------------------
Surface casing valves and thief hatches on an uncontrolled storage
vessel are the most likely emissions sources for these small well
sites. As discussed for single wellhead only well sites, the surface
casing valve can easily be identified as open or closed during an AVO
inspection and would not require the use of OGI to detect the leak.
Similarly, the use of OGI is not necessary to be able to identify if a
thief hatch is not closed. For example, the hatch may be fully open,
left unlatched and ``chattering'' with fluctuations from the storage
vessel pressures, or have visible indications of liquids such as
staining around the hatch. Therefore, the EPA has evaluated AVO
inspections to determine the BSER for small well sites.
The EPA utilized the same model results as those provided for
single wellhead only well sites. For that model plant, the baseline
methane emissions were estimated at 1.27 tpy. In the U.S. DOE marginal
well study, the average methane emissions rate for a thief hatch was
0.20 tpy. Likewise, the emissions factor for tank leaks identified in
Rutherford, et al. was 0.195 tpy (0.7 kg/day). Therefore, the EPA finds
it appropriate to utilize the same model results as those presented in
Table 10 for single wellhead only sites to determine the BSER for small
well sites. Based on the information presented in Table 10, and our
conclusions on the cost-effectiveness of the options for single
wellhead only well sites, the EPA proposes quarterly AVO inspections
for monitoring fugitive emissions at small well sites.
Additionally, for thief hatches and other openings on storage
vessels that are proposed as fugitive emissions components, the EPA is
proposing to require an equipment standard as part of the fugitive
emissions work practice that requires these thief hatches to remain
closed and sealed at all times except during sampling, adding process
material, or attended maintenance operations.\74\ This type of
equipment standard has been used in other leak detection work practices
where open-ended lines and valves are required to be equipped with a
closure device (e.g., cap or plug) to seal the open-end of the line or
valve, thus preventing leaks from going to the atmosphere. An open
thief hatch, even on an uncontrolled storage vessel, would still
contribute fugitive emissions and maintaining the thief hatch in a
closed position will provide for reduction of emissions at no
additional cost. Further, one commenter provided a recommendation that
the EPA should propose requirements to maintain thief hatches closed
and sealed until the potential emissions from a tank battery exceeds
the applicability threshold requiring controls for storage vessels and
that AVO monitoring should be used to verify compliance with this
standard.\75\ The EPA agrees with this recommendation that AVO
inspections would be appropriate to verify compliance with the proposed
``closed and sealed'' requirement, and therefore, is proposing this
requirement for thief hatches that are fugitive emissions components.
---------------------------------------------------------------------------
\74\ See section IV.J for solicitation for comment on
mechanisms, such as alarms and automatically closing thief hatches
that could also provide assurance that thief hatches meet this
requirement.
\75\ See Document ID No. EPA-HQ-OAR-2021-0317-0814.
---------------------------------------------------------------------------
Given all of the factors described in this section (fewer
equipment, less emissions, many are owned and operated by small
businesses, do not contain leak-prone equipment that needs OGI to
identify emissions), the
[[Page 74732]]
EPA is proposing quarterly AVO surveys and the closed and sealed
requirement for thief hatches as the BSER for reducing fugitive
emissions at small well sites. The EPA is soliciting comment on this
definition for small well sites, including whether additional metrics
should be used beyond equipment counts, as well as the proposed
standards and requirements for this subcategory of sites.
Multi-wellhead only well sites. For wellhead only well sites with
two or more wellheads, the EPA anticipates that the same large
emissions source (i.e., surface casing valves) would be present. In
addition to these valves on the wellheads, these sites have additional
piping, and thus connection points and valves that also present a
potential source of fugitive emissions. Emissions from these types of
components are generally smaller, and not easily identifiable using
AVO. Further, the estimated component count for the multi-wellhead only
well sites is at least double that of the single wellhead only well
site (and in many cases much larger), thus, the EPA has determined that
additional analysis including OGI monitoring is appropriate. As with
the AVO inspection analysis for single wellhead only well sites, the
EPA evaluated both a 0.5 percent leak generation rate and a 1.0 percent
leak generation rate for this model plant to determine which model
results were representative of the fugitive emissions measurement data
provided in the same studies used for comparison for single wellhead
only well sites analysis.
For multi-wellhead only well sites, the baseline emissions were
estimated at 2.66 tpy methane and 4.68 tpy methane at the 0.5 percent
and 1.0 percent leak generation rates, respectively. Applying the
wellhead emissions range from the U.S. DOE marginal well study to a
site with two wellheads results in baseline methane emissions of 0.52
to 1.12 tpy.\76\ Applying the wellhead emissions from the Rutherford,
et al. study to a site with two wellheads and meters results in
baseline methane emissions of 3.40 tpy. Using the average emissions
between these 2 studies, the baseline methane emissions are 2.26 tpy,
which is consistent with the 0.5 percent leak generation rate model
plant results. Accordingly, the EPA is evaluating the OGI monitoring
frequencies based on the modeled results for the 0.5 percent leak
generation rate for purposes of this proposal. Additional details of
the model results, including those for the 1.0 percent leak generation
rate, are included in the Supplemental TSD for this action located at
Docket ID No. EPA-HQ-OAR-2021-0317.
---------------------------------------------------------------------------
\76\ The emissions for meters in the U.S. DOE marginal well
study were negligible and do not impact the total average baseline
emissions for this type of site.
Table 11--Summary of Emission Reductions and Cost-Effectiveness: OGI Monitoring at Well Sites With Two or More
Wellheads
----------------------------------------------------------------------------------------------------------------
Methane VOC Cost-effectiveness Incremental cost-
Annual emission emission ---------------------- effectiveness
Monitoring frequency cost ($/ reduction reduction ---------------------
yr/site) (tpy/ (tpy/ Methane VOC ($/ Methane VOC ($/
site) site) ($/ton) ton) ($/ton) ton)
----------------------------------------------------------------------------------------------------------------
Well Sites with Two or More Wellheads: 0.5 Percent Leak Generation Rate Single Pollutant Approach
----------------------------------------------------------------------------------------------------------------
Baseline........................... ......... 2.66 0.74 ......... ......... ......... .........
Annual............................. $1,972 1.18 0.33 $1,677 $6.034 ......... .........
Semiannual......................... 2,327 1.79 0.50 1,300 4,675 $578 $2,078
Quarterly.......................... 3,037 2.06 0.57 1,473 5,300 2,620 9,425
Bimonthly.......................... 3,747 2.15 0.60 1,741 6,263 7,799 28,055
Monthly............................ 5,877 2.24 0.62 2,619 9,420 23,140 83,246
----------------------------------------------------------------------------------------------------------------
Well Sites with Two or More Wellheads: 0.5 Percent Leak Generation Rate Multipollutant Approach
----------------------------------------------------------------------------------------------------------------
Baseline........................... ......... 2.66 0.74 ......... ......... ......... .........
Annual............................. 1,972 1.18 0.33 839 3,017 ......... .........
Semiannual......................... 2,327 1.79 0.50 650 2,338 289 1,039
Quarterly.......................... 3,037 2.06 0.57 737 2,650 1,310 4,713
Bimonthly.......................... 3,747 2.15 0.60 870 3,131 3,899 14,028
Monthly............................ 5,877 2.24 0.62 1,309 4,710 11,570 41,623
----------------------------------------------------------------------------------------------------------------
Based on the information summarized in Table 11, under the single
pollutant approach where all costs are assigned to methane and zero
cost to VOC, all frequencies except monthly appear reasonable for
methane emissions; where all costs are assigned to VOC and zero cost to
methane, only annual, semiannual, and quarterly monitoring frequencies
appear reasonable for VOC emissions. Under the multipollutant approach
where the costs are divided equally between the two pollutants, all
frequencies appear reasonable when compared directly to a baseline of
no OGI monitoring.
The EPA next evaluated the incremental cost associated with
advancing to a more frequent monitoring schedule to determine if those
additional costs are reasonable for achieving the additional emissions
reductions. Under the single pollutant approach, the incremental cost
of going from semiannual to quarterly monitoring for well sites with
two or more wellheads is $2,600/ton methane and $9,400/ton of VOC.
These incremental costs are not reasonable and are outside the range of
costs the EPA has found reasonable for this source category. Under the
multipollutant approach, the incremental costs of going from semiannual
to quarterly monitoring is $1,310/ton methane and $4,713/ton VOC, which
is within the range the EPA has found reasonable for this source
category.
Next the EPA evaluated whether AVO inspections should also be
utilized, in combination with the OGI surveys to allow for faster
identification of those larger emissions sources (i.e., surface casing
valves) between OGI surveys. As
[[Page 74733]]
explained above, fugitive emissions from these large emission sources
can be detected through AVO inspections, which are less expensive than
OGI. Therefore, the EPA evaluated a combination of semiannual OGI and
various frequencies of AVO inspections to determine if this combined
program would be as effective as, but less expensive than, quarterly
OGI in light of the number and significance of fugitive emissions that
can be identified via AVO at this type of well site. The EPA analyzed
AVO inspections at quarterly, bimonthly, and monthly frequencies only
because annual or semiannual AVO inspection frequencies would occur at
the same time as at least one of the OGI surveys if the EPA were to
require OGI monitoring for multi-wellhead only well sites. Further, the
EPA determined that some costs associated with the AVO inspections
would be less than those provided in Table 9 because those costs are
also included in the OGI monitoring costs in Table 8. For example,
there would be no additional costs to read the rule, travel for
inspections that overlap with OGI monitoring surveys, or additional
recordkeeping system costs. That is, in the evaluation of semiannual
OGI with quarterly AVO inspections, only two AVO inspections would be
required outside of the OGI surveys, thus the inspection costs would be
half what is estimated for quarterly AVO inspections. Table 12
summarizes the results of this combined program for multi-wellhead only
well sites.
Table 12--Summary of Emissions Reductions and Cost-Effectiveness: Combined OGI Monitoring and AVO Inspections at Multi-Wellhead Only Well Sites
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost-effectiveness Incremental cost-
Methane VOC -------------------------- effectiveness
Monitoring frequency Annual cost emission emission -------------------------
($/yr/site) reduction reduction Methane ($/ VOC ($/ton) Methane ($/
(tpy/site) (tpy/site) ton) ton) VOC ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Multi-Wellhead Well Sites: Includes additional travel costs Single Pollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Semiannual OGI............................................... $2,327 1.79 0.50 $1,300 $4,653 ........... ...........
Semiannual OGI + Quarterly AVO............................... 2,651 1.99 0.55 1,331 4,788 $1,606 $6,038
Semiannual OGI + Bimonthly AVO............................... 2,973 2.09 0.58 1,425 5,125 3,394 12,210
Semiannual OGI + Monthly AVO................................. 3,671 2.16 0.60 1,822 6,554 12,728 45,787
--------------------------------------------------------------------------------------------------------------------------------------------------------
Multi-Wellhead Well Sites: Includes additional travel costs Multipollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Semiannual OGI............................................... 2,327 1.79 0.50 650 2,327 ........... ...........
Semiannual OGI + Quarterly AVO............................... 2,651 1.99 0.55 665 2,394 803 3,019
Semiannual OGI + Bimonthly AVO............................... 2,973 2.09 0.58 712 2,563 1,697 6,105
Semiannual OGI + Monthly AVO................................. 3,671 2.16 0.60 911 3,277 6,364 22,893
--------------------------------------------------------------------------------------------------------------------------------------------------------
Under the single pollutant approach, a combined program of
semiannual OGI and quarterly or bimonthly AVO are reasonable for
methane and VOC emissions individually. However, when incremental costs
are considered, the costs of going from quarterly to bimonthly AVO
inspections is not reasonable for either pollutant under the single
pollutant approach. Under the multipollutant approach, all combinations
appear reasonable when evaluated against a baseline of no monitoring.
However, the multipollutant incremental costs are not reasonable for a
combined program of semiannual OGI and bimonthly AVO because the
multipollutant VOC costs exceed the range that the EPA considers
reasonable for this source category at $6,105/ton VOC. Therefore, the
EPA finds it is reasonable to consider either quarterly OGI monitoring
or a combination of semiannual OGI and quarterly AVO as cost-effective
measures to reduce fugitive emissions from multi-wellhead only well
sites.
Finally, the EPA compared the emissions reductions and costs
associated with the quarterly OGI (most stringent and cost-effective
OGI frequency) to the combined program of semiannual OGI with quarterly
AVO inspections. The emissions reductions for these two monitoring
programs are comparable (2.06 tpy of methane and 0.57 tpy of VOC for
quarterly OGI versus 1.99 tpy of methane and 0.55 tpy of VOC for
semiannual OGI with quarterly AVO), but the costs are not. The annual
cost of quarterly OGI monitoring is $3,037, whereas the annual cost of
the combined OGI and AVO program is $2,489. For a combined semiannual
OGI and quarterly AVO program the same number of surveys would be
conducted at the site (with 2 surveys being OGI with AVO and 2 surveys
being AVO only). The EPA is proposing the combined program of
semiannual OGI with quarterly AVO as the BSER for multi-wellhead only
well sites because of the comparable emissions reductions, same number
of total surveys per year, and lower annual costs for the program
overall. The EPA solicits comment on this proposed standard, including
the basis for the decision to propose semiannual OGI with quarterly AVO
inspections rather than quarterly OGI.
Well sites with major production and processing equipment and
centralized production facilities. The EPA evaluated a third model
plant, which contains major production and processing equipment. The
EPA performed the same analyses to evaluate the BSER for fugitive
emissions components at well sites and centralized production
facilities with major production and processing equipment as performed
for multi-wellhead only well sites. Table 13 summarizes the cost-
effectiveness information for each OGI monitoring frequency, and Table
14 summarizes the costs of a combined program using both OGI and AVO.
As discussed for the single wellhead only and multi-wellhead only
well site analyses, the EPA modeled OGI monitoring programs for both a
1.0 percent and 0.5 percent leak generation rate and compared the
resulting modeled emissions to the same empirical study data to
determine which model was more representative of the emissions at this
type of well site. The baseline emissions resulting from FEAST for this
model plant were 15.40 tpy methane and 8.51 tpy methane at 1.0 percent
and 0.5 percent leak generation rate, respectively. The highest average
site emissions were calculated at 3.3 tpy methane for large natural gas
sites and 4.0 tpy methane for large oil sites in the U.S. DOE marginal
[[Page 74734]]
well study, which the EPA anticipates is similar to the model plant
with major production and processing equipment. The EPA next applied
the emissions factors from the Rutherford, et al. study to the
equipment counts in our model plant, resulting in emissions of 7.1 tpy
methane. These emissions suggest the 0.5 percent leak generation rate
is more appropriate for consideration of the costs of control and
appropriate OGI monitoring frequency for well sites and centralized
production facilities with major production and processing equipment.
Table 13--Summary of Emission Reductions and Cost-Effectiveness: OGI Monitoring at Well Sites With Major Production or Processing Equipment
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost-effectiveness Incremental cost-
Methane VOC -------------------------- effectiveness
Monitoring frequency Annual cost emission emission -------------------------
($/yr/site) reduction reduction Methane ($/ VOC ($/ton) Methane ($/
(tpy/site) (tpy/site) ton) ton) VOC ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Well Sites and Centralized Production Facilities: 0.5 percent leak generation rate Single Pollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline..................................................... ........... 8.51 2.37 ........... ........... ........... ...........
Annual....................................................... $2,162 3.99 1.11 $542 $1,951 ........... ...........
Semiannual................................................... 2,588 5.73 1.59 452 1,624 $244 $879
Quarterly.................................................... 3,440 6.61 1.84 520 1,872 969 3,487
Bimonthly.................................................... 4,292 6.97 1.94 616 2,217 2,398 8,625
Monthly...................................................... 6,848 7.26 2.02 943 3,393 8,676 31,212
--------------------------------------------------------------------------------------------------------------------------------------------------------
Well Sites and Centralized Production Facilities: 0.5 percent leak generation rate Multipollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Baseline..................................................... ........... 8.51 2.37 ........... ........... ........... ...........
Annual....................................................... 2,162 3.99 1.11 271 975 ........... ...........
Semiannual................................................... 2,588 5.73 1.59 226 812 122 439
Quarterly.................................................... 3,440 6.61 1.84 260 936 485 1,744
Bimonthly.................................................... 4,292 6.97 1.94 308 1,108 1,199 4,313
Monthly...................................................... 6,848 7.26 2.02 472 1,697 4,338 15,606
--------------------------------------------------------------------------------------------------------------------------------------------------------
Based on the information summarized in Table 13 for the 0.5 percent
leak generation rate, under the single pollutant approach where all
costs are assigned to methane and zero cost to VOC, all frequencies
appear reasonable for methane emissions; where all costs are assigned
to VOC and zero cost to methane, all frequencies appear reasonable for
VOC emissions. Similarly, under the multipollutant approach where the
costs are divided equally between the two pollutants, all frequencies
appear reasonable when compared directly to a baseline of no OGI
monitoring.
The EPA next evaluated the incremental cost associated with
advancing to each more frequent monitoring schedule. As shown in Table
13 for the single pollutant approach, the incremental costs of going
from quarterly to bimonthly monitoring for these larger well sites are
$2,398/ton methane and $8,625/ton of VOC. These incremental costs are
outside the range of costs the EPA has found reasonable for this source
category (i.e., $2,165/ton methane and $5,540/ton VOC). Under the
multipollutant approach, the incremental costs of going from quarterly
to bimonthly monitoring are $1,199/ton methane and $4,313/ton VOC,
which is within the range the EPA has found reasonable for this source
category.
Next the EPA evaluated the costs of a combined program for well
sites and centralized production facilities, using quarterly OGI as a
baseline with AVO inspections added at bimonthly, and monthly
frequencies to determine if this combined program would be as effective
as, but less expensive than, bimonthly OGI. The EPA did not evaluate
annual, semiannual, or quarterly AVO inspection frequencies because
those would occur at the same time as at least one of the OGI surveys
if the EPA were to require quarterly OGI monitoring for well sites and
centralized production facilities with major production and processing
equipment. However, the EPA is soliciting comment on the costs and
effectiveness of a combined program of quarterly OGI surveys in
combination with quarterly AVO inspections that are offset by one
month, such that eight total fugitive surveys would take place over the
course of a year. Further, the EPA determined that some costs
associated with the AVO inspections would be less than those provided
in Table 9 because those costs are also included in the OGI monitoring
costs in Table 8. For example, there would be no additional costs to
read the rule, travel for inspections that overlap with OGI monitoring
surveys, or additional recordkeeping system costs. Table 14 summarizes
the results of this combined program for well sites and centralized
production facilities with major production and processing equipment.
Table 14--Summary of Emissions Reductions and Cost-Effectiveness: Combined OGI Monitoring and AVO Inspections at Well Sites and Centralized Production
Facilities
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost-effectiveness Incremental cost-
Methane VOC -------------------------- effectiveness
Monitoring frequency Annual cost emission emission -------------------------
($/yr/site) reduction reduction Methane ($/ VOC ($/ton) Methane ($/
(tpy/site) (tpy/site) ton) ton) VOC ($/ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Well Sites and Centralized Production Facilities: Assumes no additional travel costs Single Pollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Quarterly OGI................................................ $3,440 6.61 1.84 $520 $1,872 ........... ...........
[[Page 74735]]
OGI + Bimonthly AVO.......................................... 4,232 6.93 1.93 611 2,198 2,497 8,981
OGI + Monthly AVO............................................ 5,021 7.10 1.97 707 2,545 4,616 16,608
--------------------------------------------------------------------------------------------------------------------------------------------------------
Well Sites and Centralized Production Facilities: Assumes no additional travel costs Multipollutant Approach
--------------------------------------------------------------------------------------------------------------------------------------------------------
Quarterly OGI................................................ 3,440 6.61 1.84 260 936 ........... ...........
OGI + Bimonthly AVO.......................................... 4,232 6.93 1.93 305 1,099 1,248 4,491
OGI + Monthly AVO............................................ 5,021 7.10 1.97 354 1,272 2,308 8,304
--------------------------------------------------------------------------------------------------------------------------------------------------------
Under the single pollutant approach, a combined program of
quarterly OGI and bimonthly or monthly AVO are reasonable for methane
and VOC emissions individually. When incremental costs are considered,
the costs of going from bimonthly to monthly AVO inspections is not
reasonable for either pollutant under the single pollutant approach.
Under the multipollutant approach, all combinations appear reasonable
when evaluated against a baseline of no monitoring. The multipollutant
incremental costs are not reasonable for a combined program of
quarterly OGI and monthly AVO. However, the EPA finds it is reasonable
to consider either a bimonthly OGI monitoring program alone or a
combination of quarterly OGI and bimonthly AVO as cost-effective
measures to reduce fugitive emissions from well sites and centralized
production facilities that include major production and processing
equipment.
Finally, the EPA compared the emissions reductions achieved by the
combined quarterly OGI and bimonthly AVO program to a bimonthly OGI
program with no AVO inspections. While both programs appear cost-
effective, the combined program achieves comparable emissions
reductions to the bimonthly OGI program (6.93 tpy of methane and 1.93
tpy of VOC for the combined program, compared to 6.97 tpy of methane
and 1.94 tpy of VOC for the bimonthly OGI program) at a comparable cost
($4,232 for the combined program compared to $4,292 for the bimonthly
OGI program), and results in more total visits to the well site or
centralized production facility. Specifically, a total of four OGI
surveys and four AVO inspections would be completed, for a total of
eight surveys at the site each year (two of the bimonthly AVO
inspections would occur at the same time as two of the OGI surveys)
whereas bimonthly OGI would result in six surveys of the site each
year. Additional visits to the site create more opportunities to find
and fix fugitive emissions, including the large emissions that can be
detected by AVO inspections. Therefore, the EPA finds that the BSER for
well sites and centralized production facilities with major production
and processing equipment is quarterly OGI surveys combined with
bimonthly AVO inspections and therefore is proposing this combined
program as the standard for reducing fugitive emissions at these sites.
The EPA solicits comment on this proposed standard, including the basis
for the decision to propose quarterly OGI monitoring with bimonthly AVO
inspections rather than bimonthly OGI monitoring.
Because the EPA finds that the combination of quarterly OGI
monitoring and bimonthly AVO inspections are reasonable, the EPA is
proposing this combination of monitoring frequencies and methods as the
BSER for well sites and centralized production facilities with major
production and processing equipment. The EPA is specifically proposing
to require this combination program for fugitive emissions components
affected facilities located at well sites or centralized production
facilities that contain the following major production and processing
equipment:
One or more controlled storage vessels or tank batteries,
One or more control devices,
One or more natural gas-driven pneumatic controllers or
natural gas-driven pneumatic pumps, or
Two or more pieces of major production and processing
equipment not otherwise specified.\77\
---------------------------------------------------------------------------
\77\ Major production and processing equipment includes
centrifugal and reciprocating compressors, separators, glycol
dehydrators, heater/treaters, and storage vessels.
---------------------------------------------------------------------------
The EPA is proposing to define this subcategory as well sites with
one or more controlled storage vessels, control devices, or natural
gas-driven pneumatic controllers because those sources individually are
known sources of super-emitter emissions events (see section IV.C) and
are subject to quarterly OGI for compliance assurance (storage vessels
and pneumatic controllers) or are subject to other continuous
monitoring requirements (control devices). Further, the EPA is defining
this subcategory as well sites with two or more other major production
and processing equipment because the model plant includes two
separators, which are another source that can contribute to large
emissions when combined with a storage tank. As explained previously
related to small well sites, the EPA is proposing an additional
subcategory of well sites to recognize that this model plant may
overstate the fugitive emissions from well sites that have only one
piece of major production and processing equipment that is not a
controlled storage vessel, control device, pneumatic controller, or
pneumatic pump. Consistent with comments received on the November 2021
proposal, the EPA understands that the industry is aware that this
specific equipment (controlled storage vessels, control devices, and
natural gas-driven pneumatic controllers) is more prone to emissions
and that fugitive surveys using OGI present an opportunity to identify
these emissions. However, the EPA is not expanding the definition of
fugitive emissions component to include controlled tank batteries,
control devices, or natural gas-driven pneumatic controllers as
explained earlier in this section because those sources are subject to
separate requirements that are intended to ensure proper operation
(including regular inspections, in the case of controlled tank
batteries and natural gas-driven pneumatic controllers).
In summary, the EPA is proposing that the BSER for well sites with
major
[[Page 74736]]
production and processing equipment and centralized production
facilities, is a combination program consisting of bimonthly AVO
inspections and quarterly OGI monitoring and the closed and sealed
requirement for thief hatches (as explained in the discussion on small
well sites).
Well closure plans. The EPA is proposing that owners and operators
of each well site or centralized production facility may stop the
required fugitive emissions monitoring and repair for that site when
the well site has been properly closed because in that event there
should not be any equipment or other fugitive components onsite for
monitoring. This would also help address concerns cited by many
stakeholders regarding continuing emissions from orphaned wells and
unplugged idled wells. In the November 2021 proposal, the EPA solicited
comment and information on idled and unplugged wells due to the EPA's
understanding and concern that these non-producing oil and natural gas
wells are generally unmanned and many are in disrepair. 86 FR 63240
(November 15, 2021). The EPA notes that ``some states and NGOs also
have elevated concerns about the potential number of wells that could
be abandoned in the near future as they reach the end of their
productive lives.'' Id.
In addition, since promulgation of NSPS OOOOa, the EPA has received
various questions from owners and operators related to when fugitive
emissions monitoring applies if a well is shut-in, idled, or
permanently closed. The Agency is therefore proposing specific
requirements in NSPS OOOOb to ensure clarity for well sites and
centralized production facilities subject to the rule. Studies have
shown that idled wells can have fugitive emissions, and in some cases
these emissions can be very large.78 79 The EPA finds that
these data demonstrate the importance of continued fugitive emissions
monitoring on a routine basis to ensure that fugitive emissions
continue to be addressed throughout the life of the well site, even
during periods when the wells at the site are shut-in or idled and
could be put back into production at a later date.
---------------------------------------------------------------------------
\78\ Amy Townsend-Small and Jacob Hoschouer. ``Direct
measurements from shut-in and other abandoned wells in the Permian
Basin of Texas indicate some wells are a major source of methane
emissions and produced water.'' 2021 Environ. Res. Lett. 16 054081.
https://iopscience.iop.org/article/10.1088/1748-9326/abf06f.
\79\ Eric D. Lebel, Harmony S. Lu, Lisa Vielst[auml]dte, Mary
Kang, Peter Banner, Marc L. Fischer, and Robert B. Jackson.
``Methane Emissions from Abandoned Oil and Gas Wells in
California.'' Environmental Science & Technology 2020 54 (22),
14617-14626. DOI: 10.1021/acs.est.0c05279.
---------------------------------------------------------------------------
However, there is a point at the end of a well site's useful life
where the EPA does anticipate the cessation of fugitive emissions
monitoring is appropriate, when all wells at the well site have been
permanently plugged and all equipment has been removed. To demonstrate
that a well site has reached that point where it is appropriate to
cease fugitive monitoring, the EPA is proposing to require owners and
operators to develop and submit a well closure plan within 30 days of
the cessation of production from all wells at the well site or
centralized production facility. The plan would include: (1) The steps
necessary to close all wells at the well site, including plugging of
all wells; (2) the financial requirements and disclosure of financial
assurance to complete closure; and (3) the schedule for completing all
activities in the closure plan. The EPA is also proposing to require
that owners and operators submit a notification to the Agency 60 days
before beginning well closure activities. The EPA solicits comment on
additional provisions that could be added, including, for example,
automatic consequences for missed monitoring reports, as a means of
assuring that companies remain engaged with the site, including
conducting monitoring, until all the wells at the site are properly
closed.
Finally, the EPA is proposing that when the well closure activities
have been completed, prior to ceasing regular monitoring, the owner or
operator would be required to conduct a survey of the well site using
OGI. The purpose of this survey is to ensure there are no emissions
identified with OGI. If any emissions are identified, the owner or
operator would be required to take steps to eliminate those emissions
and resurvey. The EPA is proposing that once the OGI survey indicates
no emissions are present, the well site would be considered closed and
no further fugitive emissions monitoring would be required.
The EPA finds that the requirements described above not only would
allow owners and operators of well sites and centralized production
facilities to stop fugitive emissions monitoring at a clearly defined
point where fugitive emissions are no longer a concern at the site,
these proposed requirements would also prevent well sites from becoming
orphaned or left in an idled and unplugged state with no form of
emissions monitoring and repair. The EPA assesses the continued
monitoring of well sites will help identify emissions and maintain the
well site such that it does not fall into disrepair. The EPA is
soliciting comment on these planning and monitoring requirements.
Lastly, because a well site could have a long useful life, during which
there may be different owners or operators, the EPA is proposing to
require owners and operators to report, through the annual report, any
changes in ownership at individual well sites so that it is clear who
the responsible owners and operators are until the site is plugged and
closed and fugitive emissions monitoring is no longer required. We
propose this reporting requirement as an important step in maintaining
transparency for the responsible owner or operator and will also
prevent well sites from becoming orphaned in the future. The EPA
solicits comment on this additional reporting requirement, including
other mechanisms for obtaining this information.
iii. Summary of Proposed Standards
Definition of fugitive emissions component. Based on changes made
and discussed under section IV.A.1.a.ii of this preamble, the EPA is
proposing to define fugitive emissions component as any component that
has the potential to emit fugitive emissions of methane or VOC at a
well site, centralized production facility, or compressor station,
including valves, connectors, pressure relief devices, open-ended
lines, flanges, covers and CVS not subject to 40 CFR 60.5411b, thief
hatches or other openings on a storage vessel not subject to 40 CFR
60.5395b, compressors, instruments, meters, and yard piping.
Monitoring requirements. The EPA is proposing the following
requirements for each subcategory of well sites not located on the
Alaska North Slope.
Single wellhead only well sites and small well sites:
Quarterly AVO inspections.
Multi-wellhead only well sites: Semiannual OGI (or EPA
Method 21) monitoring and quarterly AVO inspections at wellhead only
well sites with two or more wellheads.
Well sites with major production and processing equipment
and centralized production facilities: Quarterly OGI (or EPA Method 21)
monitoring and bimonthly AVO inspections at well sites and centralized
production facilities with: (1) One or more controlled storage vessels
or tank batteries; (2) one or more control devices; (3) one or more
natural gas-driven pneumatic controllers; or (4) two or more pieces of
major production or processing equipment not listed in items (1)
through (3).
Where semiannual monitoring is proposed, subsequent semiannual
[[Page 74737]]
monitoring would occur at least 4 months apart and no more than 7
months apart. Where quarterly monitoring is proposed, subsequent
quarterly monitoring would occur at least 60 days apart and quarterly
monitoring may be waived when temperatures are below 0 degrees
Fahrenheit ([deg]F) for two of three consecutive calendar months of a
quarterly monitoring period.
When fugitive emissions are identified through AVO inspections, the
EPA is proposing to require that repairs be completed within 15 days
after the first attempt. The EPA is proposing a 15-day repair timeframe
so that the monthly AVO inspections do not overlap the repair schedule.
When fugitive emissions are identified through OGI surveys, the EPA is
proposing to require a first attempt at repair within 30 days of
detecting the fugitive emissions, with final repair, including resurvey
to verify repair, completed within 30 days after the first attempt,
consistent with the November 2021 proposal. Finally, we are proposing
to require owners and operators to develop a fugitive emissions
monitoring plan that covers all the applicable requirements for the
fugitive emissions components located at a well site or centralized
production facility. This monitoring plan would also include specific
procedures, defined by the owner or operator, to ensure consistency in
surveys conducted with either OGI or EPA Method 21, and to ensure that
these surveys are conducted appropriately for identifying fugitive
emissions from components at the site.
Monitoring (AVO and OGI) surveys would be required to continue
until the owner or operator permanently closes the well site. Closure
includes completing well closure activities specified by the owner or
operator in a well closure plan. A final OGI survey of the well site
would be required to ensure there are no emissions following plugging
all of the wells at the site and completing closure activities. If
emissions are identified during this OGI survey, the rule would require
eliminating those emissions within the same timeline as required for
regular OGI surveys (first attempt within 30 days of identification,
with final repair within 30 days of the first attempt) and a resurvey
of the whole site to verify emissions have been addressed.
Recordkeeping and Reporting Requirements. Specific recordkeeping
and reporting requirements would also apply for each fugitive emissions
affected facility. Sources would be required to report the 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. In addition, for each fugitive emissions
components affected facility that becomes an affected facility during
the reporting period, the date of the startup of production or the date
of the first day of production after modification would be required for
well sites or centralized production facility. Each fugitive emissions
components affected facility at a well site would also be required to
specify in the annual report what type of site it is (i.e., a single
wellhead only well site, small well site, a multi-wellhead only well
site, or a well site with major production and processing equipment).
For fugitive emissions components affected facilities complying
with the requirement to conduct surveys using AVO, the annual report
would require the date of the survey, the total number and type of
equipment for which leaks were identified, or, if no leaks were
detected, a statement that there were no leaks on the day of
inspection, the total number and type of equipment for which leaks
identified were repaired within 15 calendar days, the total number and
type of equipment for which no repair attempt was made within 15 days
of the leaks being identified, and the total number and type of
equipment placed on the delay of repair.
For fugitive emissions components affected facilities complying
with the requirement to monitor for fugitive emissions using OGI on a
semiannual or quarterly basis, the following information would be
required to be included in the annual report:
Date of the survey,
Monitoring instrument used,
Any deviations from key monitoring plan elements or a
statement that there were no deviations from these elements of the
monitoring plan,
Number and type of components for which fugitive emissions
were detected,
Number and type of fugitive emissions components that were
not repaired,
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, and
Date of planned shutdown(s) that occurred during the
reporting period if there are any components that have been placed on
delay of repair.
b. EG OOOOc
In section XII.A.2 of the November 2021 proposal preamble (86 FR
63196; November 15, 2021), the EPA proposed BSER for EG OOOOc for
reducing methane emissions from existing well sites that was the same
as that proposed for new well sites, with a site-wide emissions
threshold used to determine OGI monitoring frequency. However, as
explained for new, modified, and reconstructed well sites and
centralized production facilities in the previous section, the EPA has
changed approaches for evaluating the BSER for fugitive emissions
components, which also affects the determinations for BSER for existing
sources under EG OOOOc.
The EPA did not identify any factors specific to existing sources
that would alter the analysis performed for new sources to make that
analysis different for existing well sites. Therefore, the EPA has
evaluated the presumptive standards in EG OOOOc using the same approach
as that for the proposed standards in NSPS OOOOb, specifically
evaluating both the total cost-effectiveness of each monitoring option
against a baseline of no monitoring and the incremental costs of
increasing stringency between monitoring options. The EPA has
determined that the methods for identifying fugitive emissions (i.e.,
AVO, OGI, and EPA Method 21), methane emissions reductions, costs, and
cost effectiveness related to the single pollutant approach for methane
emissions discussed above for the fugitive emissions components
affected facility at new well sites are also applicable for the
fugitive emissions components affected facility at existing well sites.
Further, the fugitive emissions requirements do not require the
installation of controls on existing equipment or the retrofit of
equipment, which can generally be an additional factor for
consideration when determining the BSER for existing sources.
Therefore, the EPA is proposing that it is appropriate to use the
analysis developed for the proposed NSPS OOOOb to also determine the
BSER and proposed presumptive standards for the EG OOOOc. Additionally,
the EPA is proposing the same requirement that thief hatches must be
closed and sealed at all times, in addition to the requiring fugitive
emissions monitoring continue until all of the wells at an existing
well site or centralized production facility are permanently closed and
the owner or operator has completed the same requirements for well
closure and submitted a well closure report meeting the same
requirements described for new sources.
Single wellhead only and small well sites. Table 15 summarizes the
costs associated with AVO inspections at existing single wellhead only
well sites
[[Page 74738]]
and existing small well sites. Based on the information summarized in
Table 15, and the explanation provided for new single wellhead only
well sites and new small well sites, the semiannual, quarterly, and
bimonthly inspection frequencies are all reasonable. When examining the
incremental costs of going from quarterly to bimonthly AVO inspections,
the costs are not reasonable at $3,618/ton methane. Therefore, the EPA
proposes that the BSER for existing single wellhead only well sites is
quarterly AVO inspections, and the BSER for existing small sites
includes quarterly AVO inspections and the closed and sealed
requirement for thief hatches (as explained in the discussion above on
new, modified and reconstructed small well sites).
Table 15--Summary of Methane Emissions Reductions and Cost-Effectiveness: AVO Inspections at Existing Single
Wellhead Only Well Sites and Small Well Sites
----------------------------------------------------------------------------------------------------------------
Methane
Annual cost ($/ emission Total cost- Incremental cost-
Monitoring frequency yr/site) reduction (tpy/ effectiveness ($/ton effectiveness ($/ton
site) methane) methane)
----------------------------------------------------------------------------------------------------------------
Annual.............................. $296 0.11 $2,579 ....................
Semiannual.......................... 417 0.40 1,048 429
Quarterly........................... 660 0.56 1,181 1,511
Bimonthly........................... 904 0.63 1,443 3,618
Monthly............................. 1,633 0.69 2,367 11,455
----------------------------------------------------------------------------------------------------------------
Multi-wellhead only well sites. Table 16 summarizes the costs
associated with OGI monitoring at multi-wellhead only well sites and
Table 17 summarizes the costs associated with combined OGI and AVO
surveys at multi-wellhead only well sites. Based on the information
summarized in Table 16, the costs of annual, semiannual, quarterly, and
bimonthly OGI monitoring is reasonable when compared to a baseline of
no monitoring. When examining the incremental costs of going from
semiannual OGI to quarterly OGI, the costs are not reasonable at
$2,620/ton methane reduced. The EPA next evaluated the costs associated
with adding AVO inspections to semiannual OGI monitoring to determine
if additional emission reductions could be achieved at a reasonable
cost. Based on the information summarized in Table 17, all programs
presented are cost-effective when compared to a baseline of no
monitoring. When examining the incremental costs of going from a
combined program of semiannual OGI with quarterly AVO inspections to
one with bimonthly AVO inspections, the costs are not reasonable at
$3,394/ton methane reduced. Because the combined program of semiannual
OGI with quarterly AVO inspections is cost-effective and would result
in more visits to the well site, and thus provide opportunity to
address any emissions detected, the EPA is proposing that the BSER for
existing multi-wellhead only well sites is a combined program of
semiannual OGI with quarterly AVO inspections.
Table 16--Summary of Emission Reductions and Cost-Effectiveness: OGI Monitoring at Well Sites With Two or More
Wellheads
----------------------------------------------------------------------------------------------------------------
Methane
Annual cost ($/ emission Total cost- Incremental cost-
Monitoring frequency yr/site) reduction (tpy/ effectiveness effectiveness
site) methane ($/ton) methane ($/ton)
----------------------------------------------------------------------------------------------------------------
Baseline............................ .............. 2.66 .................... ....................
Annual.............................. $1,972 1.18 $1,677 ....................
Semiannual.......................... 2,327 1.79 1,300 578
Quarterly........................... 3,037 2.06 1,473 2,620
Bimonthly........................... 3,747 2.15 1,741 7,799
Monthly............................. 5,877 2.24 2,619 23,140
----------------------------------------------------------------------------------------------------------------
Table 17--Summary of Methane Emissions Reductions and Cost-Effectiveness: Combined OGI Monitoring and AVO
Inspections at Existing Multi-Wellhead Only Well Sites
----------------------------------------------------------------------------------------------------------------
Methane
Annual cost ($/ emission Total cost- Incremental cost-
Monitoring frequency yr/site) reduction (tpy/ effectiveness effectiveness
site) methane ($/ton) methane ($/ton)
----------------------------------------------------------------------------------------------------------------
Semiannual OGI...................... $2,327 1.79 $1,300 ....................
OGI + Quarterly AVO................. 2,651 1.99 1,331 $1,606
OGI + Bimonthly AVO................. 2,973 2.09 1,425 3,394
OGI + Monthly AVO................... 3,671 2.16 1,822 12,728
----------------------------------------------------------------------------------------------------------------
Well sites with major production and processing equipment and
centralized production facilities. Table 18 summarizes the costs
associated with OGI monitoring and Table 19 summarizes the costs of
combined OGI and AVO surveys at existing well sites and centralized
production facilities with major production and processing equipment.
The EPA is proposing the same definition for these well sites,
including the specific equipment that
[[Page 74739]]
constitutes a well site in this subcategory (e.g., leak-prone
equipment, such as controlled storage vessels). Based on the
information summarized in Table 18, all monitoring frequencies appear
cost-effective when compared to a baseline of no monitoring. When
incremental costs are considered, the costs of going from quarterly to
bimonthly OGI monitoring is not reasonable. The EPA then evaluated if
AVO inspections could be added to the quarterly OGI monitoring at a
reasonable cost. As shown in Table 19, all programs presented are cost-
effective when compared to a baseline of no monitoring. When examining
the incremental costs of going from a quarterly OGI program to a
combined program of quarterly OGI with bimonthly AVO inspections, the
costs are not reasonable at $2,497/ton methane reduced. Therefore, the
EPA is proposing quarterly OGI monitoring for these sites. In sum, the
EPA is proposing that the BSER for existing well sites with major
production and processing equipment and centralized production
facilities consists of quarterly OGI monitoring and the closed and
sealed requirement for thief hatches (as explained above in the
discussion on new, modified or reconstructed small well sites).
Table 18--Summary of Emission Reductions and Cost-Effectiveness: OGI Monitoring at Well Sites With Major
Production or Processing Equipment
----------------------------------------------------------------------------------------------------------------
Methane
Annual cost ($/ emission Total cost- Incremental cost-
Monitoring frequency yr/site) reduction (tpy/ effectiveness effectiveness
site) methane ($/ton) methane ($/ton)
----------------------------------------------------------------------------------------------------------------
Baseline............................ .............. 8.51 .................... ....................
Annual.............................. $2,162 3.99 $542
Semiannual.......................... 2,588 5.73 452 $244
Quarterly........................... 3,440 6.61 520 969
Bimonthly........................... 4,292 6.97 616 2,398
Monthly............................. 6,848 7.26 943 8,676
----------------------------------------------------------------------------------------------------------------
Table 19--Summary of Methane Emissions Reductions and Cost-Effectiveness: Combined OGI Monitoring and AVO
Inspections at Existing Well Sites With Major Production and Processing Equipment and Centralized Production
Facilities
----------------------------------------------------------------------------------------------------------------
Methane
Annual cost ($/ emission Total cost- Incremental cost-
Monitoring frequency yr/site) reduction (tpy/ effectiveness effectiveness
site) methane ($/ton) methane ($/ton)
----------------------------------------------------------------------------------------------------------------
Quarterly OGI....................... $3,440 6.61 $520 ....................
OGI + Bimonthly AVO................. 4,232 6.93 611 $2,497
OGI + Monthly AVO................... 5,021 7.10 707 4,616
----------------------------------------------------------------------------------------------------------------
2. OGI Monitoring at Compressor Stations
a. NSPS OOOOb
In the November 2021 proposal, the EPA proposed that compressor
stations would be required to conduct quarterly OGI or EPA Method 21
monitoring. Where OGI monitoring was used to perform the quarterly
monitoring surveys, the EPA proposed surveys would be conducted
according to the procedures proposed in the November 2021 proposal as
appendix K.
In this supplemental proposal, the EPA is retaining the proposed
quarterly OGI (or EPA Method 21) monitoring requirement for fugitive
emissions components affected facilities located at compressor stations
(including the requirement that consecutive quarterly monitoring survey
be conducted at least 60 days apart). Also, as in the November 2021
proposal, the supplemental proposal includes the provision in the 2016
NSPS OOOOa that the quarterly monitoring may be waived when
temperatures are below 0 [deg]F for two of three consecutive calendar
months of a quarterly monitoring period.
In addition, the EPA is proposing to add a requirement to conduct
monthly AVO monitoring at compressor stations. As discussed above for
well sites, the EPA finds these AVO monitoring requirements can be
conducted by any personnel at the site as indications of emissions can
be identified without the need for specialized training. Any
indications of fugitive emissions identified via AVO would be subject
to repair. The EPA specifically received comments on the November 2021
proposal that indicated that ``even though small company compressor
stations are not manned 24 hours a day, they are visited weekly, if not
daily.'' \80\ Therefore, no additional costs are associated with the
proposed monthly AVO inspection requirement for compressor stations.
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\80\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0585 and EPA-HQ-
OAR-2021-0317-0814.
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While the EPA is maintaining (and strengthening in the case of the
monthly AVO requirement) the November 2021 proposal as it relates to
the collection of fugitive emissions components located at compressor
stations, the EPA is not including the requirement to conduct OGI
monitoring surveys according to the procedures that would become
appendix K. See discussion in section IV.A.1.a.ii on comments received
opposing this requirement. Instead, the EPA is proposing that quarterly
surveys be performed according to the OGI procedures specified in the
proposed regulatory text in NSPS OOOOb or according to EPA Method 21.
b. EG OOOOc
Based on the analysis presented in section XII.A.2 of the 2021
November proposal preamble (86 FR 63196; November 15, 2021), the
proposed BSER for EG OOOOc for reducing methane emissions from existing
compressor stations was quarterly monitoring (using either OGI or EPA
Method 21).
Based on the same public comment considerations and reasoning as
explained above (see sections IV.A.2.a.ii
[[Page 74740]]
of this preamble) for changes to the proposed NSPS OOOOb for fugitive
emissions at compressor stations, the EPA is proposing the same changes
and requirements under EG OOOOc. The EPA did not identify any factors
specific to existing sources that would alter the analysis performed
for new sources to make that analysis different for existing compressor
stations. The EPA determined that the methods for identifying fugitive
emissions (i.e., AVO, OGI, and EPA Method 21), methane emission
reductions, costs, and cost effectiveness discussed above for the
fugitive emissions components affected facility at new compressor
stations are also applicable for the fugitive emissions components
affected facility at existing compressor stations. The fugitive
emissions requirements do not require the installation of controls on
existing equipment or the retrofit of equipment, which can generally be
an additional factor for consideration when determining the BSER for
existing sources. Therefore, the EPA found it is appropriate to
continue using the analysis developed for the proposed NSPS OOOOb to
also determine the BSER and proposed presumptive standards for the EG
OOOOc.
3. OGI Monitoring at Well Sites and Compressor Stations on the Alaska
North Slope
a. NSPS OOOOb
In the November 2021 proposal, the EPA proposed an annual
monitoring requirement for well sites and compressor stations located
on the Alaska North Slope, which included a requirement to follow the
procedures outlined in the proposed appendix K where monitoring was
conducted using OGI.
In this supplemental proposal, the EPA is retaining the proposed
annual monitoring requirement for well sites and compressor stations
located on the Alaska North Slope. Consecutive annual monitoring
surveys would be required at least 9 months apart and no more than 13
months apart. For the reasons discussed in section IV.A.1.a.ii, the EPA
is not including the requirement to follow the proposed procedures in
appendix K when conducting monitoring surveys with OGI. The EPA is
proposing that annual surveys be performed according to the OGI
procedures specified in the proposed regulatory text in NSPS OOOOb or
according to EPA Method 21 of appendix A-7 of this part.
b. EG OOOOc
Based on the analysis presented in section XII.A.2 of the November
2021 proposal preamble (86 FR 63196; November 15, 2021), the proposed
BSER for EG OOOOc for reducing methane emissions from existing well
sites and compressor stations located on the Alaska North Slope was
annual monitoring.
In this supplemental proposal, the EPA is retaining the annual
monitoring requirement for existing well sites and compressor stations
located on the Alaska North Slope. As discussed in the November 2021
proposal, the same technical infeasibility issues with weather
conditions exist for existing well sites and compressor stations
located on the Alaska North Slope as for new well sites and compressor
stations. Further, the EPA did not identify any other factors specific
to existing sources located on the Alaska North Slope that would alter
the analysis performed for new sources to make that analysis different
for existing well sites and compressor stations. Therefore, the EPA is
proposing a presumptive standard for reducing methane emissions from
the fugitive emissions components designated facilities located at
existing well sites and compressor stations located on the Alaska North
Slope that is the same as what we are proposing for NSPS OOOOb.
B. Advanced Methane Detection Technologies
As discussed in section XI.A.5 of the November 2021 proposal
preamble (86 FR 63175; November 15, 2021), the EPA proposed an
alternative screening option that would allow the use of advanced
measurement technologies as an alternative to the use of ground based
OGI surveys and AVO inspections to identify emissions from the
collection of fugitive emissions components located at well sites,
centralized production facilities, and compressor stations. In the
November 2021 proposal, the EPA stated that we did not have enough
information to determine how the proposed alternative standard (i.e.,
bimonthly screening using advanced measurement technologies) compared
to the proposed BSER of OGI monitoring in that notice. Further we
stated that information provided through comments to the November 2021
proposal may be used to reevaluate BSER for fugitive emissions
components at well sites and compressor stations through a supplemental
proposal.\81\ As described below, commenters overwhelmingly supported
the concept of an alternative screening option that would allow owners
and operators to take advantage of advanced measurement technologies to
detect fugitive emissions. Commenters also provided helpful information
and input on how the alternative screening option could be made more
useful and effective, including flexibilities that could be
incorporated into the program design to enable the use of a wider
variety of advanced measurement technologies. While there was
widespread support of the concept of an alternative screening option,
the EPA still does not have enough information to conduct the requisite
BSER analysis \82\ for any specific advanced measurement technology to
determine whether it would qualify as the BSER for detecting fugitive
emissions (either in lieu of or in addition to OGI). The EPA, however,
does anticipate that through this alternative screening option, if
finalized as proposed and utilized by the industry, the Agency would
gain additional information that could be used to reevaluate the BSER
in a future rulemaking.
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\81\ 86 FR 63177 (November 15, 2021).
\82\ Please see CAA section 111(a)(1) for a list of factors,
including costs, that the EPA must take into account when
determining whether an emission reduction system would qualify as
the BSER.
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In response to this feedback, the EPA is proposing a number of
changes to the alternative screening option that are intended to
support the deployment and utilization of a broader spectrum of
advanced measurement technologies and, ultimately, enable more cost-
effective reductions in emissions. These changes include a proposed
``matrix'' which would specify several different screening frequencies
corresponding to a range of minimum detection levels, in contrast to
the single screening frequency and detection level permitted under the
November 2021 proposal. In addition, we are proposing to allow owners
and operators the option of using continuous monitoring technologies as
an alternative to periodic screening and are proposing long- and short-
term emissions rate thresholds that would trigger corrective action as
well as monitoring plan requirements for owners and operators that
choose this approach.
Lastly, we are proposing to establish a clear and streamlined
pathway for technology developers and other entities to seek the EPA's
approval for the use of advanced measurement technologies under this
alternative screening option. Under this pathway, entities would seek
approval for alternative test methods to demonstrate the performance of
[[Page 74741]]
alternative technologies, which would replace the use of OGI and AVO
for fugitive emissions monitoring and the use of OGI for no
identifiable emissions monitoring of covers and CVS (see section IV.K
of this preamble) in both the proposed NSPS OOOOb and EG OOOOc. Once an
alternative test method is approved by the EPA according to the
proposed process, which is described in more detail below in Section
IV.B.3, owners and operators would be able to utilize the advanced
methane detection technology/technique in accordance with the
alternative test method without the need for additional approval.
Section IV.B.1 of this preamble discusses the use of advanced
measurement technology in an alternative periodic screening approach.
Section IV.B.2 of this preamble discusses the use of advanced
measurement technologies in a continuous monitoring approach as a
second alternative approach to the fugitive emissions monitoring and
repair program and no identifiable emissions monitoring of covers and
CVS in NSPS OOOOb and EG OOOOc. Section IV.B.3 of this preamble
discusses the requirements for applying for an alternative test method,
including who can submit an application for an alternative test method.
Once an alternative test method is approved by the EPA, owners and
operators would be able to utilize the advanced methane detection
technology/technique in accordance with the alternative test method
without the need for additional approval.
1. Alternative Periodic Screening
a. Summary of November 2021 Proposal
The EPA proposed an alternative fugitive emissions monitoring and
repair program for new, modified, or reconstructed fugitive emissions
sources (i.e., collection of fugitive emissions components located at
well sites, centralized production facilities, and compressor stations)
that included bimonthly screening for large emissions events using
advanced measurement technologies coupled with ground based OGI
monitoring at least annually at each site. Specifically, the EPA
proposed to allow owners and operators to comply with this alternative
fugitive emissions standard instead of the ground-based quarterly or
(co-proposed) semiannual OGI surveys for regulated sources, so long as
owners and operators chose this alternative for all affected well
sites, centralized production facilities, and compressor stations
within a company-defined area and the methane detection technology used
for the bimonthly screening surveys had a demonstrated minimum
detection threshold of 10 kg/hr.
In the November 2021 proposal, the EPA sought comment on this
minimum detection threshold for the advanced measurement technologies
used in the alternative screening approach and solicited data on the
current detection sensitivity of commercially available methane
detection technologies as deployed, as well as other data that could be
used to support consideration of a different minimum detection
threshold. The EPA also solicited comment on development of a survey
matrix for the alternative screening approach option, where instead of
prescribing one detection threshold and screening frequency, the
frequency of screening surveys would be based on the sensitivity of the
technology (i.e., screening surveys performed with technologies with
the lower detection thresholds would need to be performed less
frequently than screening surveys performed with technologies with
higher detection thresholds).
The November 2021 proposal also included a requirement for owners
and operators to include information specific to the alternative
screening approach in their fugitive emissions monitoring plan. This
would include information on which sites are utilizing this alternative
screening option; a description of the measurement technology used for
screenings; verification of the methane detection threshold, with
supporting data to support the verification; procedures for daily
verification of sensitivity under field conditions; standard operating
procedures; and methodology for conducting the screening. The EPA
solicited comment on when notifications would be required for sites
where the alternative standard is applied and whether submission of the
monitoring plan and/or Agency approval before utilizing the alternative
standard was necessary to ensure consistency in screening survey
procedures in the absence of finalized methods or procedures.
When fugitive emissions are detected through a periodic screening
survey, the EPA proposed to require a ground based OGI survey of all
fugitive emissions components at the site within 14 days of the
screening survey. Due to the significance of the emissions events
detected through screening, an expeditious timeframe was proposed, but
the EPA requested additional information to fully evaluate the
appropriateness of this proposed 14-day deadline for a follow-up OGI
survey. Further, the EPA proposed to require repair of all fugitive
emissions identified during the follow-up OGI survey in accordance with
the same repair deadlines as those for regular fugitive surveys (i.e.,
a first attempt at repair within 30 days of the OGI survey and final
repair completed within 30 days of the first attempt). However, because
large emissions events, especially those identified during the
screening surveys, contribute disproportionately to emissions, the EPA
solicited comment on creating a tiered repair deadline requirement that
would be based on the severity of the fugitive emissions identified.
The EPA also noted that some equipment types with large emissions
warrant a requirement for a root cause analysis rather than simply
requiring the equipment to be repaired and solicited comment on how a
root cause analysis with corrective action approach could be applied in
the proposed alternative screening approach.
b. Changes to Proposal and Rationale
The EPA received overwhelming support for the inclusion of an
option to use advanced technologies for periodic screenings as an
alternative to the fugitive emissions monitoring and repair program
proposed in NSPS OOOOb and EG OOOOc. However, commenters remarked that
the Agency failed to provide sufficient supporting evidence for the
proposed minimum detection threshold of 10 kg/hr. Commenters provided
alternative minimum detection thresholds and/or monitoring frequencies;
many of these commenters provided supporting evidence for equivalency
to the proposed fugitive emission monitoring and repair program in NSPS
OOOOb and EG OOOOc, including results from LDAR program effectiveness
models, such as FEAST. However, the results of these models varied
widely, and as such, it was difficult to compare the different
thresholds and frequencies presented by commenters. Additionally, one
commenter suggested the EPA should investigate the role of modeling in
equivalency demonstrations because the modeling outputs are highly
impacted by the model inputs and assumptions made in the models.\83\
Commenters also encouraged the EPA to adopt a survey matrix for the
alternative screening approach option that would allow owners and
operators to vary the frequency of periodic screening surveys based on
the detection sensitivity of the screening survey technology.
Commenters stated that the EPA should
[[Page 74742]]
use existing publicly available LDAR program effectiveness models \84\
to determine a matrix of survey frequencies and detection thresholds
that would provide a demonstration of equivalency between the
alternative screening and the standard fugitive emissions monitoring
and repair program.
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\83\ See Document ID No. EPA-HQ-OAR-2021-0317-0747.
\84\ Currently, the free publicly available simulation models
are Fugitive Emissions Abatement Simulation Toolkit (FEAST) and Leak
Detection and Repair Simulator (LDAR-Sim).
---------------------------------------------------------------------------
Based on these comments and subsequent discussions with
commenters,\85\ the EPA decided that the best course of action for
determining equivalency between different fugitive emission programs
would be to run one of the leak detection and repair program
effectiveness models with a set of standardized model inputs. For this
effort, the EPA chose to conduct the modeling using FEAST so we could
directly compare alternatives to the results of the OGI fugitive
emissions program proposed as the BSER described in section IV.A of
this preamble.\86\
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\85\ See February 18, 2022, memorandum, Summary of Meeting with
American Petroleum Institute, and February 28, 2022, memorandum,
Summary of Meeting with Environmental Defense Fund located at Docket
ID No. EPA-HQ-OAR-2021-0317.
\86\ The EPA used FEAST version 3.1 to model the various
programs. While the EPA used FEAST in this modeling exercise, the
EPA would expect other available modeling simulation tools to
produce similar results.
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Based on recent aerial and satellite studies,\87\ \88\ a primary
advantage of more frequent screening with advanced technologies is to
quickly identify large emission events (commonly referred to as
``super-emitters''). These super-emitters may be the result of large
leaks from fugitive emissions components, but may also result from
other sources, such as unlit flares or process malfunctions. Therefore,
for this equivalency assessment, the EPA included emissions from other
sources beyond fugitive emissions components that contribute to these
super-emitters. This emissions distribution was developed using aerial
study data from Cusworth, et al.,\89\ and supplemented to include
additional leaks between the lower limits of detection of the aerial
surveys (about 15 to 20 kg/hr) and high-flow samplers commonly used in
ground-level quantification studies (maximum quantification limit of
about 9 kg/hr). The EPA assumed the small model plants (Model Plants 1
and 2) have one potential super-emitter source and that the larger
model plant (Model Plant 4) has two potential super-emitter sources.
The EPA evaluated the impact of different super-emitter frequencies but
conducted the equivalency modeling using the 1.0 percent leak
generation rate based on data from Zavala-Araiza, et al.\90\
Additionally, the EPA performed a sensitivity analysis where we assumed
a 1.0 percent leak generation rate for larger emissions sources
commonly identified using aerial screening technologies (>26 kg/hr) and
a 0.5 percent leak generation rate for fugitive emissions components
consistent with the analysis for OGI and AVO programs described in
section IV.A. More detail on the FEAST modeling assumptions and
simulations is provided in the Supplemental TSD for this action located
at Docket ID No. EPA-HQ-OAR-2021-0317. The EPA solicits comment on the
use of LDAR effectiveness models in the development of the requirements
for the alternative screening approach, specifically on the
appropriateness of the inputs and assumptions used in the EPA's FEAST
modeling simulations.
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\87\ Chen, Yuanlei, et al. 23 Mar 2022, https://doi.org/10.1021/acs.est.1c06458.
\88\ Irakulis-Loitxate, Itziar, et al. 30 June 2021, https://doi.org/10.1126/sciadv.abf4507.
\89\ Cusworth, Daniel, et al. 2 June 2021, https://pubs.acs.org/doi/10.1021/acs.estlett.1c00173.
\90\ Zavala-Araiza, Daniel, et al. 16 Jan 2017, https://doi.org/10.1038/ncomms14012.
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In this action, the EPA is revising the proposal for the
alternative screening approach to provide additional flexibility to
owners and operators to show that the advanced technology for which
they are seeking approval would reduce fugitive emissions at least
equivalent to the reduction under the proposed fugitive emission
monitoring and repair program in NSPS OOOOb and EG OOOOc, as well as
the proposed covers and CVS requirements in NSPS OOOOb and EG OOOOc.
Instead of requiring a fixed screening survey frequency for all
technologies, the EPA is proposing a survey matrix, where the minimum
detection threshold of the screening technology determines the
frequency of screening surveys and whether an annual OGI ground-based
survey is needed as a supplement to the periodic screening surveys.
Tables 20 and 21 present the details of the screening matrix for
facilities required to conduct quarterly and semiannual OGI ground-
based monitoring under the proposed fugitive emissions monitoring and
repair program in NSPS OOOOb and EG OOOOc, respectively. Based on the
FEAST modeling the EPA performed, technologies with a minimum detection
threshold above 30 kg/hr could not be deemed equivalent to the proposed
fugitive emissions monitoring and repair program in NSPS OOOOb and EG
OOOOc at any screening survey frequency, even when coupled with an
annual OGI ground-based survey. As such, the alternative periodic
screening approach is limited to technologies with a minimum detection
threshold less than or equal to 30 kg/hr.
Table 20--Survey Matrix for Alternative Periodic Screening Approach for
Affected Facilities Subject to Quarterly OGI Monitoring a
------------------------------------------------------------------------
Minimum
detection
Minimum screening frequency threshold of
screening
technology \b\
------------------------------------------------------------------------
Quarterly + Annual OGI............................... <=1 kg/hr
Bimonthly............................................ <=2 kg/hr
Monthly.............................................. <=4 kg/hr
Bimonthly + Annual OGI............................... <=10 kg/hr
Monthly + Annual OGI................................. <=30 kg/hr
------------------------------------------------------------------------
\a\ Well sites with major production and processing equipment,
controlled storage vessels, natural gas-driven pneumatic controllers,
associated covers and closed vent systems, and control devices,
centralized production facilities, and compressor stations.
\b\ Based on a probability of detection of 90 percent.
[[Page 74743]]
Table 21--Survey Matrix for Alternative Periodic Screening Approach for
Single and Multi-Wellhead Only Sites and Small Well Sites
------------------------------------------------------------------------
Minimum
detection
Minimum screening frequency threshold of
screening
technology \a\
------------------------------------------------------------------------
Semiannual........................................... <=1 kg/hr
Triannual............................................ <=2 kg/hr
Triannual + Annual OGI............................... <=5 kg/hr
Quarterly + Annual OGI............................... <=15 kg/hr
Monthly + Annual OGI................................. <=30 kg/hr
------------------------------------------------------------------------
\a\ Based on a probability of detection of 90 percent.
These survey matrices will provide owners and operators who choose
to implement the alternative periodic screening approach a wider
selection of methane detection technologies from which to choose. The
matrices also provide clear goals for vendors interested in the
development of future technologies for methane detection. The EPA
solicits comments on the survey matrices developed for the alternative
periodic screening approach. Specifically, the EPA is interested in
comments regarding the applicability of this matrix to both currently
available technologies and those currently in development. Further,
where specific technologies may not easily work within the context of
the proposed matrix, we are soliciting detailed information on how
those specific technologies work, including empirical data that would
allow for additional evaluation of parameters in the proposed matrix;
how emissions reduction equivalency can be demonstrated for those
technologies compared with the standard OGI work practice; and changes
that would be needed to the proposed matrix and the basis for those
changes. Finally, we are soliciting feedback from owners and operators
on ways to improve and further incentivize use of the proposed matrix
approach to ensure they are comfortable utilizing any approved
alternative technologies and test methods.
To reflect changes made to the proposed alternative periodic
screening approach, the EPA is also modifying the proposed requirements
for site-specific monitoring plans. The EPA is proposing to allow
owners and operators to develop a site-specific monitoring plan or to
develop a monitoring plan that covers multiples sites. At a minimum,
the monitoring plan would need to contain the following information:
(1) Identification of each site that will be monitored through periodic
screening, including latitude and longitude coordinates; (2)
identification of the test method(s) used for the periodic screening;
(3) identification and contact information for the entity performing
the periodic screening; (4) frequency for conducting periodic
screenings; (5) procedures for conducting ground-based monitoring
surveys in response to confirmed emission detection events from
periodic screening surveys; (6) procedures and timing for identifying
and repairing fugitive emissions components, covers, and CVS; (7)
procedures and timing for verifying repairs for fugitive emissions
components, covers, and CVS, and (8) recordkeeping and retention
requirements.
The EPA is also clarifying the timeframes for when owners and
operators must conduct the initial periodic screening survey when
complying with the alternative periodic screening standard. In the
November 2021 proposal, the EPA did not include timeframes for
initiating periodic monitoring. The EPA is proposing that, for the
initial periodic screening survey must be conducted within 90 days of
the startup of production for each fugitive emissions components
affected facility and/or storage vessel affected facility located at a
new, modified, or reconstructed well site or centralized production
facility and have not begun any fugitive monitoring; within 90 days of
startup for each fugitive emissions components affected facility and
storage vessel affected facility located at a new compressor station;
and within 90 days of modification for each fugitive emissions
components affected facility and storage vessel affected facility
located at a modified compressor station. This 90-day initial screening
requirement is the same as that required for the OGI-based fugitive
emissions surveys. Additionally, the EPA is proposing that the initial
periodic screening survey must be conducted no later than the date of
the next required OGI fugitive emissions survey for any affected
facility that was previously complying with the proposed fugitive
emissions monitoring and repair program and proposed covers and CVS
requirements in NSPS OOOOb and EG OOOOc. The EPA solicits comment on
the proposed timing to perform the initial periodic screening survey,
including information to support different timeframes.
When the periodic screening survey identifies emissions, the EPA is
proposing to require a ground-based survey using OGI to identify the
source of the emissions and any other fugitive emissions present. Any
fugitive emissions identified during this ground-based survey would be
subject to repair requirements. For fugitive emissions components, the
EPA is proposing to require a completion of repairs within 30 days of
the screening survey. The EPA is proposing that if the ground-based
survey confirms that emissions were caused by a failure of a control
device, the owner or operator must initiate a root cause analysis and
determine appropriate corrective action within 24 hours of the ground-
based survey. Because a failure of a control device would likely result
in violations of the standards, the EPA is proposing appropriate
corrective action should be taken as soon as possible to address these
failures. Similarly, for covers and CVS, which are either fugitive
components or are subject to the proposed cover and CVS requirements,
the EPA is proposing to require repair within 30 days of the screening
survey. The EPA is also proposing that if a leak or defect in a cover
or CVS is identified, the owner or operator would be required to
perform a root cause analysis to determine the cause of emissions from
the cover or CVS within five days of completing the ground-based
inspection, in addition to requiring repair within 30 days of the
screening survey. The root cause analysis should include a
determination as to whether the system was operated outside of the
engineering design analyses and
[[Page 74744]]
whether updates are necessary for the system. Because covers and CVS
are required to be designed and operated with no identifiable
emissions, indications of emissions from these sources could result in
violations of the CVS requirements where the CVS is not a fugitive
emissions component. Therefore, the EPA is proposing that appropriate
corrective actions should be taken to resolve the emissions and ensure
that the no detectable emissions standard is continuously met. Examples
of corrective actions might include replacement of gaskets with a
material more suitable for the composition of materials in the storage
vessel or redesign of the entire CVS to ensure pressure setpoints are
appropriate for relief devices on storage vessels. The EPA understands
that the length of time necessary to complete corrective actions will
vary based on the specific action taken. Therefore, we are soliciting
comment on an appropriate deadline by which all corrective actions
should be completed that would account for variability in complexity
for such actions.
2. Alternative Continuous Monitoring Systems
a. Summary of November 2021 Proposal
In the November 2021 proposal, the EPA recognized that the
alternative screening approach as outlined above may not be well suited
to continuous monitoring technologies, such as sensors or open-path
technology, even though these technologies may meet the minimum methane
detection threshold (86 FR 63176; November 15, 2021). To incentivize
these continuous monitoring technologies, which could be valuable tools
in quickly detecting large emissions events, as well as identifying
when emissions at the site begin to rise, the EPA requested information
that could be used in an equivalence demonstration and would allow for
the development of a flexible framework that could cover multiple types
of continuous monitoring technologies and be used as a second
alternative approach to the fugitive emissions monitoring and repair
program in NSPS OOOOb and EG OOOOc. Specifically, the EPA requested
information on the number of continuous monitors needed on a site,
placement criteria for these monitors, response factors, minimum
detection levels, frequency of data readings, how to interpret the
monitor data to determine the difference between detected emissions and
baseline emissions, how to determine allowable emissions versus leaks,
the meteorological data criteria, measurement systems data quality
indicators, calibration requirements and frequency of calibration
checks, how downtime should be handled, and how to handle situations
where the source of emissions cannot be identified even when the
monitor registers a leak.
b. Changes to Proposal and Rationale
In response to the solicitation for comment on the development of a
framework for continuous monitoring technologies in the November 2021
proposal, the EPA received comments from vendors, trade groups,
industry, and environmental groups in support of developing a framework
for these technologies. Many of these commenters discussed the benefits
of continuous monitoring systems including the low detection
sensitivities of the technologies, the potential savings involved in
identifying the largest leaks in near real time, and the potential to
repair leaks on a much quicker timeframe. The EPA is proposing a
framework for continuous monitoring technologies that is akin to the
fenceline monitoring work practice promulgated by the EPA in 2015 as
part of the National Emissions Standards for Hazardous Air Pollutants
(NESHAP) for the petroleum refinery sector (80 FR 75178; December 1,
2015). Under this proposed approach, an owner or operator utilizing
continuous monitoring technologies would conduct a root cause analysis
and corrective action whenever a methane emission rate action-level is
exceeded at the boundary of a facility.
The EPA is proposing methane emissions rate (i.e., kg/hr) based
action levels instead of methane concentration (e.g., ppmv) based
action levels (as in the Refineries NESHAP) in order to: (1) Account
for upwind contributions from other sites and meteorological effects
and (2) allow the Agency to evaluate the methane emissions reductions
achieved by this framework, thus providing for a metric to demonstrate
equivalency with the proposed fugitive emissions monitoring and repair
program and proposed covers and CVS requirements in NSPS OOOOb and EG
OOOOc. Through the comments received and subsequent discussions with
commenters,\91\ the EPA has gathered information on how these
continuous monitoring systems have been applied and how owners and
operators use the information from these systems to initiate a response
to identify and repair leaks. The application of these systems appears
to vary widely across the industry, with no consistent standard
currently employed. This is especially true for how sources initiate
identification of the cause of a leak. To standardize the use of these
systems across the industry, the EPA is proposing two action levels in
this alternative continuous monitoring approach: (1) A long-term action
level to limit emissions over time and (2) a short-term action level to
identify large leaks and malfunctions. Both action levels would apply
to all owners and operators choosing to use this alternative, and a
root cause analysis and corrective action would be triggered when
either action level is exceeded. The proposed long-term action levels
are developed from the same FEAST Model used for the development of the
proposed survey matrix for periodic screening and the action-levels are
based on the annual emissions (including super-emitters) of our Model
Plant 2 and Model Plant 3 discussed in section IV.A.2 of this preamble.
Based on this data, the EPA is proposing an action-level of 1.2 kg/hr
\92\ for sites consisting of only wellheads and 1.6 kg/hr \93\ for all
other well sites and compressor stations with equipment. This long-term
action level would be based on a rolling 90-day average, where the 90-
day average would be recalculated each day. The EPA is also proposing a
short-term action-level of 15 kg/hr for sites consisting of only
wellheads and 21 kg/hr for other well sites and compressor stations.
These action levels are based on the same magnitude of emissions as the
long-term action level; however, the rates are defined over the period
of seven days. The short-term action level would be based on a rolling
7-day average, where the 7-day average would be recalculated each day.
The EPA solicits comment on the proposed short-term and long-term
action levels. The EPA is also aware of industry led efforts \94\ to
minimize methane emissions through the entirety of the value chain
using the percentage of intensity or production as a metric. The EPA is
soliciting comment on the potential use of intensity or production in
the development of action levels, including appropriate thresholds for
setting such action levels on both a short-term and long-term basis.
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\91\ See memorandum, Summary of Meetings on Alternative
Screening and Continuous Monitoring Systems located at Docket ID No.
EPA-HQ-OAR-2021-0317.
\92\ 11.6 tons per year methane.
\93\ 15.5 tons per year methane.
\94\ One Future Coalition.
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The EPA is aware of other continuous monitoring systems using
technologies that are not designed to quantify a site-level methane
emissions rate (e.g.,
[[Page 74745]]
camera based continuous systems). While the EPA believes these systems
could be useful in a methane mitigation program, they are not suitable
for the proposed alternative continuous monitoring approach because
they are not capable of quantifying site-level methane emissions, which
is the basis for the equivalency demonstration of the proposed
alternative continuous monitoring approach. That said, the EPA solicits
comment on how these types of systems could fit within the alternative
continuous monitoring approach, what action levels should be applied to
a non-emission rate based continuous monitoring system, and data to
support those action levels in order to conduct an equivalency
demonstration. The EPA also solicits comment on whether a different
type of approach should be used for these other types of continuous
monitoring systems, and if so, what that approach would look like and
how equivalency could be demonstrated between the approach and the
proposed fugitive emissions monitoring and repair program and proposed
covers and CVS requirements in NSPS OOOOb and EG OOOOc.
The EPA is proposing that owners and operators must initiate a root
cause analysis within 5 calendar days of an exceedance of either the
short-term or long-term action level. Additionally, the EPA is
proposing that the initial corrective action identified must be
completed within five calendar days of an exceedance of the short-term
action level and within 30 calendar days of an exceedance of the long-
term action level. If, upon completion of the initial corrective
actions, the continuous monitor readings remain above an action level,
or if all identified corrective action measures require more than 30
days to complete, the owner or operator would be required to develop a
corrective action plan and submit it to the Administrator within 60
calendar days of the initial action level exceedance. The EPA is
soliciting comment on the proposed requirements for the root cause
analysis and corrective action, the timeframes for conducting these
activities, and the requirement for corrective action plan submittals.
In order to ensure that the continuous monitoring systems used in
the alternative continuous monitoring approach are sensitive enough to
trigger at the proposed action levels, the EPA is proposing that the
continuous monitoring systems must have a detection level an order of
magnitude less than the proposed action level and that the system must
produce a valid mass emissions rate (i.e., kg/hr) from the site at
least once every twelve hours. The EPA is also proposing requirements
related to operability of the monitors within the continuous monitoring
system. Specifically, the EPA is proposing that the operational
downtime of the continuous monitoring system, or the time that any
monitor fails to collect or transmit quality assured data, must be less
than or equal to 10 percent on a 12-month rolling average, where the
12-month average is recalculated each month. We are soliciting comment
on this approach to addressing downtime and other ways to address
system downtime and the consequences of that downtime.
Similar to the alternative periodic screening approach, owners and
operators who choose to implement the alternative continuous monitoring
approach must develop a monitoring plan. The monitoring plan can either
be a site-specific monitoring plan or cover multiples sites. At a
minimum, the monitoring plan would need to contain the following
information: (1) Identification of each site that will be monitored
through periodic screening, including latitude and longitude
coordinates; (2) identification of the test method(s) used for the
continuous monitoring; (3) identification and contact information for
the entity performing the continuous monitoring if the continuous
monitoring system is administered through a third-party provider; (4)
number and location of monitors; (5) system calibration procedures and
schedules; (6) identification of critical components and procedures for
their repairs; (7) procedures for out of control periods; (8)
procedures for determining when a fugitive emissions event is detected
by the continuous monitoring technology; (9) procedures and timing for
identifying and repairing fugitive emissions components, covers, and
CVS; (10) procedures and timing for verifying repairs for fugitive
emissions components, covers, and CVS, and (11) recordkeeping and
retention requirements.
The EPA is proposing that owners and operators who choose to comply
with the alternative continuous monitoring approach must install and
begin conducting monitoring with the continuous monitoring system
within 120 days of the startup of production for each fugitive
emissions components affected facility or storage vessel affected
facility located at a new, modified, or reconstructed well site or
centralized production facility; within 120 days of startup for each
fugitive emissions components affected facility and storage vessel
affected facility located at a new compressor station; and within 120
days of modification for each fugitive emissions components affected
facility and storage vessel affected facility located at a modified
compressor station. Additionally, the EPA is proposing the continuous
monitoring system must begin monitoring no later than the date of the
next scheduled OGI monitoring survey for any affected facility that was
previously complying with the proposed fugitive emissions monitoring
and repair program and proposed covers and CVS requirements in NSPS
OOOOb and EG OOOOc. The EPA solicits comment on the proposed timing to
install and begin conducting monitoring with the continuous monitoring
system, including information to support different timeframes.
The EPA is soliciting comment on this proposed alternative
continuous monitoring approach, especially the use of site-level
methane emissions as a surrogate for VOC emissions, the practicality of
implementing the proposed framework, and any additional data on how
continuous monitoring technologies have been deployed at well sites,
centralized production facilities, and compressor stations. The EPA
proposes to use the continuous monitoring system to confirm the
effectiveness of the corrective action and has proposed additional
repair and notification requirements for when corrective action is
delayed or when the corrective action is ineffective.
3. Alternative Test Method Approval
a. Summary of November 2021 Proposal
The EPA solicited comment on whether owners and operators choosing
to comply with the alternative periodic screening approach would need
to submit their monitoring plan to the delegated authority and whether
Agency approval was necessary before the owner or operator could
implement the alternative. The EPA proposed that EPA approval may be
necessary to ensure consistency in screening survey procedures in the
absence of finalized methods and procedures.
b. Changes to Proposal and Rationale
The EPA received comments from industry, state agencies, and non-
governmental organizations acknowledging that review and approval of
individual monitoring plans increases the burden on industry.
Additionally, the review of these monitoring plans increases the burden
on delegated authorities to evaluate the alternative technologies and
may result
[[Page 74746]]
in inconsistent application or variable approvals for the same
technology between different states. The EPA also received direct
comment \95\ from one state that expressed that the EPA should serve as
the clearinghouse for approving these advanced measurement techniques.
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\95\ See Document ID No. EPA-HQ-OAR-2021-0317-0763.
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The EPA continues to find that, prior to implementation, approval
of the technologies used in the alternative periodic screening approach
and the alternative continuous monitoring approach is necessary due to
the lack of standard methods and performance specifications for these
types of systems. Approval of these systems will allow a wider range of
methane detection techniques to be applied, but also allow the Agency
to provide more specific guidance on the proper operation of these
systems. Based on the comments received, the EPA is proposing to
require these systems to be approved by the Administrator under the
alternative test method provisions in 40 CFR 60.8(b)(3) instead of
owners and operators seeking approval of these systems through site-
specific monitoring plans. The use of the alternative test method
provisions has typically been applied to the approval of alternative
test methods used to conduct performance testing to demonstrate
compliance with a numerical emission standard. While work practice
standards are not numerical emission standards, there is precedent for
approving alternative test methods within work practice standards, so
long as the change in the testing or monitoring method or procedure
will provide a determination of compliance status at the same or higher
stringency as the method or procedure specified in the applicable
regulation.96 97 The EPA is soliciting comment on the use of
this provision at 40 CFR 60.8(b)(3) for the approval of the alternative
test method for an alternative technology for measurements within the
proposed alternative periodic screening approach and the proposed
alternative continuous monitoring approach.
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\96\ In amendments to the approval of state programs and
delegation of federal authorities, the EPA clarified that certain
provisions within work practices, such as those related to
compliance and enforcement provisions, are delegable provisions. In
particular, the EPA stated that monitoring requirements are
delegable. See 65 FR 55810 (September 14, 2000).
\97\ The fenceline monitoring work practice in 40 CFR part 63
subpart CC allows owners and operators to seek an alternative test
method for use of technologies other than the prescribed sorbent
tube monitoring with Method 325 A and B of appendix A to 40 CFR part
63. See 40 CFR 63.658(k)(1).
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Once an alternative test method for an alternative technology has
been approved, if it is broadly applicable, the EPA will post it to the
Emission Measurement Center website.\98\ Any owner or operator who
meets the specific applicability for the alternative test method, as
outlined in the alternative test method, may use the alternative test
method to comply with the alternative periodic screening approach or
alternative continuous monitoring approach. The owner or operator would
be required to notify the Administrator of adoption of the alternative
periodic screening approach or alternative continuous monitoring
approach in the first annual report following implementation of the
alternative standard. The owner or operator's fugitive emissions
monitoring plan would identify the approved alternative test method(s)
the owner or operator is using the alternative periodic screening
approach or alternative continuous monitoring approach.
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\98\ https://www.epa.gov/emc/oil-andgas-approved-alternative-test-methods.
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In an effort to streamline the approval process and reduce the time
needed for processing these request for alternative test methods, the
EPA is proposing the following pre-qualifications for those requesting
approval of their technology: (1) Requestors are limited to any
individual or organization located in or that has representation in the
U.S.; (2) requestor must have direct knowledge of the design,
operation, and characteristics of the underlying technology; (3) the
underlying technology must have been applied to methane measurements in
the oil and gas production, processing, and/or transmission and storage
sectors either domestically or internationally; (4) the technology must
be a commercial product, meaning it has been sold, leased, or licensed,
or offered for sale, lease, or license, to the general public. While
the EPA has based these pre-qualifications on comments received from
vendors or advanced methane detection technologies, the EPA solicits
comments on how we have characterized the pre-qualifications in this
proposal and whether any additional pre-qualifications may be
appropriate.
In an effort to streamline the approval of these requests by
ensuring adequate information is received in the request to allow a
full evaluation of the alternative technology, the EPA is proposing
that any application for an alternative test method contain the
following information at a minimum: (1) The desired applicability of
the technology (i.e., site-specific, basin-specific or broadly
applicable across the sector); (2) a description of the measurement
systems; (3) supporting information verifying that the technology meets
the desired detection threshold(s) as applied in the field; (4) a
detailed description of the alternative testing procedure(s), including
data quality objectives to ensure the detection threshold(s) are
maintained and procedures for a daily verification check of the
measurement sensitivity under field conditions, and; (5) standard
operating procedures consistent with the EPA's guidance and including
safety considerations, measurement limitations, personnel
qualification/responsibilities, equipment and supplies, data and record
management, and quality assurance/quality control. The EPA solicits
comment on the proposed information required to be submitted with the
application of an alternative test method and whether the EPA should
consider requiring any additional information.
The EPA is proposing a defined timeframe for review and
determination of alternative test method requests by the Agency. The
EPA is proposing to issue either an approval or disapproval in writing
to the requestor within 270 days of receipt of the request, with a
number of milestones for acknowledgement of receipt and initial
reviews. The EPA is also proposing a mechanism to allow a conditional
approval of a submitted alternative test method in the event a
determination is not made by the Agency within 270 days. Finally, the
EPA is maintaining the authority to rescind any previous approval if we
find it reasonable to dispute the results of any alternative test
method used to demonstrate compliance with either the alternative
periodic screening approach or the alternative continuous monitoring
approach. The EPA proposes to make these approvals and the supporting
information available to the public on an EPA supported website. The
EPA solicits comments on the proposed timeframe to review and approve
alternative test methods and whether alternative timelines should be
considered.
C. Super-Emitter Response Program
Although results vary by basin, many studies have found that the
top five percent of sources contribute over 50 percent of the total
emissions.\99\ There is
[[Page 74747]]
wide agreement in the peer-reviewed research that a subset of sources
comprising the very largest emission events, commonly referred to as
super-emitters, is typically caused by abnormal operating conditions or
malfunctions.\100\
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\99\ Yuanlei Chen et al., ``Quantifying Regional Methane
Emissions in the New Mexico Permian Basin with a Comprehensive
Aerial Survey,'' Environmental Science and Technology, Vol. 56, No.
7 (March 2022), https://doi.org/10.1021/acs.est.1c06458.
\100\ Daniel Zavala-Araiza et al., ``Super-emitters in Natural
Gas Infrastructure are Caused by Abnormal Process Conditions,''
Nature Communications Vol. 8 (January 2017), https://doi.org/10.1038/ncomms14012; Ram[oacute]n A. Alvarez et al., ``Assessment of
Methane Emissions from the U.S. Oil and Gas Supply Chain,'' Science,
Vol. 361 (July 2018), https://doi.org/10.1126/science.aar7204;
Daniel H. Cusworth et al., ``Intermittency of Large Methane Emitters
in the Permian Basin,'' Environmental Science and Technology Letters
Vol. 8, No. 7 (June 2021), https://doi.org/10.1021/acs.estlett.1c00173; Jeffrey S. Rutherford et al., ``Closing the
Methane Gap in US Oil and Natural Gas Production Emissions
Inventories,'' Nature Communications Vol. 12 (August 2021), https://doi.org/10.1038/s41467-021-25017-4; Yuanlei Chen et al.,
``Quantifying Regional Methane Emissions in the New Mexico Permian
Basin with a Comprehensive Aerial Survey,'' Environmental Science
and Technology, Vol. 56, No. 7 (March 2022), https://doi.org/10.1021/acs.est.1c06458.
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Many of the requirements of this rule, when implemented correctly,
would result in reducing the number of super-emitter emissions events.
For the reasons described below, the EPA is further proposing a super-
emitter response program as a backstop to address the large
contribution of super-emitters to the pollution from this sector. For
purposes of this program, the EPA is proposing to define a super-
emitter emissions event as quantified emissions of 100 kg/hr or greater
of methane, a very high threshold that encompasses the largest
emissions events.
Recognizing that super-emitter emissions events are a significant
source of methane and VOC emissions, the November 2021 proposal and
this supplemental proposal contain standards and requirements that, if
implemented correctly, would prevent (e.g., via zero-emissions
standards for pneumatic controllers and design and operation
requirements for flares) or detect and mitigate (e.g., via regular
monitoring for fugitive emissions using OGI or advanced detection
technologies) most of these large emissions events.\101\ We note that
the estimated emission reductions in both the November 2021 proposal
and this supplemental proposal likely undercount the emission
reductions that would be achieved by this rule because they might not
fully account for the emissions resulting from all super-emitter
emissions events that would be prevented or quickly corrected as a
result of this rule. Though we are not currently able to quantify the
emissions reductions likely to result from preventing or more quickly
mitigating super-emitter emissions events, we note that the information
presented in appendix D to the RIA for this supplemental proposal
includes model simulations suggesting that covering large emitters
could ``significantly impact[] the expected emissions from the fugitive
emission program.'' \102\
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\101\ Super-emitter emissions events could also be from
intentional venting as part of normal operations or maintenance. The
proposed super-emitter response program discussed in this section is
not intended to address these events.
\102\ As stated, some of the model simulations in appendix D to
the RIA for this supplemental proposal suggest that large-emitters
could significantly impact the estimated emissions reductions;
however, those simulations are not directly related to the
definition of ``super-emitter'' included in this proposal, thus the
emissions and emission reductions cannot be used to directly assess
the emissions or emission reductions related to the proposed super-
emitter program. The model simulations relied on information of
large emissions from a single basin (Permian), and available data
suggest that the frequency of these events may vary significantly
across different production basins, which could lead to significant
uncertainty if the emission reductions were applied nationwide.
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It is clear from the estimates from the two proposals that these
methods are expected to result in the prevention, detection, and repair
of many current super-emitters. Sites that take advantage of
opportunities for continuous emissions monitoring offered by the
alternative monitoring strategies the EPA has proposed may be
particularly able to quickly identify and timely address these events.
However, super-emitters' significant impact on the communities
where they are located, as well as their greatly disproportionate
contribution to emissions in total, call for additional measures to
backstop compliance and address the unique characteristics of these
events. The abnormal process conditions that characterize these events
can be persistent or episodic, meaning that while some sources are
consistent super-emitters, many such large emissions events are
intermittent and can occur at different sites over time.\103\ A cost-
effective inspection program can therefore miss some of these super-
emitter events, even if implemented in accordance with the proposed
standards. We further note that oil and gas facilities, in particular
those in remote areas, may not have personnel present when super-
emitter emissions events occur. Given the large number and broad
geographic distribution of affected sources and designated facilities
to be regulated under this rule, the EPA also recognizes that the need
for rigorous compliance assurance will be particularly important in
this source category.
---------------------------------------------------------------------------
\103\ Daniel Zavala-Araiza et al., ``Super-emitters in Natural
Gas Infrastructure are Caused by Abnormal Process Conditions,''
Nature Communications Vol. 8 (January 2017), https://doi.org/10.1038/ncomms14012; Daniel H. Cusworth et al., ``Intermittency of
Large Methane Emitters in the Permian Basin,'' Environmental Science
and Technology Letters Vol. 8, No. 7 (June 2021), https://doi.org/10.1021/acs.estlett.1c00173.
---------------------------------------------------------------------------
The same sophisticated research and constantly advancing new
monitoring technologies that have contributed to our understanding of
the serious problem of super-emitters can bolster the other standards
and requirements included in this proposal and serve to help identify
and mitigate any super-emitter emissions events. The super-emitter
response program, which the EPA outlined conceptually in the November
2021 proposal for public comment and which we are now proposing here,
would allow the use of reliable and demonstrated remote sensing
technology deployed by experienced, certified entities or regulatory
authorities to find these large emissions sources. As described in the
November 2021 proposal, this proposed super-emitter response program
builds on the growing use of these advanced technologies by a variety
of entities to identify and mitigate super-emitting events.
This proposed program establishes a pathway by which an EPA-
approved entity or regulatory authority may provide credible, well-
documented identification of a super-emitter emissions event using one
of several permitted technologies and approaches, and then notify the
responsible owner or operator. Once notified of the event, owners and
operators would be required to perform a root-cause analysis and take
corrective actions to address the emissions source at their individual
well sites, centralized production facilities, and compressor stations.
Upon conducting the root-cause analysis, the owner or operator may
determine that all necessary and appropriate actions have been taken
and that no additional action is needed. However, if the owner or
operator confirms the existence of a super-emitter emissions event that
requires mitigation--either due to a failure to comply with one of the
standards in this rule or due to an upset or malfunction at a source
covered by this rule--then the owner or operator must take prompt steps
to eliminate the super-emitter emissions event and report both its
root-cause analysis and corrective actions to the EPA and the
appropriate state or tribal authority. To ensure this program operates
in a transparent manner, the EPA will make available in a document
repository the notices to operators that the EPA receives, as well as
the reports
[[Page 74748]]
sent to the EPA by owners and operators in response, so that notifiers,
communities, and owners and operators have quick access to the
information submitted to the EPA under the super-emitter provisions.
The EPA believes that the super-emitter response program proposed
here will provide a cost-effective and efficient mechanism for
comprehensively detecting and addressing super-emitter emission events,
complementing and reinforcing the other requirements of this proposal
and securing reductions in methane as well as emissions of VOCs and
other health-harming air pollutants. In response to the November 2021
proposal, the EPA received comments from representatives of communities
affected by air pollution from the oil and natural gas sector,
including communities with environmental justice (EJ) concerns, voicing
concern about the impacts of these emissions and support for enhanced
monitoring efforts. The EPA anticipates that the proposed super-emitter
response program will have important benefits for such communities and
will create opportunities for communities to partner with entities
engaged in remote sensing to monitor nearby sources of emissions. The
EPA also anticipates that the proposed transparency requirements for
notifications and for follow-up actions by owners and operators will
provide valuable information for communities about neighboring sources
of emissions and steps taken to mitigate them.
This section begins with a description of the November 2021
proposal and the comments received on that proposal, followed by a
description of the specific criteria the EPA is proposing for
notifications to sources of super-emitter events and subsequent
corrective actions taken to eliminate the emissions. The EPA seeks
comment on all aspects of this proposed program.
1. November 2021 Proposal
As described in the November 2021 proposal, ``industry,
researchers, and NGOs have utilized advanced methane detection systems
to quickly identify large emission sources and target ground based OGI
surveys. state and local governments, industry, researchers, and NGOs
have been utilizing advanced technologies to better understand the
detection of, sources of, and factors that lead to large emission
events.'' See 86 FR 63177 (November 15, 2021). In that proposal, the
EPA solicited comment on a potential program for large emission events
that would take advantage of data from the use of advanced technologies
that could identify super-emitter emissions events; under the program,
if emissions were detected above a defined threshold ``by a community,
a Federal or state agency, or any other third party, the owner or
operator would be required to investigate the event, do a root cause
analysis, and take appropriate action to mitigate the emissions, and
maintain records and report on such events.'' See 86 FR 63177 (November
15, 2021).
2. Rationale for and Summary of Proposed Program
The EPA received numerous comments from industry, non-industry
groups, states, tribes, and local communities articulating a range of
views on the concept described in the November 2021 proposal. These
comments provided valuable information and input on, among other
issues, the potential benefits of the program and the importance of
comprehensively addressing large emission events; implementation
challenges and concerns that would arise in establishing a system by
which researchers or other third parties could identify these events
and notify owners and operators, including concerns related to ensuring
the accuracy of such notifications and providing for safe and lawful
monitoring of sources; and the EPA's legal authority to promulgate such
a program under CAA section 111.
The EPA has carefully considered these comments, in conjunction
with various peer-reviewed studies, in designing this proposal for a
super-emitter response program. As described below, the principal
objective of this proposed program is to provide a comprehensive and
effective remedy for large emission events that disproportionately
contribute to methane emissions from the Crude Oil and Natural Gas
source category and can be accompanied by health-harming pollution that
affects nearby communities. However, as comments provided by a wide
range of stakeholders emphasized, it is also imperative that any such
program ensure the safety of entities engaged in monitoring as well as
of owners and operators and their employees; utilize accurate,
reliable, and rigorous methods for identifying large emission events;
and be streamlined and efficient to administer, both for owners and
operators of regulated sources as well as for the EPA and the states.
The proposed program contains key features and safeguards that were
designed with these principles in mind.
As noted above, the EPA assesses this *COM007*program is important
both because of the significant harm associated with super-emitter
emissions events and the well-documented challenges in identifying
these events. The most widely known sources of unintentional releases
resulting in super-emitter emissions events are from controlled tank
batteries, flares, natural gas-driven pneumatic controllers, and
fugitive emissions components. The standards and requirements included
in the November 2021 proposed rule and this supplemental proposal are
expected to identify and eliminate many super-emitters when implemented
as required. However, a cost-effective inspection program requiring
periodic fugitive emissions surveys cannot immediately detect every
instance of a super-emitter emissions event or quickly identify when
equipment malfunctions occur and therefore may not capture some
intermittent or episodic super-emitter emissions events. Further, it is
not cost-effective to impose additional inspection costs on every
source in hopes of detecting the small percentage of sources that
become super-emitters. The proposed super-emitter response program
would provide a cost-effective backstop to the rest of the regulatory
program by directing operator attention to problems urgently requiring
a remedy and providing useful feedback about the effectiveness of the
other regulatory requirements.
The EPA faced a similar situation when establishing standards for
petroleum refineries, where cost-effective controls and inspections of
equipment and operations would not have addressed potentially
significant levels of emissions that could occur between regular
inspections.\104\ In that instance, the EPA required additional
monitoring and corrective action to address such high emissions;
specifically, the EPA required fenceline monitoring to ``identify a
significant increase in emissions in a timely manner (e.g., a large
equipment leak or a significant tear in a storage vessel seal), which
would allow corrective action measures to occur more rapidly than it
would if a source relied solely on the traditional infrequent
monitoring and inspection methods.'' 79 FR at 36920.\105\ The EPA is
taking a similar approach in this supplemental proposal to address
super-emitter emissions events in a timely manner. This program
[[Page 74749]]
is likewise motivated by the same types of considerations that led the
EPA to establish a hotline for reporting oil spills and other
environmental releases (e.g., https://www.epa.gov/emergency-response/national-response-center). However, unlike most oil spills, large
releases of methane are not visible to the human eye; identifying them
requires people with specialized equipment and expertise.
---------------------------------------------------------------------------
\104\ Proposed Rule: Petroleum Refinery Sector Risk and
Technology Review and New Source Performance Standards, 79 FR 36880,
36920 (June 30, 2014).
\105\ This fenceline monitoring requirement is codified at 40
CFR 63.658 of the National Emission Standards for Hazardous Air
Pollutants from Petroleum Refineries, 40 CFR part 63, subpart CC.
---------------------------------------------------------------------------
The following sections first describe the details of the proposed
super-emitter response program, including the definition of a super-
emitter emissions event under the program, the requirements for any
party that seeks to report a super-emitter emissions event under the
program; and the requirements for owners and operators responding to
such report. It then describes the statutory structure for the program
under CAA section 111.
a. Super-Emitter Response Program Design
Threshold for a super-emitter emissions event. To clearly define
what emissions events would be subject to the requirements of this
program, the EPA is proposing to define a super-emitter emissions event
as any emissions detected using remote detection methods with a
quantified emission rate of 100 kg/hr of methane or greater. While the
term ``super-emitter'' has been widely used to describe large emissions
events in literature and various other discussions, no specific mass-
based or production-based rates have been formally or consistently
applied to the term. The EPA is proposing to apply a definition, for
purposes of this response program, that focuses on very large emissions
events at an individual well site, centralized production facility,
compressor station, or natural gas processing plant which warrant
immediate investigation.
This threshold definition of 100 kg/hr of methane takes into
account several factors. First, this proposed super-emitter response
program is intended to provide a mechanism to utilize high quality
remote sensing detection of only the largest, most harmful emissions
events, and not address all the standards and requirements of NSPS
OOOOb and EG OOOOc that are applicable to individual affected
facilities and associated controls. The goal of this program is to
ensure that if, notwithstanding the other requirements in this
proposal, a very large emissions event occurs and is detected by a
regulatory authority or qualified third parties using particular
technologies, that super-emitting event is quickly addressed.
Therefore, the threshold definition of a super-emitter emissions event
needs to be sufficiently high that it does not duplicate other actions
(e.g., leak detection and repair) facilities are undertaking to comply
with the applicable standards in the rule. Second, where compliance is
achieved with the applicable standards, the EPA does not expect
unintentional releases at these very high levels to occur in normal
operations. Thus, the occurrence of an unintentional release at this
emissions rate should be unusual and would clearly warrant immediate
investigation and mitigation. Defining a super-emitter event to
encompass these unusually large events is therefore consistent with the
EPA's objective of establishing a backstop to the other requirements
proposed in this rule. Third, by setting such a high threshold to
capture the largest and most concerning emissions events, the program
would be more feasible to implement and would properly focus resources
on the most significant and potentially harmful sources of emissions.
Such high rates of emissions also mean that it is cost effective to
quickly address these super-emitters, which release more methane in a
single week than the total methane cost-effectively prevented over the
course of an entire year at sources covered by the fugitive emissions
program. Fourth, as discussed immediately below, this threshold allows
the use of remote sensing technologies that are already in use by the
EPA, states, and third parties, which could allow the program to be
readily implemented upon finalizing NSPS OOOOb and the subsequent state
plans required by EG OOOOc.
Technologies that may be used to detect a super-emitter emissions
event. Various technologies are available for remote methane detection
that would provide a quantified mass emissions rate, including several
that would meet the performance criteria proposed for the alternative
periodic screening or continuous monitoring for fugitive emissions as
described in sections IV.B.1 and IV.B.2 of this preamble. Some
commenters stated that thresholds should be defined that could allow
the use of a range of technologies, without limiting to one specific
class of technologies.\106\ Among these, as discussed in the November
2021 proposal, the EPA described its understanding that ``some
satellite systems are generally capable of identifying emissions above
100 kg/hr with a spatial resolution which could allow identification of
emission events from an individual site.'' See 86 FR 63177 (November
15, 2021). Several commenters agreed that the use of satellites for
detecting super-emitters was appropriate, while noting that this
technology is continuing to advance.\107\ Further, several commenters
raised concerns regarding potential safety or trespassing on sites with
a program using more ground based or close-range detection
methods.\108\
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\106\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0605, EPA-HQ-
OAR-2021-0317-0769, EPA-HQ-OAR-2021-0317-0811, and EPA-HQ-OAR-2021-
0317-0844.
\107\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0738, EPA-HQ-
OAR-2021-0317-0753, EPA-HQ-OAR-2021-0317-0769, and EPA-HQ-OAR-2021-
0317-1391.
\108\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0727, EPA-HQ-
OAR-2021-0317-0730, EPA-HQ-OAR-2021-0317-0749, EPA-HQ-OAR-2021-0317-
0750, EPA-HQ-OAR-2021-0317-0763, EPA-HQ-OAR-2021-0317-0797, EPA-HQ-
OAR-2021-0317-0810, EPA-HQ-OAR-2021-0317-0814, EPA-HQ-OAR-2021-0317-
0817, EPA-HQ-OAR-2021-0317-0924, and EPA-HQ-OAR-2021-0317-0955.
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The EPA agrees with the commenters that some flexibility is
appropriate in the type of technology that could be utilized for the
detection of super-emitters, provided that the technology can be safely
deployed and will reliably identify super-emitter emissions events as
defined in this proposal. Considering concerns for the safety of
individuals engaged in third-party monitoring and of facility operator
personnel, the purposes of this program as described above, and
feedback from commenters on the performance and characteristics of
various monitoring technologies, the EPA assesses that allowing only
remote-sensing technologies is appropriate. Therefore, we are proposing
to allow the use of remote-sensing aircraft, mobile monitoring
platforms, or satellites to identify super-emitter emissions events.
The EPA is soliciting comment on this list of technology types that
could be applied for the identification of super-emitter emissions
events and the threshold of 100 kg/hr of methane.
Qualifications and requirements for notification of super-emitter
emissions events. Next, the EPA is proposing specific requirements
related to the notification of a super-emitter emissions event by
regulatory authorities and qualified third-party notifiers. Several
commenters emphasized the importance of assuring the quality and
reliability of the data and suggested that the EPA should have a role
in verifying the information to provide that assurance.\109\ In order
to address concerns about the expertise of the third party identifying
the super-emitter event, the EPA is proposing that any
[[Page 74750]]
third party interested in identifying and notifying owners and
operators of super-emitter emissions events must be pre-approved by the
Agency for the notification to be valid. This approval process would
follow submission of a request for approval as a qualified third-party
notifier to the EPA that demonstrates the potential notifier's
technical expertise in the specific technologies and detection
methodologies proposed for the identification of super-emitter
emissions events (i.e., remote-sensing aircraft, mobile monitoring
platforms, or satellite). This demonstration would include technical
expertise in the use of the detection technology and interpretation, or
analysis, of the data collected by the technology. The EPA would
maintain a public list of approved qualified third-party notifiers so
owners and operators can verify approval before being required to act
on a notification. These approved notifiers could be any third party,
including but not limited to technology vendors, industry, researchers,
non-profit organizations, or other parties demonstrating technical
expertise as described. The EPA is soliciting comment on this approval
criteria, including whether additional criteria would be appropriate.
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\109\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0738, EPA-HQ-
OAR-2021-0317-0938, and EPA-HQ-OAR-2021-0317-0844.
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Once approved, a qualified notifier would be required to submit
specific information in the notification. Providing actionable data of
known quality to the owner or operator is essential to ensure resources
are focused on swiftly eliminating the super-emitter emissions event.
Therefore, the EPA is proposing that each notification must contain
specific information to help owners and operators verify that the
emissions are correctly linked to their site and aid in a focused
investigation to swiftly identify the source of emissions. Specific
information that would be required in each notification includes: (1)
The location of emissions in latitude and longitude coordinates, (2)
description of the detection technology and sampling protocols used to
identify the emissions, (3) documentation depicting the emissions and
the site (e.g., aerial imaging with emissions plume depicted), (4)
quantified emissions rate, (5) date(s) and time(s) of detection and
confirmation after data analysis that a super-emitter emissions event
was present, and (6) a signed certification that the notifier is an
EPA-approved entity for providing the notification, and the information
was collected and interpreted as described in the notification. The EPA
believes this level of specificity is necessary to provide owners and
operators with credible information, and address the concerns raised by
commenters that owners and operators could experience undue burden
investigating emissions from monitoring data that are not collected in
a rigorous manner. We are soliciting comment on the specific required
elements of the notification, including whether additional requirements
should be added to aid in verifying the credibility of this
information.
The EPA further proposes that the entity making the report shall
provide a complete copy to the EPA and to any delegated state authority
(including states implementing a state plan) at an address those
agencies shall specify. The EPA would then promptly make such reports
available to the public online. Third parties may also make such
reports available to the public on other public websites. The EPA would
generally not verify or authenticate the information in third party
reports prior to posting.
The EPA is seeking comment on whether it should establish a
procedure for owners and operators to suggest that EPA reconsider the
approval granted to a third-party notifier. One type of procedure the
EPA has considered would be based on information provided by the owner
or operator that demonstrates they had received more than three notices
at the same site and from the same third party for super-emitter
emissions events which the owner or operator demonstrates, after
opportunity for response by the third party, that the notifications
contain meaningful, demonstrable errors, including, for example, that
the third party did not use the appropriate methane detection
technology, or that the emissions event did not exceed the threshold.
Where such demonstrable error is identified, the owner and operator
would not be obligated to conduct the root-cause analysis and
corrective action discussed later in this section and could, instead,
submit a report indicating the error. The EPA would not allow use of
this type of mechanism to dispute the accuracy of technologies that
have been approved by the EPA. Given the intermittency of super-emitter
emissions events, the failure of the operator to find the source of the
super-emitter emissions event upon subsequent inspection would not be
proof, by itself, of demonstrable error on the part of the third-party
notifier. The EPA, in its discretion, may remove that third party from
the pre-approved list of third-party notifiers upon demonstration by
the owner or operator and/or a finding by the EPA that more than three
notifications to that same owner or operator were made in error.
The design of the super-emitter response program ensures that the
EPA will make all of the critical policy decisions and fully oversee
the program. The proposed framework for the super-emitter response
program further includes a robust series of safeguards to ensure that
these notifications represent validly collected data and evidence of a
super-emitter emissions event. First, the qualified third party
permitted to submit notifications must be certified by the EPA as
having appropriate experience and expertise. Second, the qualified
third party may only use certain remote detection technology approved
by the EPA for use in the super-emitter response program. Third, the
EPA would establish the threshold defining what emissions events
detected by the qualified third parties would trigger any obligation on
the part of the owner and operator under the program. Fourth, the EPA
has prescribed the specific factual information that must be included
in any appropriate notification provided to an owner or operator. And
fifth, the EPA has proposed a mechanism for owners and operators to
seek a revocation of a notifier's certification from the EPA should
they establish that more than one notification contained demonstrable
errors. Accordingly, under this framework the qualified third party
would essentially only be permitted to engage in certain fact-finding
activities and issue fact-based notifications within the limited
confines that the EPA has authorized. Such fact-based notifications
originating from third parties would not represent the initiation of an
enforcement action by the EPA or a delegated authority.
In addition, and as discussed in more detail later in this section,
owners and operators would have the opportunity to rebut any
information in a notification provided by the qualified third parties
in their written report to the EPA, by explaining, where appropriate,
that (a) there was a demonstrable error in the third party
notification; (b) the emissions event did not occur at a regulated
facility; or (c) the emissions event was not the result of malfunctions
or abnormal operation that could be mitigated. And, as just discussed,
the EPA proposes to retain the authority to revoke a third-party
certification upon evidence that the notifier has made repeated,
demonstrable errors in notifications provided to owners and operators.
Thus, the EPA believes that the proposed program appropriately
limits third party notifiers' discretion and retains oversight by the
EPA over all key
[[Page 74751]]
decision-making elements of the program. In light of these
considerations, the EPA also believes that a greater role for the
Agency in reviewing third-party notifications would be an unnecessary
task and duplicative of the predicate approval processes and subsequent
revocation procedure. Indeed, were the EPA to review third-party
notifications, such review could potentially be limited to ensuring
that the third party is properly EPA-certified, has used an EPA-
approved remote monitoring technology, and has found emissions above
the super emitter threshold--all of which are elements that the
proposed program structure adequately ensures. The EPA believes other
facts necessary to rebut the information in a notification regarding a
particular emissions event are likely to only be known by the owner and
operator and are best presented in their written report to the EPA.
Moreover, given the urgency with which the EPA believes such large
emissions events should be addressed, any additional role for the EPA
in the notification process would unnecessarily delay mitigation of
ongoing harms. The EPA solicits comments on these conclusions, and
whether there would be a meaningful benefit to a greater role for the
EPA in reviewing and/or approving third-party notifications before the
obligation of the owner or operator to respond is triggered. And if so,
the EPA further solicits comment on what kind of role would be
appropriate without meaningfully delaying the mitigation of the large
emissions events this program is intended to target.
Addressing a super-emitter emissions event. In the November 2021
proposal, the EPA solicited comment on what specific actions an owner
or operator would be required to take when they are notified of the
detection of a super-emitter emissions event. Examples of those
specific actions were provided for comment, including verifying the
location of the emissions, conducting ground investigations to identify
the specific emissions source, conducting a root cause analysis,
performing corrective action within a specific timeframe to mitigate
emissions, and preventing ongoing and future chronic or intermittent
events from that source. See 86 FR 63177 (November 15, 2021). One
commenter stated that not all sources of super-emitter emissions events
would require a root cause analysis with corrective actions because the
emissions may not be the result of malfunctions or abnormal operation
(e.g., an emergency blowdown of equipment).\110\ Other commenters
stated that a root cause analysis and immediate corrective actions
should be required for any event identified through this program.\111\
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\110\ See Document ID No. EPA-HQ-OAR-2021-0317-1391.
\111\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0586, EPA-HQ-
OAR-2021-0317-0605, and EPA-HQ-OAR-2021-0317-0832.
---------------------------------------------------------------------------
The EPA agrees with commenters that swift action must be taken when
an owner or operator is notified about the detection of a super-emitter
emissions event to correct any malfunction or abnormal operation that
is identified as the cause of the event. First, the owner or operator
should confirm that the reported emissions event is traceable to a
source located on the notified owner or operator's site and investigate
to confirm if a super-emitter emissions event is still ongoing.
Further, the EPA agrees that a root cause analysis is necessary to
identify the causes of the super-emitter emissions event. Therefore, we
are proposing to require owners and operators to initiate a root cause
analysis to determine the cause of the super-emitter emissions event
and to take corrective actions to mitigate the emissions. Examples of a
root cause analysis and corrective action could range from a survey
using OGI or other technologies combined with repairs of any leaks
identified, to visual inspections of thief hatches and closing any
found open or unlatched. As explained in more detail later in this
section, such corrective actions are tasks that owners and operators
already would undertake to maintain normal operations. One commenter
\112\ noted that the investigation may find the emissions are
attributed to something other than a malfunction or abnormal emission;
in those cases, the responsive action may only need to include specific
documentation of the emissions source, such as maintenance activities,
which should be described in the report.
---------------------------------------------------------------------------
\112\ See Document ID No. EPA-HQ-OAR-2021-0317-1391.
---------------------------------------------------------------------------
The EPA is proposing to require initiation of the root cause
analysis and corrective actions within five calendar days of an owner
or operator receiving the notification of the super-emitter emissions
event, and completion of corrective actions within 10 days of the
notification. Because super-emitter emissions events are such large
mass emissions rates (100 kg/hr or greater), it is imperative that
mitigation is achieved in a timely manner. One commenter \113\
suggested a program where the investigation would start within 14 days
of notification, with repairs completed within 30 days of discovery of
the event. However, the EPA believes that identification of the
emissions source and remedial action in a much shorter timeframe is
both warranted and necessary.
---------------------------------------------------------------------------
\113\ See Document ID No. EPA-HQ-OAR-2021-0317-0832.
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Notwithstanding the necessary urgency of mitigating super-emitter
emissions events, the EPA does recognize that in some cases,
significant efforts may be required to fully complete required
mitigation. It is possible that some corrective actions would take
longer than the proposed 10 days to complete. Therefore, the EPA is
proposing a requirement for owners and operators to develop and submit
a corrective action plan that describes the corrective action(s)
completed to date, additional measures that they propose to employ to
reduce or eliminate the emissions, and a schedule for completion of
those measures. This corrective action plan would be due within 30 days
of receipt of the notification of the super-emitter emissions event.
This timeframe allows for an additional 20 days beyond the repair
deadline to draft the corrective action plan and submit it to the
Agency or delegated state authority.
Finally, the EPA is proposing to require the submission of a
written report within 15 days of completing the root cause and
corrective action to the Agency and delegated state authority. In the
case of a designated facility covered by a state plan, the EPA solicits
comment on whether such written report should be sent to the state in
addition to the EPA. The EPA would promptly post online all reports
received from the owner-operator in response to a notice of super-
emitter event. This written report would include information such as
the data included in the notification, the source of the emissions,
corrective actions taken to mitigate the emissions, and the compliance
status of the affected facilities. To the extent a deviation or
potential violation is identified as the root cause of the emissions,
the owner or operator would report that information. If the operator
finds that emissions above the super-emitter threshold are not
occurring, and there is no evidence that they may have occurred as
reported, then the method for making that determination and the
evidence in support should be included in the required report to the
EPA. To the extent an owner or operator determines that the
notification contains a demonstrable error (e.g., that the notifier was
not a qualified third party, that the third party did not use the
appropriate methane detection technology, or that
[[Page 74752]]
the reported emissions event did not exceed the threshold), the report
would need only include a description of the error and an explanation
as to why, under these circumstances, a root cause analysis was not
conducted. The EPA solicits comment on what other elements should be
included in the owner-operator reports to the state and the EPA.
The EPA solicits comment on these proposed deadlines for initiating
the analysis and completion of corrective actions. For comments
requesting shorter or longer timeframes, we are requesting specific
examples that would support any changes to this proposal.
b. Statutory Basis of Super-Emitter Program
There are several ways in which the proposed super-emitter response
program described above fits within the EPA's authority under section
111 of the CAA, and two legal frameworks are outlined below.
First, the EPA could treat a super-emitter emissions event as a
separate and distinct source of emissions. Under this regulatory
framework, sources of super-emitter emissions events from unintended
venting would be an affected facility/designated facility, and the
super-emitter response program would serve as the standard reflecting
the BSER for these facilities.
Specifically, the EPA is proposing a new ``super-emitter'' affected
facility under NSPS OOOOb (and designated facility under EG OOOOc),
which the EPA would define as any equipment or control devices, or
parts thereof, at a well site, centralized production facility,
compressor station, or natural gas processing plant, that causes a
super-emitter emissions event (i.e., any emissions detected using
remote detection methods with a quantified emission rate of 100 kg/hr
of methane or greater). While the other requirements proposed as part
of this rulemaking are intended to reduce or eliminate unintentional
releases, the super-emitter response program is intended as a backstop
to those provisions, to identify any super-emitter emissions events not
prevented as a result of other requirements of the proposed rule.
As discussed above, the EPA believes that super-emitter emissions
events from unintentional releases tend to occur as a result of
equipment malfunctions and/or poor operations; therefore, the BSER for
super-emitter emissions events would be to correct the malfunction or
operational issues and resume normal operations consistent with the
standards or requirements applicable to the source(s) of the super-
emitter emissions event in this proposed rule. The November 2021
proposal and this supplemental proposal contain standards and
requirements that, if implemented correctly, would prevent or mitigate
these super-emitter emissions events. For example, if a root cause
analysis identifies a control device as a source of a super-emitter
emissions event, then complying with the requirements for that control
device in this proposed rule would bring such device back to normal
operation. If the source of a super-emitter emissions event is a
leaking fugitive emissions component or an open thief hatch, repairing
the component or ensuring that the thief hatch is closed in accordance
with the fugitive emissions standards in this proposal would resume
these components to normal operation. The super-emitter response
program would require that, where approved, qualified third parties or
state or Federal governments provide actionable data of known quality
about a super-emitter event to owners and operators of a super-emitter
affected facility, and owners and operators would conduct a root-cause
analysis to identify the sources of the super-emitter emissions and
take corrective actions to mitigate the problems in order to resume
normal operation. Because specific corrective actions required to
resume normal operations would depend on the equipment causing the
super-emitter emissions event, and because normal operations could
differ from site to site, the proposed program would allow owners and
operators to determine the appropriate corrective actions so long as
the event is mitigated.
The EPA proposes to determine that these requirements are justified
as BSER for this proposed super-emitter affected/designated facility
for several reasons. First, we expect that, as part of normal
operations, owners and operators should already be correcting equipment
malfunctions and/or poor operations as such issues arise; therefore,
costs associated with maintaining normal operations should already be
accounted for in their operational costs. As mentioned above, the most
widely known sources of unintended super-emitter emissions events are
from equipment or control devices that would be subject to emission
limitations (e.g., 95 percent reduction) or associated compliance
assurance requirements in the proposed NSPS OOOOb/EG OOOOc. For these
sources, where a super-emitter emissions event suggests a violation of
one or more of these standards or requirements, owners and operators
would already be required to investigate the source of the super-
emitter emissions event to ensure that it is complying with all
applicable standards and requirements. The proposed super-emitter
response program would simply require the owner and operator to take
these same steps upon receiving notice of a super-emitter emissions
event, provided by a regulatory authority or an EPA approved qualified
third party, as determined under the proposed program. As explained in
more detail above, the proposed super-emitter response program would
include a certification process and other criteria to assure the
quality and reliability of third-party data regarding a super-emitter
emissions event. Having established the reliability and quality of the
third-party data regarding a super-emitter emissions event, it is
reasonable to require prompt investigation and remediation of the
emissions. Super-emitter emissions events could also be caused by
fugitive emissions components that, if persistent, would be detected
and repaired during the next fugitive monitoring survey; the super-
emitter program would simply make the same repair earlier. There would
be no associated monitoring cost for owners and operators, as
monitoring under this program would be conducted by EPA-approved
qualified third parties. Accordingly, the EPA anticipates that there
should be no additional cost associated with this work practice
standard for the super-emitter emissions event affected facility. The
EPA seeks comment on this issue.
To the extent there are additional costs associated with the
investigation or mitigation of these events, the EPA anticipates that
the costs would be minor in relation to the benefits of stopping such a
huge emissions event, making them obviously cost-effective, as
explained below. The EPA proposes that it is reasonable to conclude
that these actions would be cost effective in light of the large mass
emissions rate (100 kg/hr of methane or greater) that would be reduced
and the value of the high volume and value of gas saved by mitigation
of the event. The EPA finds in the November 2021 proposal and this
supplemental proposal that some proposed standards are cost effective
when they result in an expected reduction of about 10 tons of methane
at a facility over the course of a year. The super-emitters that can be
identified through the super-emitter response program produce that
amount of methane in five days or less and the
[[Page 74753]]
remedies are the same or similar.\114\ For example, if the source of a
super-emitter emissions event is an open thief hatch on a controlled
tank battery, the first corrective action would be to close the thief
hatch, which would incur negligible costs. In other words, it is highly
unlikely that in general these actions would exceed the $2,185/ton of
methane reduced, which is the highest value we have determined to be
cost effective for reducing methane in rulemakings addressing methane
under section 111 of the CAA. The cost effectiveness for responses to
super-emitter emissions events will usually be substantially below this
threshold, given that, by definition, super-emitter emissions events
emit at least one ton of methane every nine hours, and over 18 tons in
a week. For the reasons stated above, the EPA anticipates that
requiring immediate corrective actions to resume normal operations to
eliminate the super-emitter emission event could be achieved at a
reasonable cost for this proposed affected/designated facility. The EPA
seeks comment on this conclusion.
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\114\ See Table 11, Summary of Emission Reductions and Cost-
Effectiveness: Well Sites with Major Production or Processing
Equipment, Quarterly Monitoring.
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The EPA finds that the above regulatory framework of treating
super-emitter emissions events from unintended venting as an affected
facility that would be subject to the super-emitter response program is
a clear, simple, and straight forward approach for addressing such
large emission events.
Second, the super-emitter response program can be justified as part
of the standards and requirements that apply to individual affected/
designated facilities under this rule, a number of which are known to
be frequent causes of super-emitter emission events which, as explained
earlier, may not necessarily be identified and addressed through more
frequent monitoring that we have determined is not cost-effective. As
mentioned above, the most widely known sources of unintentional
releases resulting in super-emitter emissions events are from
controlled tank batteries, flares, natural gas-driven pneumatic
controllers, and fugitive emissions, all of which would be either
affected facilities or designated facilities under the NSPS OOOOb and
EG OOOOc, respectively, or are control devices used on affected
facilities/designated facilities for which the proposed rules include
specific requirements. The EPA proposes to incorporate the super-
emitter program into these standards by considering the super-emitter
program as: (1) An additional compliance assurance measure, in the case
of sources that are subject to numerical standards of performance and
associated control device requirements, and (2) an additional work
practice standard, in the case of sources for which the EPA is
proposing work practice standards under this rule. However, despite the
proposed incorporation, the super-emitter response program is
nevertheless severable from the standards of performance and work
practice standards that are being separately established for each of
the sources addressed in this rule. Each of these other proposed
standards in this rule reflects the use of a specific emission
reduction or detection technology or measure that the EPA has
determined to be BSER for a given emission source after evaluating its
performance, cost and other factors associated with its use, as
required by CAA section 111(a) (under the definition of a ``standard of
performance''). Because whether such technology or measure qualifies as
the BSER under CAA section 111(a) does not depend on the presence of
the super-emitter response program, the resulting standards of
performance and work practice standards proposed in this rulemaking
would continue to reflect the use of that technology or measure, and in
turn the BSER, even without the super-emitter response program.
Compliance assurance. For super-emitter emissions events from
affected facilities/designated facilities subject to numerical
standards, the super-emitter response program would serve as an added
compliance assurance mechanism, aimed at ensuring compliance with the
numerical emissions standards and associated control device or other
compliance assurance requirements. Where one of these facilities is
determined to be the cause of a super-emitter emissions event, it is
reasonable to assume that the emissions source is out of compliance and
to require corrective action to bring the facility back into compliance
with the applicable standard or requirement.
There are two known sources of unintended venting that could result
in super-emitter emissions events that would be subject to numerical
performance standards as affected facilities or designated facilities:
tank batteries with potential emissions above six tpy of VOC or 20 tpy
of methane and natural gas-driven pneumatic controllers. Specifically,
for storage vessel affected facilities/designated facilities, the EPA
is proposing a numerical standard of performance that would require
reducing VOC and methane emissions by 95 percent. Where a control
device is used to meet this standard, the EPA is proposing specific
compliance assurance measures, such as a requirement that thief hatches
and other openings remain closed (``closed cover requirements''). As
discussed in section IV.I of this preamble, the EPA is proposing to
require quarterly OGI inspections of thief hatches and other openings
to ensure the closed cover requirement, and in turn the 95 percent
emission reduction standard, are met. If these standards and
requirements are rigorously followed, the EPA anticipates that they
should prevent super-emitter emissions events from controlled storage
tanks. However, these thief hatches are a commonly known source of
super-emitter emissions events when they are not closed and properly
latched. The proposed super-emitter response program would therefore
serve as a backstop--an additional compliance assurance measure for the
storage vessels standards--by requiring corrective action where it is
determined that a super-emitter emissions event was caused (in whole or
in part) by noncompliant storage vessels. Similarly, with respect to
natural gas-driven pneumatic controllers, for which the EPA is
proposing a zero-emissions standard, the EPA is proposing to require
quarterly OGI inspections of self-contained natural gas-driven
pneumatic controllers to ensure there are no identifiable emissions
from the controller as a compliance assurance measure. The super-
emitter response program would serve as an additional compliance
assurance measure by requiring immediate corrective action where it is
determined that a super-emitter emissions event was caused (in whole or
in part) by a natural gas-driven pneumatic controller affected
facility.
As mentioned above, flares are also a widely known cause of super-
emitter emissions events. To our knowledge, all flares located at well
sites, centralized production facilities, compressor stations, or
natural gas processing plants are (or would be) used to meet a
performance standard in NSPS OOOOb or EG OOOOc. As such, they would be
required to meet the design and operation requirements for flares in
this proposal, such as operation and monitoring for a continuous pilot.
Flares designed and operated according to the proposed requirements for
control devices should not cause a super-emitter emissions event. The
super-
[[Page 74754]]
emitter response program would help assure compliance with these flare
requirements (and in turn the relevant performance standards) by
requiring owners and operators to take immediate corrective actions to
bring that flare into compliance where it is determined that a super-
emitter emissions event is caused by a flare. For these sources, where
a super-emitter emissions event suggests a violation of one or more of
these standards or requirements, owners and operators would already be
required to investigate the source of the super-emitter emissions event
to ensure that it is complying with all applicable standards and
requirements. Since the proposed super-emitter response program would
require these same measures, we do not anticipate additional costs
associated with the program.
To the extent there are additional costs associated with the
investigation or mitigation of these events, the EPA expects that the
costs would be minor in relation to the benefits of stopping such a
huge emissions event, making them obviously cost-effective. As
explained previously in this section, it is reasonable to conclude that
these actions would be cost effective in light of the large mass
emissions rate (100 kg/hr of methane or greater) that would be reduced
and the value of the high volume of gas saved by mitigation of the
event.
Work practice standards for detecting and repairing fugitive
emissions. As discussed above, super-emitter emissions events may also
occur from fugitive emissions components, which are not subject to
numerical standards, but rather to a work practice standard that
requires periodic monitoring (using OGI, AVO, or an advanced
technology) and repair of emissions that are identified from fugitive
emissions components. A super-emitter emissions event could occur
between the required periodic monitoring and thus not be detected and
repaired until the next periodic monitoring event. In addition, if
required periodic monitoring is missed, or is not performed well,
super-emitter emissions events could be occurring that the periodic
monitoring program fails to identify. For affected facilities and
designated facilities (i.e., collection of fugitive emissions
components) subject to the periodic monitoring and repair requirements,
the super-emitter response program would serve as an additional work
practice standard that would require corrective action whenever the
owner or operator is notified of a super-emitter emissions event by an
EPA, a state, or an approved third party under the super-emitter
response program, and it is determined that fugitive emissions
components are (in whole or in part) the source of the event.
While, as discussed in section IV.A.1, the EPA does not believe it
is cost-effective to require operators to conduct periodic OGI
monitoring more frequently than the intervals set out in Section
IV.A.1, if a super-emitter emissions event is detected by a regulatory
authority or approved qualified third party in between monitoring
requirements, the EPA proposes that the BSER include responding to that
event and addressing the root cause of the super emission.
The more targeted super-emitter response program would thus be a
more effective solution for addressing sporadic, large emission events
that may occur outside the periodic OGI monitoring. The conclusion that
the super-emitter response program is appropriate for addressing these
particularly large emissions events does not undermine the EPA's
determination about the frequency of periodic monitoring otherwise
required under the fugitive emissions work practice standard. While
super-emitter emissions events are important to address as a
significant source of potential emission reductions, these events do
not occur regularly across all well sites and are not predictable.
Accordingly, while the periodic monitoring is appropriate to address
more routine leak detection and repair, and to help prevent the
occurrence of super-emitter emissions events, the super-emitter
response program will help ensure that the unpredictable but
potentially significant super-emitter emissions events are
expeditiously addressed.
Further, the corrective action to mitigate a super-emitter
emissions event from this source has the potential to result in
significant emissions reductions earlier than would have been achieved
by the periodic monitoring requirements. The EPA therefore believes
that the super-emitter response program is a reasonable addition as
part of the BSER for fugitive components because the program would only
target particularly large emission events (measuring over 100 kg/hr)
from these affected or designated facilities and would not require any
action for smaller emissions events that would be addressed by the
periodic monitoring.
We have considered the costs of adding the super-emitter response
program as an additional work practice standard to the periodic
monitoring and repair requirements for addressing fugitive emissions
and concluded that the cost is reasonable. First, owners and operators
do not bear the cost of monitoring and detecting super-emitter
emissions events, which would be conducted by EPA-approved qualified
third parties. Instead, as discussed in more detail below, the first
step of the program would be for owners and operators to investigate
and identify the source(s) of a super-emitter emissions event upon
receiving reliable information. Since owners and operators would
already have to perform this task for purposes of the compliance
assurance measure for other affected facilities and associated control
devices under the super-emitter response program, described above,
there would be little additional cost in including this same root-cause
analysis as part of the fugitive emissions work practice standards.
Second, to the extent a root-cause analysis reveals that the super-
emitter emissions event is caused by a fugitive emissions component,
there may be no additional cost associated with their repair, since
these fugitive emissions might be detected and repaired during the next
scheduled periodic monitoring; the super-emitter response program would
simply require such repair to occur sooner. In other words, for super-
emitter emissions events identified as resulting from fugitive
emissions components between scheduled monitoring surveys, the proposed
super-emitter response program would provide an opportunity for repairs
sooner than the next scheduled survey, thus resulting in fewer
emissions overall from the event.
Moreover, even if there are costs associated with the investigation
and mitigation, the threshold for identifying a super-emitter emissions
event is so high that it ensures that the emissions reductions achieved
by the mitigation are cost-effective. In other words, it is reasonable
to conclude that these actions would be cost-effective in light of the
large mass rate of emissions (100 kg/hr of methane or greater) that
would be reduced, and the high volume of gas saved. It is highly
unlikely that these actions would exceed the $2,185/ton of methane
reduced, which is the highest value we have determined to be cost
effective for reducing methane from sources within this source
category.
In summary, the EPA finds the data demonstrate that the super-
emitter response program is cost-effective, even though the EPA
recognizes that the total emissions reductions that will result from
the program are difficult to quantify. By definition, a super-emitter
emissions event emits more than 100 kg of methane/hour, which means
that an on-going super-emitter emissions event that lasts an extended
period may emit
[[Page 74755]]
more than 2.5 tons of methane in a day, and potentially almost 80 tons
if it continued undetected for a month. Applying the same social cost
of methane values used to develop the estimates in Table 5 above, such
an event could generate over $100,000 in avoidable climate
damages.\115\ The proposed fugitive emissions monitoring and repair
requirements for facilities with major production and processing
equipment, discussed in section IV.A, are cost-effective when they are
projected to reduce 10.85 tpy of methane. A super-emitter emissions
event may emit almost twice that, or in some cases substantially more,
in a single week. In addition, the cost of most of the repairs that
would be necessary to respond to a super-emitter emissions event may be
achieved at very low additional cost because the need for repair would
be discovered at the next required inspection, indicating that most
repairs in response to super-emitter emissions events may be simply
moving the repairs earlier in time. Furthermore, halting super-emitter
emissions events recovers natural gas for sale that would otherwise be
emitted to the atmosphere, so it is possible that for many super-
emitter emissions events identified, the revenues from recovered
natural gas may offset a significant portion of the costs of repair
incurred by the owner or operator. For all these reasons, the EPA finds
the super-emitter response program cost-effective. Because the costs of
this program incurred by owners and operators, the length of time over
which these events occur, and the emissions reductions that may be
achieved have uncertainties associated with them, the EPA solicits
comments on the various factors related to the cost-effectiveness of
the super-emitter response program, including any information further
detailing the costs and emissions reductions of this program.
Specifically, the EPA solicits comments on any relevant data,
appropriate methodologies, or reliable estimates to help quantify the
costs, emissions reductions, benefits, and potential distributional
effects of this program (including, for example, benefits for
communities with EJ concerns). We also take comment on how to improve
the accuracy of our estimates of baseline emissions levels, emissions
reduction opportunities, and the frequency and intensity of super-
emitter events, and how to incorporate any recent, reliable estimates
of methane emissions.
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\115\ This damage estimate assumes a social cost of methane
estimate of at least $1,400 per metric ton of methane, which is less
than the interim estimate that EPA uses in the RIA for a 3% discount
rate for the first year that the proposed NSPS OOOOb is assumed to
go into effect (2023).
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c. Additional Solicitations for Comment
While the EPA is proposing a general framework for the super-
emitter response program, there are several additional aspects of the
program for which we are soliciting additional information and comment.
These solicitations are described in the following paragraphs.
First, the EPA is soliciting comment on the mechanism for
identifying the owners and operators to receive the super-emitter
emissions event notifications. Entities approved to make such
notifications need a way to identify to whom they should be sent and
how to assure they are received. The EPA specifically seeks comment on
what mechanisms exist to make such identifications now, the
reliability, accuracy, and timeliness of those mechanisms, and the
difficulty or cost of accessing those mechanisms.
The EPA is also soliciting comment on the amount of time allowed
for notifications following detection of a super-emitter emissions
event. Clearly, timely notification of the event is essential to
maximize the emission reduction potential from the event, but it is the
EPA's understanding that each technology or remote measurement method
experiences a lag between when a survey is conducted and when the data
has been analyzed to demonstrate emissions were present. The EPA is
soliciting comment on what deadline for notifications following
detection survey is most advantageous and feasible given current data
analysis requirements for remote measurement technologies and methods.
Further, time will be required to properly identify the relevant owner
or operator of the site. One factor is that ownership of sites can
change frequently, or specific contacts may move into other roles or
leave the company. Therefore, the EPA is soliciting comment on the
amount of additional time that should be factored into the notification
process to account for this identification step.
D. Pneumatic Controllers
Pneumatic controllers are devices used to regulate a variety of
physical parameters, or process variables, often using air or gas
pressure to control the operation of mechanical devices, such as
valves. The valves, in turn, control process conditions such as levels,
temperatures and pressures. When a pneumatic controller identifies the
need to alter a process condition, it will open or close a control
valve. In many situations across all segments of the Oil and Natural
Gas Industry, pneumatic controllers make use of the available high-
pressure natural gas to operate or control the valve. In these
``natural gas-driven'' pneumatic controllers, natural gas may be
released with every valve movement (intermittent) and/or continuously
from the valve control. Detailed information on pneumatic controllers,
including their functions, operations, and emissions, is provided in
the preamble for the November 2021 proposal (86 FR 63202-63203;
November 15, 2021).
1. NSPS OOOOb
a. November 2021 Proposal
In the November 2021 proposal, a pneumatic controller affected
facility was defined as each single natural gas-driven pneumatic
controller, whether the controller was a continuous bleed controller or
an intermittent vent controller. This affected facility definition
would have applied at sites in all segments of the oil and natural gas
source category. We proposed the requirement that all controllers
(continuous bleed and intermittent vent) have a VOC and methane
emission rate of zero. The proposed rule did not specify how this
emission rate of zero was to be achieved, but a variety of viable
options were discussed. These options included the use of pneumatic
controllers that are not driven by natural gas such as instrument air-
driven pneumatic controllers and electric controllers, as well as
natural gas-driven controllers that are designed so that there are no
emissions, such as self-contained pneumatic controllers. Because we
proposed to define an affected facility as each pneumatic controller
that is driven by natural gas and that emits to the atmosphere,
pneumatic controllers not driven by natural gas would not have been
affected facilities. Controllers that are driven by natural gas but
that do not emit to the atmosphere would not have been affected
facilities either, according to the November 2021 proposed definition.
The November 2021 proposed rule included an exemption from this
zero-emission standard for pneumatic controllers at sites in Alaska
that do not have access to electrical power. For these sites, the
proposed rule would have required the use of low-bleed, continuous
bleed controllers. It would also have required that intermittent vent
controllers not vent during idle periods and that periodic inspections
be performed on these controllers to ensure that such venting does not
occur.
[[Page 74756]]
b. Changes to Proposal and Rationale
The proposed NSPS OOOOb requirements in this supplemental proposal
differ from the November 2021 proposal in several ways, starting with
the affected facility definition. As noted above, the pneumatic
controller affected facility definition proposed in November 2021 was
each individual natural gas-driven pneumatic controller. In this
supplemental proposal, a pneumatic controller affected facility is
defined as the collection of all the natural gas-driven pneumatic
controllers at a site.
Another change from the November 2021 proposal is that two specific
types of natural gas-driven controllers that were proposed to be
excluded from the affected facility definition are now proposed to be
included. These are: (1) Controllers where the emissions are collected
and routed to a gas-gathering flow line or collection system to a sales
line, used as an onsite fuel source, or used for another useful purpose
that a purchased fuel or raw material would serve (i.e., generally
characterized as ``routing to a process''); and (2) self-contained
natural gas pneumatic controllers.
There is no change to the fundamental proposed standard for
pneumatic controllers, which is that all pneumatic controllers would be
required to have a methane and VOC emission rate of zero. The proposed
standard does include requirements for the two specific types of
natural gas-driven controllers identified above. These controllers do
not emit methane or VOC from routine operations. However, since they
are powered by natural gas, the potential for emissions exists if they
are not maintained and operated properly. For instance, a self-
contained controller could malfunction or develop leaks, or a CVS that
is routing the controller emissions to a process could develop leaks.
Therefore, the proposed rule includes requirements to avoid such
situations so that the controllers have zero direct emissions. Since
routing to a process includes the option of using the natural gas
captured for use as a fuel source, emissions would occur downstream at
the engine, generator, or process heater resulting from the combustion
of the natural gas from the controllers. However, these emissions are
replacing those that would have resulted from the combustion of fuel
gas, meaning that the net result is still zero direct emissions.
While the BSER conclusion did not change from the November 2021
analysis, the EPA did update the analysis based on information received
in the public comments, including an analysis of potential alternative
standards for small sites with few pneumatic controllers.
Details on the proposed pneumatic controller requirements in this
supplemental proposal are provided below in section IV.D.1.c. The
following sections provide the rationale for the changes discussed
above, a discussion of other related issues raised by commenters, and
the updated BSER analysis.
i. Affected Facility, Modification, and Reconstruction
As noted above, the pneumatic controller affected facility
definition changed from being based on a single continuous bleed or
intermittent vent controller in the November 2021 proposal to the
collection of natural gas-driven continuous bleed and intermittent vent
controllers at a site in this supplemental proposal.\116\ The EPA is
proposing this change based on the consistent recommendation of
numerous commenters, particularly commenters from the oil and natural
gas industry. Several comments on the November 2021 proposal noted the
disconnect between the pneumatic controller affected facility
definition (i.e., an individual controller) and the cost analysis,
which was based on the replacement of all pneumatic controllers with
zero-emitting devices at a site.\117\ One commenter pointed out the
complexities of tracking and managing the universe of pneumatic
controllers at a site when some are affected facilities and others are
not, and recommended that the EPA propose a simpler and more robust
system.\118\ Another commenter indicated that defining the affected
facility on a site-wide basis aligns with how emissions from pneumatic
controllers will likely be handled by owners and operators of oil and
natural gas facilities. This commenter opined that defining the
pneumatic controller affected facility on a single controller basis, as
opposed to as the collection of all controllers at a site, would be
unnecessarily burdensome.\119\ A separate commenter discusses the fact
that converting a single pneumatic controller to a zero-emitting device
typically requires a conversion of all controllers at the facility to
zero-emitting devices.\120\
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\116\ The EPA notes that there are other sources of emissions in
this supplemental proposed rule that the EPA proposes to regulate as
a collection of emissions sources, rather than as individual
emission units. Namely, the EPA proposes to define tank batteries as
the group of all storage vessels that are manifolded together for
liquid transfer and proposes to define fugitive emissions components
as the collection of fugitive emissions components at all well
sites.
\117\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0599, EPA-HQ-
OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-0831, and EPA-HQ-OAR-2021-
0317-0777.
\118\ See Document ID No. EPA-HQ-OAR-2021-0317-0742.
\119\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
\120\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808.
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We agree with the commenters that defining the pneumatic controller
affected facility as the collection of all controllers at a site is the
most practical approach. Significantly, most of the zero-emissions
measures for pneumatic controllers are site-wide solutions. For
instance, a compressed air system installed at a site would be used to
power all of the pneumatic controllers at the site, rather than a
separate system for each controller. Similarly, a solution based on
solar energy would likely utilize a single array of solar panels to
provide power to all the controllers at the site. In fact, as pointed
out by the commenters, the analysis for the November 2021 proposed rule
was conducted on a ``model plant'' site-wide basis. As noted above, the
comments that the EPA received on the pneumatic controller affected
facility definition in the November 2021 proposal all advocated for a
change in the definition from a single controller to the collection of
all onsite pneumatic controllers. However, the EPA did not specifically
solicit comment on the particular question of how to define the
affected facility in November. Now that the EPA is proposing in this
supplemental proposal to define the affected facility as the collection
of natural gas-driven continuous bleed and intermittent vent
controllers at a site, the EPA solicits comment on the proposed changed
definition.
Under the previous approach of treating each controller on an
individual basis, the installation or replacement of a pneumatic
controller would have resulted in that singular controller being a new
source and an affected facility subject to NSPS OOOOb. Under this
supplemental proposal approach to treat the collection of all
controllers at a site as the affected facility, clear descriptions of
modification and reconstruction are needed in order to indicate when an
existing collection of controllers would become subject to NSPS OOOOb.
In 40 CFR 60.14(a), a ``modification'' is defined as ``any physical or
operational change to an existing facility which results in an increase
in the emission rate to the atmosphere of any pollutant.'' To clarify
what constitutes a modification for the
[[Page 74757]]
collection of all controllers at a site, the supplemental proposed rule
specifies that if one or more pneumatic controllers is added to the
site, such addition constitutes a modification and the collection of
pneumatic controllers at the site becomes a pneumatic controller
affected facility. This is because the addition of a controller
represents a physical change to the site and would result in an
increase in emissions from the collection of controllers. Based on
information provided by industry commenters, the EPA believes that
owners and operators will implement zero-emissions controllers across a
site when a modification occurs because converting a single pneumatic
controller to a zero-emitting device typically requires converting all
controllers at the facility to zero-emitting devices. The EPA solicits
comment on the ways in which a modification to a pneumatic controller
affected facility would occur in light of the affected facility
definition proposed herein, which includes the collection of all
natural gas-driven continuous bleed and intermittent vent controllers
at a site.
In 40 CFR 60.15(b), ``reconstruction'' is defined as the
replacement of components of an existing facility ``to such an extent
that the fixed capital cost of the new components exceeds 50 percent of
the fixed capital cost that would be required to construct a comparable
entirely new facility,'' and ``it is technologically and economically
feasible to meet the applicable standards.'' The proposed pneumatic
controller affected facility definition for this supplemental proposal
is the collection of all natural gas driven controllers at a site;
therefore, the cost that would be required to construct a ``comparable
entirely new facility'' would be the cost of replacing all existing
controllers with new controllers. Because individual controllers are
likely to have comparable replacement costs, it is reasonable to assume
that there would be a one-to-one correlation between the percentage of
controllers being replaced at a site and the percentage of the fixed
capital cost that would be required to construct a comparable entirely
new facility. Accordingly, we are proposing to include a second,
simplified method of determining whether a controller replacement
project constitutes reconstruction under 40 CFR 60.15(b)(1) whereby
reconstruction may be considered to occur whenever greater than 50
percent of the number of existing onsite controllers are replaced.\121\
The EPA believes that allowing owners or operators to determine
reconstruction by counting the number of controllers replaced is a more
straightforward option than requiring owners and operators to provide
cost estimate information. By providing this option, the EPA intends to
reduce the administrative burden on owners and operators, as well as on
the implementing agency reviewing the information. Owners and operators
would be able to choose whether to use the cost-based criterion or the
proposed number-of-controllers criterion. No matter which option an
owner or operator chooses to use, the remaining provisions of 40 CFR
60.15 apply--namely, 40 CFR 60.15(a), the technological and economical
provision of 40 CFR 60.15(b)(2), and the requirements for notification
to the Administrator and a determination by the Administrator in 40 CFR
60.15(d), (e) and (f). The EPA is proposing that the standard in 40 CFR
60.15(b)(1) specifying that the ``fixed capital cost of the new
components exceeds 50 percent of the fixed capital cost that would be
required to construct a comparable entirely new facility'' can be met
through a showing that more than 50 percent of the number of existing
onsite controllers are replaced. Therefore, upon such a showing, an
owner or operator may demonstrate compliance with the remaining
provisions of 40 CFR 60.15 that reference the ``fixed capital cost''
criterion. The EPA solicits comment on its proposal to add an option
for owners or operators to use in determining whether reconstruction
occurs by showing the number of components replaced. The EPA reiterates
that this proposed option would supplement the existing option of
determining replacements by fixed capital cost, as set forth in 40 CFR
60.15.
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\121\ Adding this method of determining ``reconstruction'' for
pneumatic controllers is in accordance with 40 CFR 60.15(g), which
states that ``[i]ndividual subparts of this part
[``Reconstruction''] may include specific provisions which refine
and delimit the concept of reconstruction set forth in this
section.''
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A second factor for consideration in the reconstruction of an
existing pneumatic controller affected facility is during what time
period the number of controllers replaced or the fixed capital cost of
the new components should be aggregated. Consider the following
scenario: an owner first seeks to replace 30 percent of the pneumatic
controllers of an existing facility and then, shortly after commencing
or completing those replacements, the owner seeks to replace an
additional 30 percent. The owner would have replaced 60 percent of its
controllers in total, and presumably, the fixed capital cost of those
two replacement programs would be approximately 60 percent of the fixed
capital cost that would be required to construct a comparable entirely
new facility. It is unclear under the language of 40 CFR 60.15(d)
whether this owner should be deemed to have proposed two distinct
replacement programs or instead a single replacement program. The EPA
believes that such a stepwise controller replacement program should not
be used by facilities undergoing numerous replacement programs close in
time to avoid compliance with the NSPS. Failure to regulate these
sources would undermine Congress' intent that air quality be enhanced
over the long term with the turnover of polluting equipment, and with
the intent of the EPA's reconstruction provisions, which are triggered
where an existing facility replaces its components ``to such an extent
that it is technologically and economically feasible for the
reconstructed facility to comply with the applicable standard of
performance.'' \122\ Where a number of controllers are replaced
relatively close in time such that the aggregate costs or number of
controllers is greater than 50 percent, the EPA proposes to conclude
that it is reasonable to treat those replacements as part of a
continuous program of controller replacement for purpose of determining
reconstruction.
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\122\ See Modification, Notification, and Reconstruction, 40 FR
58,417 (December 16, 1975) (also stating that ``the purpose of the
reconstruction provision is to recognize that replacement of many of
the components of a facility can be substantially equivalent to
totally replacing it at the end of its useful life with a newly
constructed affected facility.'').
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In order to clarify how the regulatory language in 40 CFR 60.15
would apply to the replacement of pneumatic controllers, we are
proposing that where an owner or operator applies the definition of
reconstruction in Sec. 60.15(b)(1), reconstruction occurs when the
fixed capital cost of the new pneumatic controllers exceeds 50 percent
of the fixed capital cost that would be required to replace all the
pneumatic controllers at the site. The ``fixed capital cost of the new
pneumatic controllers'' includes the fixed capital cost of all
pneumatic controllers which are or will be replaced pursuant to all
continuous programs of component replacement which are commenced within
any 2-year rolling period.\123\
[[Page 74758]]
Thus, the EPA will count toward the greater than 50 percent
reconstruction threshold all controllers replaced pursuant to all
continuous programs of controller replacement which commence within any
2-year rolling period following proposal of these standards. If the
owner or operator applies the definition of reconstruction based on the
percentage of pneumatic controllers replaced, reconstruction occurs
when greater than 50 percent of the pneumatic controllers at a site are
replaced. The percentage includes all pneumatic controllers which are
or will be replaced pursuant to all continuous programs of pneumatic
controller replacement which are commenced within any 2-year rolling
period.
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\123\ As noted above, incorporating a set period of time within
which numerous component replacements amount to ``reconstruction''
is in accordance with 40 CFR 60.15(g), which provides that
``[i]ndividual subparts of this part [``Reconstruction''] may
include specific provisions which refine and delimit the concept of
reconstruction set forth in this section.'' In addition, the EPA
notes that numerous NSPS and EG regulatory provisions incorporate a
2-year time period into the definition of reconstruction. See, e.g.,
Standards of Performance for New Stationary Sources; Bulk Gasoline
Terminals, 48 FR 37582-83 (August 18, 1983) (explaining need for a
fixed period within which to determine reconstruction when component
replacement occurs over time and determining that two years is
reasonable); 40 CFR 60.506(b) (codifying reconstruction definition
to include such a time period for bulk gasoline terminals (40 CFR
part 60, subpart XX)). See also 40 CFR 60.383(b) (metallic mineral
processing plants (subpart LL)); 40 CFR 60.100(f), 60.100a(d)
(petroleum refineries (40 CFR part 60, subparts J and Ja)); 40 CFR
60.706(a) (volatile organic compound emissions from synthetic
organic chemical manufacturing industry reactor processes (40 CFR
part 60, subpart RRR)).
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In the Administrator's judgment, the 2-year rolling period provides
a reasonable method of determining whether an owner of an oil and
natural gas site with pneumatic controllers is actually proposing
extensive controller replacement, within the EPA's original intent in
promulgating 40 CFR 60.15. The EPA solicits comment on this proposed 2-
year rolling aggregation period for all continuous programs of
pneumatic controller and pneumatic pump replacement (see section
IV.E.b.i. for a discussion of proposing the same approach for
determining reconstruction for pneumatic pumps). The EPA is
particularly interested in comments regarding whether this approach
will make it easier for owners and operators to determine
reconstruction at their sites, whether using a set time frame is
reasonable and feasible to put into practice, whether two years is an
appropriate timeframe, and whether a rolling basis for the two-year
time frame is a reasonable calculation (for example, see Scenario 5
below). The EPA is also interested in understanding how frequently
controllers and pumps are typically replaced.
The following are example scenarios of the application of these
proposed requirements for a site with 15 natural gas-driven pneumatic
controllers. Scenario 1: One of the controllers is to be replaced (at
any given time). The collection of controllers at the site would not
become a pneumatic controller affected facility because the emissions
from the collection of controllers would not be increased (so such
action does not constitute a modification). Also, such action would not
constitute reconstruction because the fixed capital cost of the
replacement of this single controller would not equal 50 percent or
greater of the fixed capital cost that would be required to replace all
the controllers in the affected facility. Scenario 2: Eight of the
controllers are to be replaced at the same time. This would represent
reconstruction (because more than 50 percent of the total are being
replaced which means that the fixed capital cost of the replacement
would exceed 50 percent of the fixed capital cost that would be
required to replace all the controllers in the affected facility), so
the 15 controllers (i.e., the ``collection'' of controllers at the
site) would become a pneumatic controller affected facility. This
affected facility would then be subject to the zero-emissions standard,
meaning that all controllers at the site, including the eight new
controllers and the seven existing controllers, must comply with a
methane and VOC emission rate of zero. Scenario 3--six of the pneumatic
controllers are replaced in January and seven more controllers are
replaced the following April (15 months later). This would represent
reconstruction because more than 50 percent of the total number of
controllers are being replaced over a 2-year period, so the 15
controllers (i.e., the ``collection'' of controllers at the site) would
become a pneumatic controller affected facility at the time the seven
controllers were replaced in April. This affected facility would then
be subject to the zero-emissions standard, meaning that all controllers
at the site must comply with a methane and VOC emission rate of zero.
Scenario 4: An additional pneumatic controller is added at any given
time. This would represent a modification since it would constitute a
physical change and would result in an increase in emissions. The 16
controllers would represent a pneumatic controller affected facility
and all would need to comply with a methane and VOC emission rate of
zero. Scenario 5: replacement of four of the pneumatic controllers is
commenced in January in year 1; replacement of two more controllers is
commenced the following April in year 2 (15 months later); replacement
of two more is commenced the following March in year 3 (26 months after
the initiating replacement in January); and replacement of four more is
commenced that August of year 3 (31 months after initiating replacement
in January). Only six controllers of the 15 controllers were replaced
in the discrete two-year time period that began in January of year 1,
and therefore would not meet the proposed reconstruction definition.
However, when considered on a rolling 2-year basis, eight of the 15
controllers were replaced over years 2 and 3, which would meet the
proposed reconstruction definition. EPA specifically solicits comment
on whether the two-year time frame should be implemented on a rolling
basis or as a discrete time period.
The EPA also solicits comment on whether it would be appropriate to
apply either of the two elements of reconstruction that the EPA is
proposing for pneumatic controllers (and pneumatic pumps, as described
in section IV.E.) to any other affected facility in NSPS OOOOb and EG
OOOOc. Specifically, the EPA is interested in comments regarding
whether any other source category would benefit from either: 1) adding
an option to determine reconstruction based on the number of components
replaced (in addition to the existing option of determining
replacements by fixed capital cost, as set forth in 40 CFR 60.15), and/
or 2) setting a specific time period within which replaced components
will be aggregated toward the greater than 50 percent replacement
threshold (assessed either by number or cost), e.g., any two-year
period beginning when a continuous program of component replacement
commences.
Commenters stated that the EPA should allow like-kind replacement
of existing individual controllers without causing the controller to
become an affected facility under NSPS OOOOb.\124\ The commenters
indicated that if the EPA were to not allow this, operators who are
voluntarily replacing high-bleed natural gas-driven controllers with
low-bleed controllers would likely stop doing so. The EPA's proposed
change to a site-wide pneumatic controller affected facility definition
would allow the replacement of existing high-bleed controllers with
low-bleed controllers without becoming an affected facility, provided
that 50
[[Page 74759]]
percent or less of the controllers are replaced at the same time.
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\124\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0817 and EPA-HQ-
OAR-2021-0317-0831.
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Commenters also encouraged the EPA to provide an exemption for
``temporary sources.'' One commenter provided the example where an
operation may require use of temporary or portable equipment for a
short period of time (i.e., less than 180 days) where it may not be
possible to connect to the grid or route to an onsite control
device.\125\ Another commenter indicated that non-emitting \126\
requirements are not justified for short term controller usage related
to a non-stationary source, and exemption of controllers on temporary
equipment is consistent with state regulations proposed in New Mexico
and finalized in Colorado. The commenter indicated that the EPA should
also make it clear that the requirements for pneumatic controllers are
not applicable during drilling or completion.\127\
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\125\ See Document ID No. EPA-HQ-OAR-2021-0317-0831.
\126\ The terms ``zero emissions'' and ``non-emitting'' are used
to describe pneumatic controllers. In Colorado, 5 Code of Colorado
Regulations (CCR) Regulation 7, Part D, Section III, defines a
``non-emitting'' controller as ``a device that monitors a process
parameter such as liquid level, pressure or temperature and sends a
signal to a control valve in order to control the process parameter
and does not emit natural gas to the atmosphere. Examples of non-
emitting controllers include but are not limited to: no-bleed
pneumatic controllers, electric controllers, mechanical controllers
and routed pneumatic controllers.'' A routed pneumatic controller is
defined as ``a pneumatic controller that releases natural gas to a
process, sales line or to a combustion device instead of directly to
the atmosphere.'' The EPA is proposing that pneumatic controllers
must be ``zero emission'' controllers. The difference in non-
emitting, as defined by Colorado and as used by the commenter, and
zero emissions, as proposed in this action, is that pneumatic
controllers for which emissions are captured and routed to a
combustion device are not considered to be ``zero emission''
controllers. Therefore, routing to a combustion device is not an
option for compliance with the proposed NSPS OOOOb.
\127\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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The EPA acknowledges that the focus of the BSER analysis has been
on stationary sources and pneumatic controllers that are part of the
routine operation of oil and natural gas facilities. Although some type
of alternative approach may be warranted for pneumatic controllers
associated with temporary operations, we lack sufficient information to
include an exemption, or perhaps alternative standards, for pneumatic
controllers associated with temporary equipment. Therefore, the EPA is
requesting more information on these situations. The EPA would like
specific examples of when temporary equipment is utilized, the function
of the controllers during this time, how they are powered, and the
typical duration of their usage. The EPA also requests information
explaining in detail why the zero-emission solutions that are used for
the permanent equipment at the site cannot be also utilized for this
temporary equipment.
Another change to the affected facility definition in this
supplemental proposal is that natural gas-driven controllers from which
all emissions are collected and routed to a process, as well as self-
contained natural gas-driven pneumatic controllers, are not excluded
from the pneumatic controller affected facility definition. The EPA is
proposing to include these types of natural gas driven controllers
because they are driven by natural gas. While the EPA understands that
these controllers have zero routine emissions from the operation of the
device and are therefore compliant with the proposed standard when they
are properly operated and maintained, they do have the potential to
emit methane and VOC if they are not operated and maintained properly.
Therefore, we are proposing that natural gas-driven controllers from
which all emissions are collected and routed to a process, as well as
self-contained natural gas-driven pneumatic controllers (which release
gas into the downstream piping and not to the atmosphere), are part of
a pneumatic controller affected facility, and therefore subject to the
zero methane and VOC emissions standards. Specifically, the proposed
rule would require that owners and operators ensure proper maintenance
and operation of the controllers. For natural gas-driven controllers
from which all emissions are collected and routed to a process, the CVS
collecting and routing the emissions to the process must comply with
the CVS no identifiable emissions requirements in proposed 40 CFR
60.5411b, paragraphs (a) and (c). Self-contained controllers would be
required to be designed and operated with no identifiable emissions, as
demonstrated by initial and quarterly inspections using optical gas
imaging and any necessary corrective actions.
NSPS OOOOa exempts controllers from the standards for functional
needs, ``including but not limited to response time, safety, and
positive actuation.'' 40 CFR 60.6390a(a). The November 2021 proposed
rule did not include these functional needs exemptions, except for
locations in Alaska that did not have access to electrical power. The
NSPS OOOOa exemptions were based on the use of a low-bleed natural gas
driven pneumatic controller. Because the November 2021 proposed
standard would not have allowed the use of natural-gas driven
controllers, the EPA did not believe that this exemption was needed.
Several commenters requested that the NSPS OOOOa functional needs
exemptions be included in NSPS OOOOb in their entirety, while other
commenters indicated that they should only be allowed in very limited
instances and only when justification is provided in an annual report.
Commenters consistently raised the need to utilize natural gas-driven
pneumatic controllers associated with emergency shutdown devices
(ESDs). One commenter explained that an ESD is designed to minimize
consequences of emergency situations and will only emit in certain
isolated circumstances, such as if a well must be shut in. A large
change in pressure is required to actuate an ESD, which may not be
deliverable in a sufficient time by a compressed air or electric
controller. Furthermore, if power is lost, these devices must still be
able to function. It is rare that ESDs are activated, and their
emissions impact is minimal, but their functional need is necessary and
critical to safe operations. The commenter noted that both the current
version of the proposed rule in New Mexico and finalized regulations in
Colorado offer similar exemptions for ESDs.\128\
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\128\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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The EPA still believes that the overall functional needs exemption
is not necessary, as the limitations inherent in low-bleed natural gas-
driven controllers are not present in many of the zero emissions
options, particularly compressed air. The EPA also notes that any
natural gas-driven controller is allowed, whether low or high-bleed, if
the emissions are collected and routed to process in a manner that
achieves zero methane emissions.
The EPA recognizes the important function of natural gas-driven
controllers for ESDs. Rather than including such devices in the
affected facility, the EPA is proposing to specifically exclude them
from the affected facility definition.
Relatedly, one commenter requested that the EPA allow companies the
option to continue to use, or install, a dual natural gas system as a
backup for key controller functions. Such a natural gas backup system
would be used in the case of electrically actuated controller failure,
loss of power, or other contingencies.\129\ Another commenter added
that if the zero-emissions system (i.e., instrument air) goes down,
there is no provision within the proposed rule
[[Page 74760]]
to allow for the temporary use of natural gas. The commenter urged the
EPA to evaluate the reliability and availability of such systems that
would be deployed at such breadth.\130\ The EPA is interested in
understanding these backup systems more fully. In particular, the EPA
is requesting information on these systems regarding how frequently and
for how long these systems are used or would be expected to be used.
The EPA is concerned that allowing these backup systems would result in
a potential loophole that would enable owners or operators to continue
to use natural gas-driven controllers in routine situations. Therefore,
the EPA is interested in how the use of these systems could be narrowly
defined and how a clear distinction could be drawn between the allowed
use of these backup systems and violations of the zero emissions
standard.
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\129\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
\130\ See Document ID No. EPA-HQ-OAR-2021-0317-0599.
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ii. BSER Analysis
Based on comments received on the November 2021 BSER analysis and
updated information provided, the EPA revised the BSER analyses for
this supplemental proposal for pneumatic controllers for the production
and transmission and storage segments of the industry. The following
paragraphs describe the updated information, the changes to the BSER
analyses, and the updated results. The analysis for natural gas
processing plants, which can be found in the TSD for the November 2021
proposal, was not updated.
Several commenters objected to the emission factors that were used
for the analysis. One commenter stated that the emission factors used
in the GHGRP petroleum and natural gas source category (40 CFR part 98,
subpart W, also referred to as ``GHGRP subpart W'') for pneumatic
controllers were developed in the 1990's and that they may no longer be
applicable considering technological improvements.\131\ Another
commenter indicated that the factors used underestimated emissions and
that recent research indicates that actual average emissions from
pneumatic controllers may be higher than estimated.\132\
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\131\ See Document ID No. EPA-HQ-OAR-2021-0317-0749.
\132\ See Document ID No. EPA-HQ-OAR-2021-0317-0918.
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The emissions factors used for the November 2021 BSER analysis for
the production segment were from a recent study conducted by the
American Petroleum Institute (API).\133\ The factors for the
transmission and storage segment were from Table W-3B of GHGRP subpart
W (2021). Since the November 2021 proposal, the EPA has conducted a
comprehensive review of available information related to emissions from
natural gas-driven pneumatic controllers and has proposed to update the
emission factors in GHGRP subpart W to reflect this research (87 FR
36920; June 21, 2022). The EPA concluded that these results are the
most appropriate for use in this BSER analysis. The information
evaluated for the June 2022 proposed revisions to GHGRP subpart W
included the API study. Table 22 provides the emission factors used for
the November 2021 analysis and those used for the updated analysis in
this supplemental proposal.
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\133\ ``API Field Measurement Study: Pneumatic Controllers EPA
Stakeholder Workshop on Oil and Gas.'' November 7, 2019--Pittsburg
PA. Paul Tupper.
Table 22--Natural Gas-Driven Pneumatic Controller Emission Factors for
the Production and Transmission and Storage Segments
------------------------------------------------------------------------
Emissions (scf whole gas/hr)
-----------------------------------
Segment/type of controller 2022 Updated November 2021
analysis analysis
------------------------------------------------------------------------
Production:
Low bleed....................... 6.8 2.6
High bleed...................... 21.2 16.4
Intermittent vent............... 8.8 9.2
Transmission and Storage:
Low bleed....................... 6.8 1.37
High bleed...................... 32.4 18.2
Intermittent vent............... 2.3 2.35
------------------------------------------------------------------------
As can be seen in Table 22, the emissions factors for low-bleed and
high-bleed increased from those used for the November 2021 analysis,
while the intermittent vent factors decreased slightly.
One commenter indicated that while they appreciated that the EPA
utilized emission factors from the API's Field Measurement Study, they
believed that the use of the average intermittent pneumatic device vent
rate was incorrect in this application.\134\ They stated that under
this proposal, any intermittent device would be monitored routinely and
repaired or replaced if malfunctioning, so the more appropriate
emission factor is 0.28 scf whole gas/controller-hour, not the average
emission factor of 9.2 scf whole gas/controller-hour that the EPA used
in the November 2021 proposal. The commenter noted that the average
emission factor should only be used for controllers that are not
routinely monitored as part of a proactive monitoring and repair
program or where the monitoring status is unknown. The commenter stated
that the normal operation emission factor should be applied to
controllers that are found to be operating normally as part of a
proactive monitoring and repair program and contended that this
approach achieves a nearly similar level of emission reduction for much
less investment by operators.
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\134\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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The EPA agrees with the commenter that the lower emission factor is
appropriate to represent the emissions level for intermittent vent
controllers that are routinely monitored as part of a proactive
monitoring and repair program. While the EPA recognizes that some
companies have voluntarily implemented such programs, we do not have
information to suggest that the majority of the intermittent vent
controllers in operation are part of such a program. The average
emission factor that the EPA used considers those low-emitting properly
operating controllers, as well as those that are not operating
[[Page 74761]]
properly and that are venting during idle. The EPA finds that this
average factor is the correct factor to represent the ``uncontrolled''
emissions from the universe of intermittent vent controllers.
One commenter noted that all three sizes of model plants (small,
medium, large) contained one high-bleed natural gas-driven controller.
The commenter indicated that some state regulations do not allow for
the use of high-bleed controllers and concluded that the EPA's baseline
emissions analysis was likely skewed high.\135\
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\135\ See Document ID No. EPA-HQ-OAR-2021-0317-0749.
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The EPA agrees with this commenter. In addition to state
regulations that do not allow the use of high-bleed controllers, in the
absence of NSPS OOOOb, NSPS OOOOa would not allow the installation of
high-bleed controllers at new sites. Therefore, in the updated analysis
for new sources, the EPA did not include any high-bleed controllers in
any of the model plants. Table 23 provides a summary of the pneumatic
controller model plants and emissions. The emissions shown consider the
changes in the emission factors provided above in Table 22.
Table 23--Summary of Pneumatic Controller Model Plants for New Sources
--------------------------------------------------------------------------------------------------------------------------------------------------------
November 2021 analysis 2022 updated analysis
-------------------------------------------------------------------------------------------------------------
Segment/model plant Number of controllers Emissions (tpy) Number of controllers Emissions (tpy)
-------------------------------------------------------------------------------------------------------------
HB \a\ LB \a\ INT \a\ CH4 VOC HB \a\ LB \a\ INT \a\ CH4 VOC
--------------------------------------------------------------------------------------------------------------------------------------------------------
Production:
Small................................. 1 1 2 5.7 1.6 0 2 2 4.7 1.3
Medium................................ 1 1 6 11.2 3.1 0 2 6 10.0 2.8
High.................................. 1 4 15 24.9 6.9 0 5 15 25.1 7.0
Trans/Storage:
Small................................. 1 1 2 4.1 0.1 0 2 2 3.1 0.09
Medium................................ 1 1 6 5.7 0.2 0 2 6 4.6 0.1
High.................................. 1 4 15 10.0 0.3 0 5 15 11.6 0.3
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ HB--continuous high bleed, LB--continuous low bleed, INT--intermittent vent.
Some commenters also disagreed with the costs used for the BSER
analysis. One commenter said that the EPA's cost estimates were taken
directly from the 2016 White Paper \136\ and that the EPA did not
update the cost numbers for zero-emission electronic controllers, solar
panels, or batteries.\137\ The EPA notes that the primary basis for the
costs used for the November 2021 analysis was not the White Paper, but
rather a 2016 report by Carbon Limits, a consulting company with
longstanding experience in supporting efficiency measures in the
petroleum industry.\138\ One commenter \139\ pointed out that Carbon
Limits updated their report in early 2022,\140\ and recommended that
the EPA utilize the more recent information in that report since it
included more up-to-date research on zero emissions options for
pneumatic controllers. We reviewed the updated 2022 Carbon Limits
report and we agree with the commenter that the information presented
is well researched and representative of the costs of zero-emission
pneumatic controller technologies.
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\136\ U.S. EPA OAQPS. Oil and Natural Gas Sector Pneumatic
Devices. Report for Oil and Natural Gas Sector Pneumatic Devices
Review Panel. April 2014.
\137\ See Document ID No. EPA-HQ-OAR-2021-0317-0924.
\138\ Carbon Limits. (2016) Zero emission technologies for
pneumatic controllers in the USA--Applicability and cost
effectiveness.
\139\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
\140\ Carbon Limits. (2022) Zero emission technologies for
pneumatic controllers in the USA Updated applicability and cost
effectiveness. Available at https://cdn.catf.us/wp-content/uploads/2022/01/31114844/Zero-Emissions-Technologoes-for-Pneumatic-Controllers-2022.pdf.
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In addition to updating the analysis to reflect the information in
the 2022 Carbon Limits report, we also increased the estimate of
installation costs and considered operation and maintenance costs for
all types of pneumatic controller systems not driven by natural gas.
One commenter mentioned that for zero emission, electrical
controller setups, skilled electrical labor is required for wiring,
programming, and tuning, which cannot be conducted by lease operators
that would otherwise manage this equipment. According to the commenter,
one available estimate is as high as $20,000 in labor costs per multi-
well pad.\141\ In the November 2021 BSER analysis, we assumed that the
installation and engineering costs were 20 percent of the total cost of
the equipment. For the updated analysis, we increased those costs to 50
percent. The results were installation and engineering costs ranging
from $8,500 for a small electrical controller system to almost $52,000
for a large instrument air system.
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\141\ See Document ID No. EPA-HQ-OAR-2021-0317-0749.
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Another change to the capital cost estimate that the EPA made was
to adjust the capital cost to represent the difference in the capital
cost between the pneumatic controller system not driven by natural gas
and the natural gas-driven controllers that would be used in the
absence of a zero emissions requirement. These costs, which were
calculated based on $2,227 equipment costs and the $387 installation
cost per pneumatic controller, were subtracted from the total capital
investment of the pneumatic controller systems not driven by natural
gas.
For the November 2021 analysis, the annual costs were estimated as
the capital recovery of the original capital investment. This assumed
that the operating and maintenance costs for a pneumatic controller
system not driven by natural gas was the same as for natural gas-driven
controllers. For this analysis, we took into account differences in
operating costs. In general, the operating and maintenance costs for
pneumatic controller systems not driven by natural gas is less than
that of natural gas driven controllers, particularly if the gas is wet
gas. To estimate the operating costs for natural gas-driven
controllers, we used the average between the wet gas and dry gas cost
from the 2022 Carbon Limits report. This resulted in a net savings in
the annual operations and maintenance costs for electric and solar-
powered controller systems. There are additional operating and
maintenance costs
[[Page 74762]]
associated with instrument air systems, which resulted in an overall
increase in these costs as compared to natural gas-driven controllers.
The costs for electric controllers and instrument air systems
assume access to electrical power (that is, access to the grid). Solar-
powered controllers can be utilized at remote sites that do not have
access to electrical power. Instrument air systems can also be utilized
at sites without access to the electricity grid, but these would
require the installation and operation of a generator. These generators
could be powered by engines fueled by natural gas, diesel, or by solar
energy. One commenter provided estimated costs ranging from $60,000 to
over $200,000 for an instrument air system driven by a natural gas
generator.\142\ Using the information provided by the commenter, the
EPA estimated costs for the three model plants. Note that the largest
model plant contained 20 controllers and the highest cost provided by
the commenter was for a site with more than 200 controllers. Therefore,
this cost was not utilized. The EPA is specifically requesting more
detailed information on the use of generators at sites without access
to the grid to power pneumatic controllers, primarily to power
instrument air systems. The EPA is also interested in receiving more
information on the costs associated with this equipment. Table 24
provides the updated pneumatic controller systems not driven by natural
gas costs. This table also provides the costs from the November 2021
analysis for comparison.
---------------------------------------------------------------------------
\142\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
Table 24--Total Capital and Annual Costs for Pneumatic Controller Systems Not Driven by Natural Gas
--------------------------------------------------------------------------------------------------------------------------------------------------------
November 2021 analysis 2022 Updated analysis
--------------------------------------------------------------------------------------------------------------
Model plant Adjusted
TCI \a\ TAC \b\ TCI \a\ TCI \b\ TAC \c\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Electric:
Small System......................... $25,494........................... $2,799............................ $25,742 $15,287 $762
Medium System........................ 45,889............................ 5,038............................. 46,335 25,426 959
Solar:
Small System......................... 28,171............................ 3,093............................. 27,286 16,831 1,112
Medium System........................ 51,242............................ 5,626............................. 49,424 28,515 1,679
Instrument Air System--Grid:
Small System......................... not estimated..................... not estimated..................... 57,966 47,512 9,285
Medium System........................ not estimated..................... not estimated..................... 92,335 71,426 10,658
Large System......................... 95,602............................ 10,497............................ 165,550 113,277 14,891
Instrument Air System--Natural Gas
Generator:
Small System......................... not estimated..................... not estimated..................... 105,570 95,115 12,604
Medium System........................ not estimated..................... not estimated..................... 121,240 100,231 11,914
Large System......................... not estimated..................... not estimated..................... 242,850 190,577 19,565
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ TCI = Total capital investment includes capital cost of equipment plus engineering and installation costs.
\b\ Adjusted TCI = Total capital investment minus the cost that would have been incurred if natural gas-driven controllers had been installed.
\c\ TAC = Total annual costs including capital recovery (at 7 percent interest and 15-year equipment life) and operation and maintenance costs.
The controllers not driven by natural gas do not emit methane or
VOC. Therefore, the emission reductions associated with these systems
equal the total emissions shown above in Table 23. The estimated cost
effectiveness values for the controllers not driven by natural gas are
provided in Table 25. In addition to the cost effectiveness values,
Table 25 provides a conclusion regarding whether the estimated cost
effectiveness value is within the range that the EPA has typically
considered to be reasonable. The ``overall'' reasonableness
determination is classified as ``Y'' if the cost effectiveness of
either methane or VOC is within the range that the EPA considers
reasonable for that pollutant, or ``N'' if both the methane and VOC
cost effectiveness values are beyond the range the EPA considers
reasonable on a multipollutant basis.
Table 25--Summary of Pneumatic Controller Systems Not Driven by Natural Gas Cost Effectiveness for New Sources
----------------------------------------------------------------------------------------------------------------
Cost effectiveness ($/ton) \a\--reasonable?
--------------------------------------------------------------------------------
Segment/model plant Single pollutant Multipollutant
---------------------------------------------------------------- Overall \a\
Methane VOC Methane VOC
----------------------------------------------------------------------------------------------------------------
Production:
Small--Electric $162-Y $581-Y $81-Y $291-Y Y
controllers--grid.........
Small--Electric 238-Y 856-Y 119-Y 428-Y Y
controllers--solar........
Small--Compressed air--grid 1,969-Y 7,082-N 984-Y 3,541-Y Y
Small--Compressed air-- 2,673-N 9,615-N 1,336-Y 4,807-Y Y
generator.................
Medium--Electric 96-Y 344-Y 48-Y 172-Y Y
controllers--grid.........
Medium--Electric 167-Y 602-Y 84-Y 301-Y Y
controllers--solar........
Medium--Compressed air-- 1,062-Y 3,820-Y 531-Y 1,910-Y Y
grid......................
Medium--Compressed air-- 1,187-Y 4,270-Y 594-Y 2,135-Y Y
generator.................
Large--Electric 62-Y 222-Y 31-Y 111-Y Y
controllers--grid.........
Large--Electric 130-Y 467-Y 65-Y 234-Y Y
controllers--solar........
[[Page 74763]]
Large--Compressed air--grid 593-Y 2,135-Y 297-Y 1,067-Y Y
Large--Compressed air-- 780-Y 2,805-Y 390-Y 1,402-Y Y
generator.................
Transmission and Storage:
Small--Electric 247-Y 8,942-N 124-Y 4,471-Y Y
controllers--grid.........
Small--Electric 364-Y 13,164-N 182-Y 6,582-N Y
controllers--solar........
Small--Compressed air--grid 3,015-N 108,939-N 1,507-Y 54,469-N N
Small--Compressed air-- 4,093-N 147,891-N 2,046-N 73,946-N N
generator.................
Medium--Electric 207-Y 7,474-N 103-Y 3,737-Y Y
controllers--grid.........
Medium--Electric 362-Y 13,082-N 181-Y 6,541-N Y
controllers--solar........
Medium--Compressed air-- 2,299-N 83,066-N 1,149-Y 41,533-N N
grid......................
Medium--Compressed air-- 2,570-N 92,854-N 1,285-Y 46,427-N N
generator.................
Large--Electric 134-Y 4,830-Y 67-Y 2,415-Y Y
controllers--grid.........
Large--Electric 281-Y 10,156-N 141-Y 5,078-Y Y
controllers--solar........
Large--Compressed air--grid 1,285-Y 46,422-N 642-Y 23,211-N Y
Large--Compressed air-- 1,688-Y 60,992-N 844-Y 30,496-N Y
generator.................
----------------------------------------------------------------------------------------------------------------
\a\ For the production and processing segments, the owners and operators realize the savings for the natural gas
that not emitted and lost. The cost effectiveness values shown do not consider these savings. Note that the
consideration of savings does not impact whether the cost effectiveness of any of these options falls within
the ranges considered reasonable by the EPA.
\b\ For overall cost effectiveness to be considered reasonable, either the cost effectiveness of methane or VOC
on a single pollutant basis must be within the ranges considered reasonable by the EPA, or the cost
effectiveness of both methane and VOC on a multipollutant basis must be within the ranges considered
reasonable by the EPA.
iii. Proposed BSER Conclusion.
As demonstrated in the analysis and shown in Table 25, there are
pneumatic controller options for controllers not driven by natural gas
at sites in the production and transmission and storage segments where
the cost effectiveness is within the ranges considered to be reasonable
by the EPA. These options can be utilized at sites with access to grid
electricity and remote sites that do not have this access. This
conclusion is consistent with the findings in the November 2021
proposal.
In addition to these options that use pneumatic controllers not
driven by natural gas, there are two types of natural gas-driven
controllers that we are proposing as zero-emissions options: (1)
Controllers whose emissions are collected and routed to a process, and
(2) self-contained natural gas pneumatic controllers. As noted in
section IV.D.1.b.i, these natural-gas driven controllers are included
in the revised proposed definition of affected facility, meaning that
they would be subject to standards to ensure that they are operated and
maintained in a manner that ensures zero emissions of methane and VOC.
We are including these as compliance options in this proposed action
because: (1) they are included as compliance options under several
state rules, and (2) there is cursory information indicating that they
are utilized in some locations. However, the available information
about the prevalence of either of these options at sites in the oil and
natural gas production or transmission and storage segments is very
limited. Therefore, the EPA is requesting is requesting comment on
several issues related to these controllers.
The EPA is interested in several aspects related to the option of
collecting the pneumatic controller emissions and routing them to a
process. First, we are soliciting information that describes specific
situations where owners and operators have utilized this option to use,
rather than lose, the valuable natural gas emitted from pneumatic
controllers. We are interested in the specific processes and equipment
needed, as well as their costs.
Second, our understanding is that routing emissions from pneumatic
controllers to a process achieves a 100 percent reduction in emissions.
This understanding is based on the fact that the natural gas that is
emitted from pneumatic controllers is drawn directly from the raw
product gas stream that will be collected and routed to a gathering and
boosting station and eventually to a natural gas processing plant
(i.e., the gas ``sales line''). Therefore, the emissions from pneumatic
controllers are of the same composition as the gas in the sales line.
Since the emissions are at atmospheric pressure, it is likely that the
gas would need to be compressed prior to re-introduction to the sales
line. We do not expect that this compression would result in emissions.
Similarly, since the gas composition of these emissions is typically
high in methane, the heat content would make it amendable to being used
as fuel, or introduced with the primary fuel stream for use in an
engine without the need for additional processing that could result in
emissions. We are interested in information to support this
understanding that routing emissions from pneumatic controllers to a
process achieves a 100 percent reduction in emissions.
The 100 percent emissions reductions that we believe can be
achieved for controllers contrasts with routing emissions from storage
vessels or centrifugal compressor wet seal fluid degassing systems to a
process where the emissions are of a different composition from the
sales gas. For these situations, a VRU or other treatment is necessary
to obtain a gas stream whose composition is suitable to be returned to
the sales line or used for another purpose. A VRU often includes a
scrubber, separator, condenser, or other component that has a small
vent stream emitted to the atmosphere. In addition, the complex nature
of VRUs results in the need for maintenance or other situations where
the VRU may be bypassed, and emissions vented for short periods of
time. Because of both of these situations, the EPA has historically
assumed that VRUs achieve
[[Page 74764]]
a 95 percent reduction or greater in emissions.
The EPA requests information on the assumption that installation of
VRUs would not be needed to enable the use of emissions from pneumatic
controllers in a process. If there are situations where a VRU is
needed, the EPA is interested in the conditions that result in this
need, as well as the emissions reduction achieved and the costs.
We are aware of technical limitations of self-contained
controllers, namely that their applicability is limited by a number of
conditions (e.g., pressure differential, downstream pressure, etc.).
The EPA is therefore specifically soliciting information on the
frequency of the use of these self-contained controllers in the field,
as well as confirmation of specific limitations and costs. We are also
interested in information to support our understanding that self-
contained controllers achieve 100 percent reduction in emissions when
maintained and operated properly.
Several commenters maintain that there are technical limitations
that will not allow pneumatic controllers not driven by natural gas to
be utilized at sites without electricity, particularly solar-powered
controllers.\143\ One commenter stated that while the EPA suggested the
use of onsite solar generation paired with battery storage as an
alternative to grid electricity, such systems are currently ``uncommon,
unreliable, and will likely increase the frequency of facility upsets,
which will increase safety risks such as overpressure events and
spills.'' \144\ Another commenter stated that while there may be some
pilot projects within the industry, it has not been demonstrated that
reliable turnkey packages are available on a widescale basis.\145\
Several commenters noted that there are severe geographic limitations
to the use of any solar-powered devices. One noted that West Virginia
averages only 164 days of sunshine per year, compared with an average
of 205 days for the rest of the United States. Even in typically sunny
states, operations in canyons or mountain valleys receive significantly
limited sunlight exposure. Snow and ice raise additional reliability
concerns during winter months.\146\ Another commenter stated that
large-scale solar applications have not yet been tested in winter
months when there is more cloud coverage, increased snow cover, and
less sunlight in more northern locations (e.g., Colorado, North Dakota,
Idaho, and Wyoming).\147\ One industry organization agreed that solar
power might be an option but reported that their member companies have
not yet been able to demonstrate this to be universally true in Utah's
Uinta Basin. This organization cited specific problems such as the
requirement of excess generation and battery storage capacity to
maintain operations during wintertime inversions and challenges from
snowstorms, which could cover the solar panels and inhibit or prevent
electricity generation. They conclude that utilizing solar electricity
for oil and gas operations in Utah may be labor intensive, costly, and
unreliable such that operations would still require backup power from
the electric grid or from generators.\148\ Another commenter also
mentioned that it is probable that supplemental power via natural gas
or diesel-powered generators could be required during winter months
and/or severe weather events, which would be necessary to ensure a
continuous power supply, and, thus, a controlled operation. This
commenter also noted that interruptions within the control system pose
safety risks to operators and can damage processing equipment, which
could potentially lead to excess emissions associated with equipment
malfunctions.\149\
---------------------------------------------------------------------------
\143\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0817, EPA-HQ-
OAR-2021-0317-0743, EPA-HQ-OAR-2021-0317-0749, and EPA-HQ-OAR-2021-
0317-0808.
\144\ See Document ID No. EPA-HQ-OAR-2021-0317-0793.
\145\ See Document ID No. EPA-HQ-OAR-2021-0317-0599.
\146\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
\147\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
\148\ See Document ID No. EPA-HQ-OAR-2021-0317-0740.
\149\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------
One commenter indicated that they were unaware of any operators
converting to solar-powered electric controllers at this time. They
said while the technology seems promising, many of these solar systems
have not yet been proven reliable for all remote locations or facility
designs and are not ready for deployment across the country at the
large scale that the EPA's proposed rules would require. They note that
in 2014, the EPA stated ``solar-powered controllers can replace
continuous bleed controllers in certain applications but are not
broadly applicable to all segments of the oil and natural gas
industry.'' \150\
---------------------------------------------------------------------------
\150\ Oil and Natural Gas Sector Pneumatic Devices, Review
Panel, USEPA, OAQPS, 2014: https://www.ourenergypolicy.org/wp-content/uploads/2014/04/epa-devices.pdf.
---------------------------------------------------------------------------
However, other commenters disagreed and supported the EPA's
November 2021 proposal to require zero-emission controllers. Commenters
cited several state rules that require all new pneumatic controllers to
be non-emitting, including states with colder climates (Colorado). As
the EPA also indicated in the November 2021 proposal, there are
Canadian provinces that have successfully implemented non-emitting
controller regulations. Comments were also provided by vendors that
report the successful installation and operation of zero-emission
controller systems in a variety of climate conditions.\151\ One of
these vendors notes the installation of solar-driven instrument air
systems in several states, including Wyoming and Colorado.\152\
---------------------------------------------------------------------------
\151\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0838 and EPA-HQ-
OAR-2021-0317-0802.
\152\ See Document ID No. EPA-HQ-OAR-2021-0317-0838.
---------------------------------------------------------------------------
In a supplement to their 2022 report that was provided in a late
comment, Carbon Limits addressed many of the alleged shortcomings of
solar and other zero-emitting controller technologies raised in public
comments. They state, ``[a]ddressing the queries on the reliability of
solar systems for remote locations and cold states, the technology
providers and operators interviewed as part of this assessment have
solar-powered controllers installed at well sites in remote and cold
locations such as Northern Alberta and British Colombia, without major
reliability issues. Some of the interviewed technology providers have
installed these systems in over 400 well-sites in these states and
provinces. The commenter further refers to a statement by the EPA from
2014. However, it is to be noted that solar technology has improved
drastically from 2014 to 2021. Efficiency has increased while costs
have gone down significantly. Solar-powered controllers are capable of
operating at low temperatures and remote locations, among different gas
sectors. When it comes to snow cover on panels affecting the
performance of solar cells, all the interviewees stated that the panels
are placed at a low angle, to catch ample sun in the winter months.
Most often, these panels are placed vertically, eliminating snow cover
on the solar panels.'' \153\ Commenters also indicated that at sites
without electricity, owners or operators could install a generator to
power an instrument air system.
---------------------------------------------------------------------------
\153\ See Document ID No. EPA-HQ-OAR-2021-0317-1451.
---------------------------------------------------------------------------
Under CAA section 111(b), EPA must show that a BSER determination
has been ``adequately demonstrated.'' The EPA concludes that zero-
emission
[[Page 74765]]
pneumatic controller systems that do not use natural gas meet this
standard at sites both with and without access to electricity. In
addition, as discussed above, we have concluded that there are options
available at sites in all segments of the industry that have cost-
effective values considered reasonable by the EPA.
Secondary impacts from these non-natural gas-driven, zero-emission
controllers, particularly from the use of instrument air systems are
indirect, variable, and dependent on the electrical supply used to
power the compressor. The 2016 Carbon Limits report indicates that a
small instrument air compressor would require around 5 horsepower (HP)
of air compression capacity, while a larger facility would require up
to 20 HP. Assuming the compressor operates one-half of the total hours
in a year, and using an electricity factor of 0.75 HP/kilowatt, the
compressor yields an annual electricity usage of around 100 mmBtu/yr
for a 5 HP compressor and 400 mmBty/yr for a 20 HP compressor. There
would be secondary air pollution impacts associated with the generation
of this electricity. The secondary criteria pollutant emissions are
estimated to be 7 lbs/yr CO, 60 lbs/yr NO2, 3 lbs/yr PM, 1
lb/yr PM2.5, and 120 lbs/yr SO2 for a 5 HP
compressor and 29 lbs/yr CO, 239 lbs/yr NO2, 12 lbs/yr PM, 4
lb/yr PM2.5, and 478 lbs/yr SO2 for a 20 HP
compressor. The secondary GHG emissions generated as a result of this
electricity generation are 20,489 lbs/yr CO2, 2 lbs/yr
methane, and 1lb/yr N2O for a 5 HP compressor and 81,955
lbs/yr CO2, 10 lbs/yr methane, and 2 lbs/yr N2O
for a 20 HP compressor. Considering the global warming potential of
these GHGs, the total CO2e emissions would be 20,667 lbs
CO2e from a 5 HP compressor and 82,669 lbs CO2e
from a 20 HP compressor. These total CO2e would represent a
more than 90 percent reduction in the CO2e emissions when
compared to the uncontrolled methane emissions from natural gas driven
controllers. No other secondary impacts are expected.
Commenters indicated that at sites without electricity, owners or
operators would likely install a generator to power an instrument air
system. These commenters contended that relying on a generator would
result in emissions of criteria pollutants and carbon monoxide (CO)
that could potentially offset the emissions reductions from the methane
and VOC. One commenter provided an estimate that a natural gas-fired
generator of approximately 200 horsepower would be needed to support
reliable operation of a large instrument air system without grid power.
This commenter estimated emissions from a generator that size to be
1.94 tpy NOX, 3.88 tpy of CO, 1.36 tpy of VOC, 0.12 tpy of
particulate matter with a diameter of 10 micrometers or less
(PM10), 0.14 tpy CH4 and 730 tpy of
CO2.\154\
---------------------------------------------------------------------------
\154\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------
The EPA recognizes that if owners and operators elect to comply by
installing and operating a generator, there will be secondary emissions
generated from the fuel combustion. However, we also point out that,
for a site with 100 controllers (a size cited by the commenter
requiring a large instrument air system), these secondary emissions
would represent approximately a 77 percent decrease in CO2
equivalent emissions and a 96 percent decrease in VOC emissions from a
site with 25 low bleed and 75 intermittent bleed controllers.
In light of the above, we find that the BSER for reducing methane
and VOC emissions from natural gas-driven controllers in the production
and transmission and storage segments of the industry to be the use of
controllers that have a methane and VOC emission rate of zero. This
option results in a 100 percent reduction of emissions for both methane
and VOC. Therefore, for NSPS OOOOb, we are proposing to require that
each pneumatic controller affected facility be designed and operated
with a methane and VOC emission rate of zero in the production and
transmission and storage segments of the source category, with the
following exception for sites in Alaska that do not have access to grid
electricity.
In the November 2021 proposal, we determined a separate BSER for
the subset of pneumatic controllers, specifically those at sites in
Alaska that do not have access to electricity. We also proposed
specific requirements for these controllers. We are not proposing any
changes to these requirements in this supplemental proposal.
Specifically, these sites would be required to use low-bleed
controllers (instead of high-bleed controllers) and would be allowed to
use high-bleed controllers instead of low-bleed based only upon a
showing of functional needs. In addition, we proposed that owners or
operators at such sites be required to inspect intermittent vent
controllers to ensure they are not venting during idle periods. The
rationale for this decision was discussed in the November 2021 proposal
(86 FR 63207; November 15, 2021).
The EPA notes that the BSER determination for pneumatic controllers
at natural gas processing plants was also not revisited in this
supplemental proposal. Therefore, the November 2021 BSER determination
of zero emission controllers at natural gas processing plants is
retained in this supplemental proposal. The rationale for this decision
is contained in the November 2021 proposal (86 FR 63207- 63208;
November 15, 2021).
iv. Routing to an Existing Control Device
Several commenters requested that the EPA include an option to
collect the emissions from natural gas-driven controllers and route
them to a flare or combustion device that achieves 95 percent reduction
in methane and VOC. These comments stated that in many situations, an
onsite control device already exists and that using it would be a cost-
effective method of achieving significant emission reductions.
The EPA acknowledges that this is a viable option to achieve
emission reductions from natural gas-driven pneumatic controllers.
However, as discussed above, we have determined that BSER for pneumatic
controllers is use of one of the several types of controllers that have
zero methane and VOC emissions. Thus, routing to an existing control
device (i.e., achieving 95 percent reduction) would result in a less
stringent standard than the BSER. In the 2021 Inventory of U.S.
Greenhouse Gas Emissions and Sinks (GHGI), the estimated methane
emissions for 2019 from pneumatic controllers were 700,000 metric tons
of methane for petroleum systems and 1.4 million metric tons for
natural gas systems. These levels represent 45 percent of the total
methane emissions estimated from all petroleum systems (i.e.,
exploration through refining) sources and 22 percent of all methane
emissions from natural gas systems (i.e., exploration through
distribution). While we recognize that these emissions include
emissions from existing sources, it is clear that pneumatic controllers
represent a significant source of methane and VOC emissions. Allowing
an option that results in 5 percent more emissions would be a quite
significant increase.
The EPA recognizes that there are other instances in the proposed
rule where there are options allowed that are less stringent than the
measures determined to be BSER. However, in each of these situations,
the EPA is convinced that there are genuine technical limitations or
safety issues that make compliance with the BSER infeasible. For
pneumatic controllers, the EPA maintains that there is a
[[Page 74766]]
technically feasible option available for all production, processing,
and transmission and storage sites, except for sites in Alaska without
access to electricity. Therefore, the proposed NSPS OOOOb does not
include any alternative non-zero emission standards for pneumatic
controllers. The EPA is interested in information that may dispute the
conclusion that there is a technically feasible option that does not
emit methane or VOC available for all sites in all segments. Some
commenters raised concerns about specific situations that may make
individual technologies impracticable to implement (e.g., the inability
of solar-powered controller systems to meet the needs at certain remote
locations that do not have access to electricity). Although the EPA
will consider any additional information commenters may submit about
such situations, the EPA notes that there are multiple options for
meeting the proposed zero-emission standard and that limitations on the
use of one technology at any given site does not mean that other
options for meeting the standard are unavailable. As a result, the EPA
is particularly interested in understanding whether there are site
characteristics that would make every zero-emitting option (electric
controllers powered by the grid or by solar power; instrument air
systems powered by the grid, a generator, or by solar power; collecting
the emissions and routing them to a process; self-contained
controllers, etc.) technically infeasible at the site.
c. Summary of Proposed Standards
In this supplemental proposal, the pneumatic controller affected
facility is defined as the collection of natural gas-driven pneumatic
controllers at a well site, centralized production facility, onshore
natural gas processing plant, or a compressor station. This definition
applies in all segments of the oil and natural gas source category.
Natural gas-driven pneumatic controllers that function as emergency
shutdown devices and pneumatic controllers that are not driven by
natural gas are exempt from the affected facility, provided that the
records are maintained to document these conditions. In addition to the
modification definition in 40 CFR 60.14 and the reconstruction
definition in 40 CFR 60.15, the proposed rule includes clarification of
these terms for the pneumatic controller affected facility. A
modification occurs when the number of natural gas-driven pneumatic
controllers at a site is increased by one or more, and reconstruction
occurs when either the cost of the controllers being replaced exceeds
50 percent of the cost to replace all the controllers, or when 50
percent or more of the pneumatic controllers at a site are replaced.
The proposed standard for pneumatic controller affected facilities
is zero emissions of methane and VOC to the atmosphere. An exception to
this standard exists for pneumatic controller affected facilities
located at sites in Alaska without access to electrical power. The
proposed rule does not specify how this emission rate of zero must be
achieved, but a variety of viable options are available. All
controllers at a site that are not driven by natural gas (e.g.,
pneumatic controllers driven by compressed air, electric controllers,
solar-powered controllers) are not part of the pneumatic controller
affected facility, provided that documentation is maintained as
previously discussed. If all pneumatic controllers at a site are not
natural gas-driven, then there would be no pneumatic controller
affected facility at the site, provided the documentation is
maintained.
Natural gas-driven controllers can comply with the zero emissions
standard by collecting and routing emissions via a CVS to process, or
by using self-contained controllers. The proposed rule defines a self-
contained pneumatic controller as a natural gas-driven pneumatic
controller that releases gas into the downstream piping and not to the
atmosphere, resulting in zero methane and VOC emissions.
If you comply by routing the emissions to a process, the CVS that
collects the emissions must be routed to a process through a CVS that
meets the requirements in proposed 40 CFR 60.5411b, paragraphs (a) and
(c). These requirements include certification by a professional or in-
house engineer that the CVS was designed properly, and that the CVS is
operated with no identifiable emissions as demonstrated through initial
and periodic inspections, observations, and measurements. This includes
monitoring using OGI at the same frequency as required under the
fugitive monitoring program. All issues identified must be corrected.
Required records would include the certification and records of all
inspections and any corrective actions to repair the defect or the
leak.
If you comply by using a self-contained natural gas-driven
pneumatic controller, the controller must be designed and operated with
no detectable emissions, as demonstrated by conducting initial and
quarterly inspections using optical gas imaging. Required records would
include records of all inspections and any corrective actions to repair
the defect or the leak.
The proposed rule includes an exemption from the zero-emission
requirement for pneumatic controllers in Alaska at locations where
electrical power is not available. In these situations, the proposed
standards require the use of a low-bleed controller (i.e., a controller
with a natural gas bleed rate less than or equal to 6 scfh). Records
would be required to demonstrate that the controller is designed and
operated to achieve a bleed rate less than or equal to 6 scfh. For
controllers in Alaska at location without electrical power, the
proposed rule includes the exemption that would allow the use of high-
bleed controllers instead of low-bleed based on functional needs
(including but not limited to response time, safety, or positive
actuation). To utilize this exemption, a demonstration of the
functional need must be made and submitted in the initial annual
report. The proposed rule also includes requirements for natural gas-
driven intermittent vent controllers at these sites in Alaska without
access to electrical power. Specifically, the proposed rule would
require that an intermittent vent not vent to the atmosphere during
idle periods. Compliance with this requirement would be demonstrated by
modifying the fugitive emissions monitoring plan to include these
intermittent vents, monitoring them at the schedule required by the
site for the fugitive emissions components affected facility, and
repairing any leaks or defects identified. Records would be required of
all inspections and repairs.
2. EG OOOOc
The November 2021 proposal defined the pneumatic controller
designated facility for EG OOOOc as each natural gas-driven controller.
As with the change discussed above for the NSPS OOOOb affected
facility, we are also proposing that the EG OOOOc designated facility
definition to be the collection of natural gas-driven pneumatic
controllers at a well site, centralized production facility, onshore
natural gas processing plant, or a compressor station. This definition
applies in all segments of the oil and natural gas source category.
In response to comments received and additional information
collected, we also updated the BSER analysis for existing sources. The
same basic changes were made to the existing source analysis as
discussed above for the new source analysis. However, there were a few
instances where the emissions and costs differed for existing sources
as compared to new. These are discussed in the following sections.
[[Page 74767]]
a. Model Plant Emissions
As noted above, for the new source analysis we adjusted the model
facilities to remove all high-bleed controllers since NSPS OOOOa and
many state rules already prohibit the use of high-bleed controllers.
While there are limited instances where states impose this requirement
on existing sources, we concluded that the best representation for
pneumatic controller model plants was to include one high-bleed for
each type of facility. The emissions, calculated using the updated
emission factors provided in Table 22, are provided below in Table 26.
Table 26--Summary for Pneumatic Controller Model Plants for Existing Sources
----------------------------------------------------------------------------------------------------------------
Number of controllers
------------------------------------------------ Methane
Segment/model plant Intermittent emissions
High bleed Low bleed vent (tpy)
----------------------------------------------------------------------------------------------------------------
Production:
Small....................................... 1 1 2 6.9
Medium...................................... 1 1 6 12.2
High........................................ 1 4 15 27.3
Transmission and Storage:
Small....................................... 1 1 2 7.4
Medium...................................... 1 1 6 9.0
High........................................ 1 4 15 15.9
----------------------------------------------------------------------------------------------------------------
b. Costs for Controllers Not Driven by Natural Gas
There were instances where the estimated costs for the systems for
controllers not driven by natural gas were different for existing
sources and for new sources. Following are brief descriptions of the
reasons for these differences.
For electric and solar-powered controllers, the new source capital
costs included the cost for controller valves. For existing sources, we
assumed that the existing valves could be used for converting from
natural gas pneumatic controllers. For new sites, the cost of natural
gas-driven controllers was subtracted from the cost of the controllers
not driven by natural gas, as those capital expenses would be
``saved.'' This adjustment was not made for existing sources. We
assumed that the relative engineering and installation costs would be
higher at an existing site; therefore, we assume an engineering and
installation cost of 100 percent of the capital costs. For instrument
air systems, the new site costs included costs for the new controllers,
while the assumption was that existing sources could continue to use
the existing controllers that were formerly driven by natural gas. The
instrumentation cost for a retrofit for an existing site was assumed to
be 40 percent higher than for a new site, and the engineering and
installation costs were assumed to be 100 percent of the capital costs
for existing sites (as opposed to 50 percent for new sites). As with
electric and solar-powered controllers, the cost of the natural gas-
driven controllers not needed was not subtracted from the existing
source capital costs.
The operation and maintenance costs for existing sources used were
the same as for new sources. Therefore, the only difference in total
annual costs was due to the difference in the capital recovery costs
because of the different total capital investment.
Table 27 compares the total capital investment and total annual
cost for new sources and existing sources for each model plant and zero
emission controller technology.
Table 27--Comparison of Total Capital and Annual Costs for Non-Emitting Controllers Not Driven by Natural Gas at
New and Existing Sources
----------------------------------------------------------------------------------------------------------------
New sources Existing sources
---------------------------------------------------------------
Model plant Adjusted TCI
\a\ \b\ TAC \c\ TCI\a\ TAC\c\ \d\
----------------------------------------------------------------------------------------------------------------
Electric:
Small System................................ $15,287 $762 $20,593 $1,345
Medium System............................... 25,426 1,112 34,322 1,936
Large System................................ 55,842 1,550 75,508 3,709
Solar:
Small System................................ 16,831 959 22,653 1,761
Medium System............................... 28,515 1,679 38,441 2,768
Large System.................................... 63,049 3,258 85,119 5,681
Instrument Air System--Grid:
Small System................................ 47,512 9,285 58,636 10,506
Medium System............................... 71,426 10,658 76,481 11,213
Large System.................................... 113,277 14,891 127,469 16,449
Instrument Air System--Generator:
Small System................................ 95,115 12,604 120,000 15,337
Medium System............................... 100,231 11,914 120,000 14,085
Large System................................ 190,577 19,565 220,000 22,795
----------------------------------------------------------------------------------------------------------------
\a\ TCI = Total capital investment includes capital cost of equipment plus engineering and installation costs.
\b\ Adjusted TCI = Total capital investment minus the cost that would have been incurred if natural gas-driven
controllers had been installed.
\c\ TAC = Total annual costs including capital recovery (at 7 percent interest and 15-year equipment life) and
operation and maintenance costs.
\d\ For the production segment, the owners and operators realize the savings for the natural gas that not
emitted and lost. The cost values shown do not consider these savings.
[[Page 74768]]
c. Existing Source BSER Determination
Table 28 shows the cost effectiveness values for methane of the
controller technologies that are not driven by natural gas and that do
not emit methane.
Table 28--Summary of Pneumatic Controller Systems Not Driven by Natural
Gas Methane Cost Effectiveness for Existing Sources
------------------------------------------------------------------------
Cost
effectiveness \a\
Segment--model plant ($/ton methane Reasonable?
reduced)
------------------------------------------------------------------------
Production Segment:
Small--Electric controllers-- $195 Y
grid...........................
Small--Electric controllers-- 255 Y
solar..........................
Small--Compressed air--grid..... 1,524 Y
Small--Compressed air--generator 2,225 N
Medium--Electric controllers - 158 Y
grid...........................
Medium--Electric controllers-- 227 Y
solar..........................
Medium--Compressed air--grid.... 918 Y
Medium--Compressed air-- 1,153 Y
generator......................
Large--Electric controllers - 136 Y
grid...........................
Large--Electric controllers-- 208 Y
solar..........................
Large--Compressed air--grid..... 603 Y
Large--Compressed air--generator 836 Y
Transmission and Storage Segment:
Small--Electric controllers-- 181 Y
grid...........................
Small--Electric controllers-- 238 Y
solar..........................
Small--Compressed air--grid..... 1,418 Y
Small--Compressed air--generator 2,069 Y
Medium--Electric controllers - 216 Y
grid...........................
Medium--Electric controllers-- 309 Y
solar..........................
Medium--Compressed air--grid.... 1,250 Y
Medium--Compressed air-- 1,571 Y
generator......................
Large--Electric controllers - 233 Y
grid...........................
Large--Electric controllers-- 357 Y
solar..........................
Large--Compressed air--grid..... 1,033 Y
Large--Compressed air--generator 1,432 Y
------------------------------------------------------------------------
\a\ For the production segment, the owners and operators realize the
savings for the natural gas that not emitted and lost. The cost
effectiveness values shown do not consider these savings. Note that
the consideration of savings does not impact whether the cost
effectiveness of any of these options falls within the ranges
considered reasonable by the EPA.
As shown in Table 28, all options evaluated, with the exception of
an instrument air system driven by a generator at a small model plant,
have cost effectiveness values within the range that the EPA considers
reasonable for methane.
Further, as discussed at length above in section IV.D.1.b.iii, the
EPA finds that these controller technologies not driven by natural gas
are technically feasible in locations with and without electrical
power. Owners and operators can use natural gas-driven low or high
bleed controllers or intermittent controllers, provided the emissions
are collected and routed through a CVS to a process. Finally, owners
and operators have the option of using natural gas-driven self-
contained controllers.
Secondary impacts from these options, particularly from the use of
instrument air systems, are indirect, variable, and dependent on the
electrical supply used to power the compressor. As discussed above,
this would result in an increase in electricity needs and minimal
emission increases. As discussed above, the use of a generator to power
an instrument air system will result in emissions of two criteria
pollutants--CO and CO2. However, the comparison in the
CO2 equivalent emissions shows that even with the secondary
emissions from the generator, there is a substantial reduction in
CO2 equivalent emissions.
In light of the above, we find that the BSER for reducing methane
emissions from existing natural gas-driven controllers in the
production and transmission and storage segments of the industry to be
the use of controllers that have a methane emission rate of zero. This
option results in a 100 percent reduction of emissions of methane.
Therefore, for EG OOOOc, we are proposing to require that each
pneumatic controller affected facility be designed and operated with a
methane emission rate of zero for all pneumatic controllers in the
production and transmission and storage segments of the source
category, with the exception discussed below.
As discussed above for new sources, we did not re-evaluate BSER for
sites in Alaska that do not have access to electricity and are
proposing the same requirements as in the November 2021 proposal.
Similarly, we did not re-evaluate BSER for pneumatic controllers at
existing natural gas processing plants. Therefore, the November 2021
BSER determination of zero-emission controllers at natural gas
processing plants is retained in this supplemental proposal.
The proposed standards and other requirements for existing
pneumatic controller designated facilities under EG OOOOc are the same
as described above for new pneumatic controller affected facilities
under the NSPS OOOOb.
d. Additional Comments
There were two additional topics raised in the public comments that
are discussed in this section: (1) The potential exemption of small
sites with low production and/or a low number of controllers, and (2)
issues associated with the supply chain.
[[Page 74769]]
i. Small Site Exemptions.
Several commenters requested that the EPA include an exemption for
small sites with low production and/or a low number of pneumatic
controllers. The commenters provided a range of pneumatic controllers
that they felt represented a reasonable cut-off, ranging from 3 to 30
controllers.
The EPA notes that the cost effectiveness values for the smallest
model plant, which includes 1 high-bleed, 1 low-bleed, and 2
intermittent vent controllers, were $181 and $238 per ton of methane
reduced for electric controllers and solar controllers, respectively.
These cost effectiveness values are well within the ranges considered
to be reasonable by the EPA. We also performed an analysis of the cost
effectiveness of the use of electric controllers and solar-powered
controllers at sites with a single controller. For sites with only one
high-bleed controller, the cost effectiveness was estimated to be $379
and $437 per ton of methane reduced for electric and solar-powered
controllers, respectively. For a site with one intermittent vent
controller, the cost effectiveness values were estimated as $913 per
ton for electric controllers, and $1,053 per ton for solar-powered
controllers. For a site with one low-bleed controller, the cost
effectiveness values were $1,181 per ton for electric controllers and
$1,363 per ton for solar-powered controllers. As all of these cost
effectiveness values are within the range considered reasonable for
methane by the EPA, this analysis does not support an exemption for
sites with low numbers of pneumatic controllers.
One commenter stated that even at the current prices for natural
gas, it would take the average low-production natural gas well about
six years of all of its profits to pay for the electric grid option and
more than that for the solar option. The commenter added that for a
Pennsylvania well site, the time period would be 70 or more years.\155\
This commenter did not provide details of their analysis. While the EPA
recognizes that that impacts on profitability are generally not
considered in determining BSER, we are interested in the details of the
analysis of profit margins at low production wells. Specific to this
information provided by the commenter, dividing the total estimated
capital investment of an electric controller system for the small model
plant ($20,593) by six years results in $3,400 per year. If it is
assumed that this capital investment is financed for six years at a 7
percent interest rate, this cost would be around $4,300 per year, which
equates to around $360 per month. The EPA is interested in learning
whether this amount represents typical profit margins for low
production wells.
---------------------------------------------------------------------------
\155\ See Document ID No. EPA-HQ-OAR-2021-0317-0814.
---------------------------------------------------------------------------
Another commenter added that the cost of converting to an
electronic controller or instrument air system will likely result in
the shut-in of many small, low-production well sites. These sites have
a remaining useful life that will be cut short by the proposed rule's
pneumatic controller requirements.\156\
---------------------------------------------------------------------------
\156\ See Document ID No. EPA-HQ-OAR-2021-0317-0777.
---------------------------------------------------------------------------
The EPA notes that the implementing regulations for emission
guidelines contained in 40 CFR part 60, subpart Ba include provisions
that allow states to develop a less stringent standard taking into
consideration factors such as the remaining useful life of such source.
For more information on remaining useful life and other factors
considerations, see section V.C of this preamble.
ii. Supply Chain Issues
In light of the proposal to require zero-emission pneumatic
controllers for both new and existing sources, the EPA would like to
address several comments it received and solicit related information.
One commenter predicted that the requirements will likely generate
supply chain shortages and the small operators will be last to procure
the necessary equipment at the highest price.\157\ Another commenter
stated that the EPA has not adequately considered the impacts of the
current supply chain interruptions on the ability of operators to
comply with the rule. Specialized equipment, such as air compressors,
electric controllers, and equipment needed to retrofit facilities have
been particularly hard-hit by supply chain constraints related to
COVID-19. This commenter reported that owners and operators have
already experienced delays of several months in acquiring equipment to
retrofit facilities to instrument air, all prior to the EPA proposal,
and that the increased demand for that equipment given proposed rule
requirements would only exacerbate the challenges associated with
acquiring that equipment.\158\ For existing sources, the EPA points out
that several years will pass between the time EG OOOOc is finalized and
the compliance dates for state rules, thus allowing a substantial
amount of time for adjustments in the supply chain. While the
commenters primarily focused on potential supply chain issues related
to requiring the conversion to zero emissions controllers at existing
sources, the EPA also understands that the promulgation of NSPS OOOOb
could also result in a spike in the demand. In light of these comments,
the EPA is specifically requesting additional comment on the
availability of zero-emission pneumatic controller systems not powered
by natural gas due to supply chain constraints or other reasons.
---------------------------------------------------------------------------
\157\ See Document ID No. EPA-HQ-OAR-2021-0317-0814.
\158\ See Document ID No. EPA-HQ-OAR-2021-0317-0743.
---------------------------------------------------------------------------
E. Pneumatic Pumps
A pneumatic pump is a positive displacement reciprocating unit
generally used by the Oil and Natural Gas Industry for one of four
purposes: (1) Hot oil circulation for heat tracing/freeze protection,
(2) chemical injection, (3) moving bulk liquids, and (4) glycol
circulation in dehydrators. There are two basic types of pneumatic
pumps used in the Oil and Natural Gas Industry--diaphragm pumps and
piston pumps. Natural gas-driven pneumatic pumps emit methane and VOCs
as part of their normal operation. Detailed information on pneumatic
pumps, including their functions, operations, and emissions, is
provided in the preamble for the November 2021 proposal (86 FR 63224-
63226; November 15, 2021).
1. NSPS OOOOb
a. November 2021 Proposal
In the November 2021 proposal, a pneumatic pump affected facility
was defined as each natural gas-driven diaphragm or piston pump in any
segment of the source category. The proposed definition of an affected
facility excluded lean glycol circulation pumps that rely on energy
exchange with the rich glycol from the contractor.
For pneumatic pumps in the production and transmission and storage
segments, the November 2021 proposal would have required that the
emissions be routed to an existing control device that achieves 95
percent control of methane and VOCs, or to route the emissions to an
existing VRU and to a process. This proposed standard would have
covered both diaphragm and piston pumps. The proposed rule did not
propose to require that a new control device be installed. At natural
gas processing plants, the proposed rule would have required the
prohibition of methane and VOC emissions from pneumatic pumps.
The BSER analysis that led to the November 2021 proposed pneumatic
pump requirements for the production
[[Page 74770]]
and transmission segments concluded that the cost effectiveness for
routing to an existing control device was reasonable. The EPA also
concluded that it was not cost-effective to require the owner or
operator of a pneumatic pump to install a new control device or process
onsite to capture emissions solely for this purpose.
The EPA also evaluated pneumatic pumps that are not powered by
natural gas. Specifically, the types of pumps evaluated were electric
pumps, solar-powered pumps, and pumps powered by compressed air. We
found that the cost-effectiveness of these options, for both diaphragm
and piston pumps, were generally within the ranges that the EPA
considers reasonable. However, for instrument air systems and electric
pumps, our analysis assumed that electrical power was available onsite.
We noted that commenters have raised concerns in the past regarding
solar-powered pneumatic pumps, which have technical limitations that do
not make them universally feasible for locations without access to
electrical power. In November 2021, we did not have information that
such limitations had been overcome, and we were therefore unable to
conclude that pumps not driven by natural gas represented BSER at that
time. We solicited comment on this issue to better understand whether
options that do not use natural gas are technically feasible at sites
without electrical power. We also solicited comment on an approach that
would subcategorize pneumatic pumps located at production and
transmission and storage sites based on availability of electricity and
would then set separate standards for each subcategory.
Since all natural gas processing plants have access to electrical
power, we only evaluated compressed air systems for this segment. The
cost effectiveness of these systems was found to be in the range
considered to be reasonable by the EPA, and we therefore concluded that
BSER was pneumatic pumps that are not driven by natural gas.
b. Changes to Proposal and Rationale
The proposed NSPS OOOOb requirements in this supplemental proposal
differ from the November 2021 proposal in several ways, starting with
the affected facility definition. As noted above, in the November 2021
proposal, a pneumatic pump affected facility was defined as each
natural gas-driven pneumatic pump. In this supplemental proposal, a
pneumatic pump affected facility is defined as the collection of all
natural gas-driven pneumatic pumps at a site.
After considering comments on the emissions standards, as well as
the information submitted in response to our specific solicitations for
information, the EPA is now proposing a zero-emissions standard for
pneumatic pump affected facilities in all segments of the industry.
Specifically, the EPA is proposing that pneumatic pumps not driven by
natural gas be used. This is a significant change from the November
2021 proposal, which would have required that emissions from pneumatic
pump affected facilities be routed to control or to a process, but only
if an existing control or process was on site.
The proposed rule recognizes that at sites without access to
electricity, there could be situations where it is technically
infeasible to use a pump that is not driven by natural gas. As a
result, the EPA is proposing to include a tiered structure in the rule
that would allow flexibility based on site-specific conditions. At
sites without access to electricity, if a demonstration is made that it
is technically infeasible to use a pneumatic pump that is not driven by
natural gas, the rule would allow the use of a natural gas-driven pump,
provided that the emissions are captured and routed to a process, which
EPA understands to achieve 100 percent reduction of methane and VOC.
Such an infeasibility determination is not allowed if the site has
access to electricity. This means the proposed rule would prohibit the
use of natural gas-driven pumps at sites with access to electricity.
At sites without access to electricity for which the owner or
operator has demonstrated that it is technically infeasible to utilize
a pneumatic pump not driven by natural gas, an owner or operator may
also demonstrate that it is technically infeasible to capture the
pneumatic pump's emissions and route them to a process. Where routing
to a process is infeasible, the resulting requirement for emissions
control depends on the number of natural gas-driven diaphragm pumps at
the site. If there are four or more natural gas-driven pumps at the
site, the proposed rule would require that the emissions from all pumps
at the site be collected and be routed to a control device that
achieves 95 percent reduction of methane and VOC. If there are less
than four natural gas-driven diaphragm pumps at the site without access
to electricity, the proposed requirements for pumps at the site would
be the same as in the November 2021 proposal, i.e., route to an
existing control device that achieves 95 percent emissions reductions.
Details on the proposed pneumatic pump requirements are provided in
section IV.D.1.c. The following sections provide the rationale for the
significant changes discussed in this section.
i. Changes to Affected Facility, Modification, and Reconstruction
As previously noted, the pneumatic pump affected facility
definition changed from being a single pump in the November 2021
proposal to the collection of pumps at a site in this supplemental
proposal. In this supplemental proposal, a pneumatic pump affected
facility is defined as the collection of all natural gas-driven
pneumatic pumps at a site. As we advanced our evaluation of the control
measures to reduce methane and VOC emissions from pneumatic pumps, it
became apparent that most of the measures to reduce or eliminate
emissions are site-wide solutions. For instance, a compressed air
system installed at a site would be used to power all pneumatic pumps
at the site, not just one, which would alleviate the need for a
separate system for each pump. In fact, the cost analysis for the
November 2021 proposed rule for compressed air systems was conducted on
a ``model plant'' site-wide basis. Similarly, emissions from all pumps
at a site would be routed to a single control device and would
therefore not require the installation of a control device for each
pump. We are specifically soliciting comment on this proposed change to
the definition of a pneumatic pump affected facility from an individual
pump to the collection of all natural gas-driven pneumatic pumps at a
site.
In addition, some of the means of powering a pneumatic pump without
the use of natural gas can also be used to power pneumatic controllers.
While our updated BSER analyses for pneumatic pumps and pneumatic
controllers evaluated the cost effectiveness of these sources
independently, the shared usage of solutions for the two sources, such
as compressed air systems, solar-powered systems, or generators, will
result in even lower overall site-wide cost effectiveness values.
Under the previous approach in which EPA assessed each pump on an
individual basis, the installation or replacement of a pneumatic pump
would have resulted in the pump being a new source and an affected
facility subject to NSPS OOOOb. In 40 CFR 60.14(a), modification is
defined as ``any physical or operational change to an existing facility
which results in an increase in the emission rate to the atmosphere of
any pollutant.'' In order to clarify what constitutes a
[[Page 74771]]
modification for the collection of all pneumatic pumps at a site, the
supplemental proposed rule specifies that if one or more pneumatic
pumps is added to the site such that the total number of pumps
increases, such addition constitutes a modification because it
represents a physical change that results in an increase in emissions.
Therefore, the collection of pneumatic pumps at the site would become a
pneumatic pump affected facility. The EPA believes that owners and
operators will implement zero-emission pumps across a site when a
modification occurs because converting a single zero-emitting device
typically requires a conversion of all devices at the facility. The EPA
solicits comment on the ways in which a modification to a pneumatic
pump affected facility would occur in light of the affected facility
definition proposed herein, which includes the collection of all
natural gas-driven pneumatic pumps at a site.
Analogous to the discussion above regarding reconstruction for
pneumatic controllers in section IV.D.1.b.i, the definition of the
pneumatic pump affected facility is the collection of natural gas-
driven pneumatic pumps at a site. As with pneumatic controllers, the
cost that would be required to construct a ``comparable entirely new
facility'' under 40 CFR 60.15(b)(1) would be the cost of replacing all
existing pumps with new pumps. Because individual pumps are likely to
have comparable replacement costs, it is reasonable to assume that
there would be a one-to-one correlation between the percentage of pumps
being replaced at a site and the percentage of the fixed capital cost
that would be required to construct a comparable entirely new facility.
Accordingly, we are proposing to include a second, simplified
method of determining whether a pump replacement project constitutes
reconstruction under 40 CFR 60.15(b)(1) whereby reconstruction may be
considered to occur whenever greater than 50 of the number of existing
onsite pumps are replaced.\159\ As with controllers, the EPA believes
that allowing owners or operators to determine reconstruction by
counting the number of pumps replaced is a more straightforward option
than requiring owners and operators to provide cost estimate
information. By providing this option, the EPA intends to reduce the
administrative burden on owners and operators, as well as on the
implementing agency reviewing the information. Owners and operators
would be able to choose whether to use the cost-based criterion or the
proposed number-of-pumps criterion. No matter which option an owner or
operators chooses to use, the remaining provisions of 40 CFR 60.15
apply--namely, 40 CFR 60.15(a), the technological and economical
provision of 40 CFR 60.15(b)(2), and the requirements for notification
to the Administrator and a determination by the Administrator in 40 CFR
60.15(d), (e) and (f). The EPA is proposing that the standard in 40 CFR
60.15(b)(1) specifying that the ``fixed capital cost of the new
components exceeds 50 percent of the fixed capital cost that would be
required to construct a comparable entirely new facility'' can be met
through a showing that 50 percent or more of the number of existing
onsite pumps are replaced. Therefore, upon such a showing, an owner or
operator may demonstrate compliance with the remaining provisions of 40
CFR 60.15 that reference the ``fixed capital cost'' criterion.
---------------------------------------------------------------------------
\159\ Adding this method of determining ``reconstruction'' for
pneumatic pumps is in accordance with 40 CFR 60.15(g), which states
that ``[i]ndividual subparts of this part [``Reconstruction''] may
include specific provisions which refine and delimit the concept of
reconstruction set forth in this section.''
---------------------------------------------------------------------------
The same logic and rationale discussed above in section IV.D.1.b.i
for applying a 2-year rolling aggregation period for controller
replacements also applies for pneumatic pumps. Therefore, we are
proposing the same 2-year rolling period as the appropriate aggregation
period to define a proposed replacement program time frame. Thus, the
EPA proposes to count toward the greater than 50 percent reconstruction
threshold all pumps replaced pursuant to all continuous programs of
reconstruction which commence (but are not necessarily completed)
within any 2-year rolling period following proposal of these standards.
In the Administrator's judgment, the 2-year rolling period provides a
reasonable method of determining whether an owner of an oil and natural
gas site with pneumatic pumps is actually proposing extensive
controller replacement, within the EPA's original intent in
promulgating 40 CFR 60.15. As explained in greater detail in section
IV.D.1.b.i, the EPA is soliciting comment on several aspects of the
proposed reconstruction definition for pneumatic pumps and pneumatic
controllers and refers commenters to that section for a description of
the specific information requested.
The following scenarios are examples of the application of these
proposed requirements for a site with access to electricity that has
four natural gas-driven pneumatic pumps. Scenario 1--One of the four
pumps is replaced at any given time. The collection of pumps at the
site would not be a pneumatic pump affected facility as this action is
not a modification or reconstruction. Scenario 2--Three of the four
pumps are replaced at the same time. This would constitute
reconstruction (replacement of greater than 50 percent of the pumps),
so the four pumps (i.e., the ``collection'' of pumps at the site) would
be a pneumatic pump affected facility. This affected facility would
then be subject to the zero emissions standard, meaning that all pumps
at the site, including the three new pumps and the one existing pump,
cannot be driven by natural gas. Under Scenario 2, the one existing
pump would need to be replaced or converted so that it is not powered
by natural gas. Scenario 3--one pneumatic pump is replaced in February
and two more are replaced in December of the same year. This would
represent reconstruction (because more than 50 percent of the total
number of pumps are being replaced over a 2-year period), so the four
pumps (i.e., the ``collection'' of pumps at the site) would be a
pneumatic pump affected facility at the time the two pumps were
replaced in December. This affected facility would then be subject to
the zero-emissions standard, meaning that all four pumps would not be
allowed to be driven by natural gas. Scenario 4--An additional
pneumatic pump is added at any given time. This addition would
represent a modification since it represents a physical change and
would result in an increase in emissions. The five pumps would be a
pneumatic pump affected facility and all five pumps would need to be
powered in a manner other than natural gas.
ii. Changes to the Standard
As discussed above, we solicited comment in the November 2021
proposal on two key issues related to the proposed standard and BSER
determination. These were: (1) An approach that would involve
subcategorizing pneumatic pumps located at production and transmission
and storage segments based on availability of electricity, and then
developing separate standards for each subcategory, and (2) the
technical feasibility of using pneumatic pumps not powered by natural
gas at sites without electrical power.
Regarding the first issue, several commenters supported the
approach of subcategorizing based on access to electrical power, and
then determining BSER for pneumatic pumps separately for sites with and
without access to
[[Page 74772]]
electrical power. One of these commenters noted that the availability
of electricity is a significant and constraining factor that is within
the EPA's authority to consider in subcategorization.\160\
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\160\ See Document ID No. EPA-HQ-OAR-2021-0317-0938.
---------------------------------------------------------------------------
The comments were mixed concerning the feasibility of options that
do not use natural gas-driven pneumatic pumps at remote sites without
access to electrical power. Several commenters maintain that zero-
emission pneumatic pumps are technically infeasible at sites without
electricity. For example, one commenter who voiced support for the use
of non-natural gas driven pumps as an option at sites where it is
technically feasible indicated that requiring these pumps at many of
their remote sites would be ``burdensome at best and would force site
shutdown in many cases.'' \161\ Another commenter stated that onsite
solar generation paired with battery storage as an alternative to grid
electricity systems are currently uncommon and unreliable. According to
the commenter, use of these systems would likely increase the frequency
of facility upsets, which would increase safety risks such as
overpressure events and spills. The commenter concluded that onsite
solar should therefore not be deemed an available technology.\162\
Other commenters provided specific examples of where pneumatic pumps
not driven by natural gas, particularly solar-powered pumps, would
likely not be technically feasible. Examples of the situations cited
included locations with very cold temperatures, extended periods of
cloud cover, and heavy snow load.
---------------------------------------------------------------------------
\161\ See Document ID No. EPA-HQ-OAR-2021-0317-0463.
\162\ See Document ID No. EPA-HQ-OAR-2021-0317-0793.
---------------------------------------------------------------------------
However, many commenters reported that options that do not use
natural gas-driven pneumatic pumps are available at sites without
access to grid electricity systems, and that their use has been
demonstrated. One of these commenters noted that in addition to solar-
powered pumps, thermal electric generators or methanol fuel cells have
been used to increase power at sites with high demand.\163\ Another
commenter is aware of retrofits at remote locations that have no
electrical power in which natural gas is used to generate electricity
to run pumps directly or to power air compressors that drive pneumatic
pumps.\164\ The EPA is requesting information regarding the
characteristics of sites where thermal electric generators, methanol
fuel cells, or other means to boost power for solar driven pneumatic
pumps are needed. The EPA is also interested in costs for those
systems.
---------------------------------------------------------------------------
\163\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
\164\ See Document ID No. EPA-HQ-OAR-2021-0317-0765.
---------------------------------------------------------------------------
Two commenters, who are also equipment vendors, confirmed the
successful implementation of technologies to utilize pneumatic pumps
not driven by natural gas at remote locations without the access to the
grid. One has deployed solar-driven pneumatic pumps and air compressors
in many states throughout the southwestern and northwestern U.S.,
including a remote location in Wyoming that experienced temperatures
down to minus 11 degrees Centigrade ([deg]C).\165\ The second vendor
reported that their standalone power generators have been deployed at a
number of sites across the country to power pneumatic pumps.\166\
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\165\ See Document ID No. EPA-HQ-OAR-2021-0317-0838.
\166\ See Document ID No. EPA-HQ-OAR-2021-0317-0823.
---------------------------------------------------------------------------
In our analysis for the November 2021 proposal, we evaluated the
costs and impacts of electric pumps run from the grid, solar-powered
pumps, and compressed air systems to power the pumps. No significant
comments were received on this 2021 analysis; therefore, the essential
elements of the analysis and results remain the same.
Baseline Emissions. The baseline emission estimates were calculated
assuming a bleed rate of 2.48 scfh for natural gas-driven piston pumps
and 22.45 scfh for natural gas-driven diaphragm pumps. Based on these
natural gas bleed rates, assuming that natural gas bleeds from the pump
for 8,760 hours per year and using the segment-specific gas
compositions developed during the 2012 NSPS, the baseline emissions
were estimated as provided in Table 21. More information on these
calculations is provided in the Technical Support Document for this
rulemaking.
The baseline emission analysis was conducted for six representative
sites: (1) A single diaphragm pump, (2) a single piston pump, (3) one
diaphragm pump and one piston pump, (4) two diaphragm pumps and two
piston pumps, (5) 10 diaphragm pumps and 10 piston pumps, and (6) 50
diaphragm pumps and 50 piston pumps. All representative sites were not
evaluated for all three sectors, as it is not expected that they would
be applicable. Specifically, the two largest sites with 10 and 100
total pumps were not evaluated for the production and transmission and
storage segments. For the processing plant segment, since it is
expected that multiple pumps would be at each site, only representative
sites 4, 5, and 6 were evaluated. The following table provides the
baseline emissions for each type of representative facility.
Table 29--Baseline Pneumatic Pump Emissions (Tons per Year) for Representative Sites
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
# of Pumps Production Processing Transmission/storage
Rep Site # -------------------------------------------------------------------------------------------------------------------------------
Diaphragm Piston Methane VOC Methane VOC Methane VOC
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1............................................................... 1 0 3.46 0.96 n/a 4.5 0.125
2............................................................... 0 1 0.38 0.11 n/a 0.50 0.014
3............................................................... 1 1 3.84 1.07 n/a 5.0 0.14
--------------------------------
4............................................................... 2 2 7.68 2.14 7.68 2.14 10.0 0.28
-------------------------------- -------------------------------
5............................................................... 10 10 n/a 38.4 10.7 n/a
6............................................................... 50 50 n/a 192.0 53.4 n/a
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Cost Analysis for Options That Do Not Use Natural Gas-Driven
Pneumatic Pumps. The EPA evaluated the following pump options that do
not use natural gas: electric pumps, solar-powered pumps, and
instrument air systems that produce compressed air to power the pumps.
All three options were evaluated for pneumatic pumps in the production
and transmission and storage segments. For the processing segment, only
instrument air systems
[[Page 74773]]
were evaluated because it is expected that all processing plants have
access to electrical power and have multiple pumps at the site.
The following paragraphs provide the estimated costs for electric
pumps, solar-powered pumps, and instrument air systems. The EPA is not
aware of differences between the oil and natural gas industry segments
that would result in the different costs for these options between
segments. These paragraphs provide capital costs and total annual
costs. For all of these options, the capital recovery cost component of
the annual cost is based on a 7 percent interest rate and an equipment
life of 10 years.
The capital and installation cost of an electric pump using
electricity from the grid is estimated to be $5,219. The total annual
costs, including capital recovery and an estimated operation and
maintenance cost of $329 per year, yields a total annual cost per
electric pump of $1,072.
For solar-powered pumps, the estimated capital cost, including
installation, is $2,501 per pump. It is assumed that the annual
operation and maintenance is no greater than a natural gas-driven pump,
so the total annual cost is the capital cost of $356 per year.
For electric pumps and solar-powered pumps, the cost information is
assessed on an individual pump basis. While it is expected that the
cost per pump would be less where there are more pumps on site, we do
not have information on these cost advantages. Therefore, our estimate
of the site-wide costs and emission reductions would simply be the
multiple of our per pump costs and emission reductions multiplied by
the number of pumps at the site. Thus, the cost effectiveness for
representative sites 3 and 4 is the same. The EPA is requesting
information on the costs of site-wide electric and solar-powered pump
solutions.
Instrument air system costs were estimated for small, medium, and
large compressors. The small compressor was assumed to have an air
capacity of 135 scfh, while the medium and large had capacities of 562
and 1,350 scfh, respectively. The estimated capital (including
installation) costs for these three sizes of instrument air systems are
$6,742 for the small system, $33,699 for the medium system, and $59,308
for the large system. The estimated annual costs, including capital
recovery, labor for operation and maintenance, and electricity, are
$11,295 for the small system, $36,264 for the medium system, and
$81,350 for the large system. In the estimation of impacts for the
representative sites described above, the small system costs were used
for representative sites 1, 2, 3, and 4; the medium system for
representative site 5; and the large system for representative site 6.
Since all of these options do not use natural gas to drive the
pneumatic pump, their use results in a 100 percent reduction in methane
and VOC emissions from the baseline levels shown in Table 21 above.
Using the annual total annual costs and these emission reductions, we
calculated the cost effectiveness for each zero-emission option for
each representative site. Cost effectiveness was calculated on a single
pollutant basis, where the total annual cost was applied entirely to
the reduction of each pollutant. Cost effectiveness was also calculated
on a multi-pollutant basis, where half the cost of control is assigned
to the methane reduction and half to the VOC reduction.
The estimated cost effectiveness values for the options that do not
use natural gas-driven pneumatic pumps are provided in Table 30. In
addition to the cost effectiveness values, Table 30 provides a
conclusion as to whether the estimated cost effectiveness value is
within the range that the EPA has typically considered to be
reasonable. The ``overall'' reasonableness determination is classified
as ``yes'' if the cost effectiveness of either methane or VOC is within
the range that the EPA considers reasonable for that pollutant, or if
both the methane and VOC cost effectiveness values are without the
range that the EPA considers reasonable on a multipollutant basis.
Table 30--Summary of Cost Effectiveness for Pneumatic Pump Options That Do Not Use Pumps Driven by Natural Gas
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost Effectiveness ($/ton) \a\--Reasonable?
----------------------------------------------------------------------------------------------
Segment Option-- Representative Single pollutant Multipollutant Overall \a\
Site ----------------------------------------------------------------------------------------------
Methane VOC Methane VOC
--------------------------------------------------------------------------------------------------------------------------------------------------------
Production Segment:
Electric Pumps--Single $310-Y................ $1,115-Y.............. $115-Y............... $557-Y............... Y
Diaphragm.
Electric Pumps--Single Piston.. 1,632-Y............... 5,869-Y............... 816-Y................ 2,934-Y.............. Y
Electric Pumps--Multiple 441-Y................. 1,585-Y............... 220-Y................ 793-Y................ Y
Pumps\b\.
Solar Pumps--Single Diaphragm.. 103-Y................. 370-Y................. 51-Y................. 185-Y................ Y
Solar Pumps--Single Piston..... 937-Y................. 3,371-Y............... 469-Y................ 1,686-Y.............. Y
Solar Pumps--Multiple Pumps\b\. 185-Y................. 667-Y................. 93-Y................. 334-Y................ Y
Instrument Air--Single 3,264-N............... 11,743-N.............. 1,632-Y.............. 5,871-Y.............. Y
Diaphragm.
Instrument Air--Single Piston.. 29,724-N.............. 106,921-N............. 14,682-N............. 53,461-N............. N
Instrument Air--1 Diaphragm/1 2,941-N............... 10,581-N.............. 1,471-Y.............. 5,290-Y.............. Y
Piston.
Instrument Air--2 Diaphragm/2 1,471-Y............... 5,290-Y............... 735-Y................ 2,645-Y.............. Y
Piston.
[[Page 74774]]
Processing Segment:
Instrument Air--2 Diaphragm/2 1,471-Y............... 5,290-Y............... 735-Y................ 2,645-Y.............. Y
Piston.
Instrument Air--10 Diaphragm/10 944-Y................. 3,397-Y............... 472-Y................ 1,699-Y.............. Y
Piston.
Instrument Air--50 Diaphragm/50 424-Y................. 1,524-Y............... 212-Y................ 762-Y................ Y
Piston.
Transmission and Storage Segment:
Electric Pumps--Single 237-Y................. 8,563-N............... 119-Y................ 4,281-Y.............. Y
Diaphragm.
Electric Pumps--Single Piston.. 1,249-Y............... 45,083-N.............. 624-Y................ 22,541-N............. Y
Electric Pumps--Multiple Pumps 337-Y................. 12,177-N.............. 169-Y................ 6,088-N.............. Y
\b\.
Solar Pumps--Single Diaphragm.. 79-Y.................. 2,844-Y............... 39-Y................. 1,422-Y.............. Y
Solar Pumps--Single Piston..... 717-Y................. 25,897-N.............. 359-Y................ 12,948-N............. Y
Solar Pumps--Multiple Pumps\b\. 142-Y................. 5,125-Y............... 71-Y................. 2,563-Y.............. Y
Instrument Air--Single 2,499-N............... 90,206-N.............. 1,249-N.............. 45,103--N............ N
Diaphragm.
Instrument Air--Single Piston.. 22,751-N.............. 821,348-N............. 11,376-N............. 410,674-N............ N
Instrument Air--1 Diaphragm/1 2,251-N............... 81,279-N.............. 1,126-Y.............. 40,640-N............. N
Piston.
Instrument Air--2 Diaphragm/2 1,126-Y............... 40,640-N.............. 563-Y................ 20,320-N............. Y
Piston.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ For the production and processing segments, the owners and operators realize the savings for the natural gas that was not emitted and lost. The cost
effectiveness values shown do not consider these savings. Note that the consideration of savings does not impact whether the cost effectiveness of any
of these options falls within the ranges considered reasonable by the EPA.
\b\ For overall cost effectiveness to be considered reasonable, either the cost effectiveness of methane or VOC on a single pollutant basis must be
within the ranges considered reasonable by the EPA, or the cost effectiveness of both methane and VOC on a multipollutant basis must be within the
ranges considered reasonable by the EPA.
\c\ For multiple pump scenarios, an equal number of diaphragm and piston pumps is assumed.
While the costs for electric pumps and instrument air systems
assume access to electrical power (that is, access to the grid), solar-
powered pumps can be utilized at many remote sites that do not have
access to electrical power. Instrument air systems can also be utilized
at sites without access to the electricity grid but would require the
installation and operation of a generator. These generators could be
powered by engines fueled by solar energy, natural gas, or diesel.
While such systems are technically a viable option at these remote
sites, we did not have detailed cost information available to include
these systems in our analysis. One commenter provided estimated costs
ranging from $60,000 to over $200,000 for an instrument air system
driven by a natural gas generator.\167\ The commenter also provided an
estimate of $250,000 for an instrument air system powered by solar
energy. However, the focus of the comments and these cost estimates was
pneumatic controllers, not pumps. The EPA is specifically requesting
information on whether these costs are representative of systems that
could be used to power compressed air-driven pneumatic pumps, as well
as comments on whether a single generator or solar system could be used
to power both pneumatic controllers and pneumatic pumps.
---------------------------------------------------------------------------
\167\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
---------------------------------------------------------------------------
Proposed BSER Conclusion. As demonstrated in the analysis, there
are pneumatic pump options that do not use natural gas for which the
cost effectiveness is within the ranges considered to be reasonable by
the EPA. These types of pumps can be utilized at sites with access to
grid electricity as well as at remote sites that do not have this
access.
This BSER conclusion is consistent with the EPA's findings in 2021.
However, at that time we were unable to conclude that pumps that do not
use natural gas represented BSER due to our inability to conclude that
technical limitations previously identified had been overcome. As
summarized above, several commenters continue to
[[Page 74775]]
maintain that there are significant technical limitations, particularly
with solar-powered pneumatic pumps. However, other commenters provided
evidence that pneumatic pumps not driven by natural gas are available
and in use in the industry.
Under CAA Section 111(b), the EPA must determine that the BSER has
been ``adequately demonstrated.'' The EPA concludes that pneumatic pump
systems that do not use natural gas have met this standard at sites
both with and without access to grid electricity. In addition, as
discussed above, we have concluded that there are system options
available at sites in all segments of the industry that have cost
effective values considered reasonable by the EPA.
Secondary impacts from these non-natural gas-driven pumps,
particularly from the use of instrument air systems, are indirect,
variable, and dependent on the electrical supply used to power the
compressor. The secondary impacts resulting from the increase in
electricity needed from the grid to power compressors for instrument
air were discussed above for pneumatic controllers. These also
represent the impacts that would occur for compressors used to provide
instrument air for pneumatic pumps. However, a single compression
system, appropriately sized, could power both pneumatic controllers and
pumps at a site, meaning that the electricity usage and resulting
secondary impacts would not necessarily be doubled. No other secondary
impacts are expected.
In light of the above, we find that the BSER for reducing methane
and VOC emissions from natural gas-driven piston and diaphragm pumps at
all segments of the industry is the use of pneumatic pumps that do not
use natural gas as a driver. This option results in a 100 percent
reduction of direct emissions for both methane and VOC, or zero methane
and VOC emissions. Therefore, for NSPS OOOOb, we are proposing to
require a natural gas emission rate of zero for all pneumatic pumps in
the source category.
One request for comments that the EPA solicited in November 2021
was related to the potential subcategorization of pumps based on access
to grid electrical power. Because we have determined that the
requirement to use zero-emission pumps that are not powered by natural
gas is BSER for all sites, regardless of whether the site has access to
electrical power, we have decided that subcategorization is not
necessary.
Technical Infeasibility Situations. While we conclude that zero-
emission pneumatic pumps not powered by natural gas are adequately
demonstrated as BSER, we understand that there may be specific
conditions at sites without access to electricity that result in
situations where it may be technically infeasible to utilize a non-
natural gas-driven pump. Therefore, we also analyzed alternatives that
could be incorporated into NSPS OOOOb in these instances. Note that
because we have concluded that it should always be technically feasible
for sites with access to electricity to utilize zero-emission pneumatic
pumps that are not driven by natural gas, these alternatives would only
be available at sites that do not have access to electricity.
First, we analyzed capturing the natural gas emissions from the
pneumatic pump through venting and routing them to an existing process.
The costs associated with this option are a capital cost of $6,102 with
an annual cost of $869 (capital recovery using 7 percent interest for
10 years). The cost effectiveness for a single diaphragm pump in the
production segment, assuming 100 percent capture, was $251 per ton of
methane removed ($79 per ton with savings) and $903 per ton of VOC
removed ($284 per ton with savings). On a multipollutant basis, these
cost effectiveness values were $126 per ton of methane ($39 per ton
with savings) and $452 per ton of VOC ($142 per ton with savings). For
a single piston pump, the cost effectiveness was $2,286 per ton of
methane removed ($2,114 with savings) and $8,224 per ton of VOC ($7,604
with savings). On a multipollutant basis, these cost effectiveness
values were $1,143 per ton of methane ($1,057 per ton with savings) and
$4,112 per ton of VOC ($3,802 per ton with savings).
For the representative site 3 (with one diaphragm piston and one
piston pump), the single pollutant cost effectiveness values were $226
per ton of methane reduction ($54 with savings) and $814 per ton of VOC
reduction ($194 with savings). The multipollutant cost effectiveness
values were $113 per ton of methane reduction ($27 with savings) and
$407 per ton of VOC reduction ($97 with savings).
All of these cost effectiveness values for both methane and VOC are
within the ranges considered reasonable by the EPA, with the exception
of the single pollutant cost effectiveness values for methane and VOC
for a piston pump. However, since the multipollutant cost effectiveness
of both methane and VOC were in the range considered acceptable by the
EPA for a site with a single piston pump, we determined that this is an
acceptable option.
For the transmission and storage segment, the cost effectiveness
for a single diaphragm pump was $192 per ton of methane removed and
$40,640 per ton of VOC. On a multipollutant basis, these cost
effectiveness values were $96 per ton of methane and $20,320 per ton of
VOC. For a single piston pump, the cost effectiveness was $1,750 per
ton of methane removed and $26,095 per ton of VOC. On a multipollutant
basis, these cost effectiveness values were $875 per ton of methane and
$13,048 per ton of VOC. For the representative site with one diaphragm
piston and one piston pump, the single pollutant cost effective values
were $173 per ton of methane reduction and $11,708 per ton of VOC
reduction, and the multipollutant cost effectiveness values were $87
per ton of methane reduction and $5,854 per ton of VOC reduction.
All of the cost effectiveness values for methane on a single
pollutant basis are within the ranges considered reasonable by the EPA.
In addition, the multipollutant cost effectiveness for both methane and
VOC were in the ranges considered reasonable by the EPA for a site with
one diaphragm and one piston pump.
In conclusion, because we believe that routing to a process is a
viable and cost-effective option for pneumatic pumps when it is
technically infeasible to use a zero-emission pneumatic pump not driven
by natural gas, this option is included in the proposed NSPS OOOOb. In
order to utilize this option, an owner or operator must demonstrate
technical infeasibility. In addition, because the CVS system that
collects and routes these emissions to a process could develop leaks,
the proposed NSPS OOOOb requires compliance with the CVS no-detectable
leaks requirements specified in 40 CFR 60.5411b(a) and (c) of the
proposed regulatory text.
The EPA is interested in several aspects related to the option of
collecting the pneumatic pump emissions and routing them to a process.
First, we are soliciting information that describes specific situations
where owners and operators have utilized this option to use, rather
than lose, the valuable natural gas emitted from pneumatic pumps. We
are interested in gathering information on the specific processes and
types of equipment that are needed to do so, as well as information on
the related costs. We are also interested in information to support our
understanding that routing to a process achieves a 100 percent
reduction in emissions. This understanding is based on the fact that
the gas that is emitted from pneumatic
[[Page 74776]]
pumps is drawn directly from the raw product gas stream that will be
collected and routed to a gathering and boosting station and eventually
to a natural gas processing plant (i.e., the gas ``sales line'').
Therefore, the emissions from the pneumatic pumps are of the same
composition as the gas in the sales line. Since the emissions are at
atmospheric pressure, it is likely that the gas would need to be
compressed prior to re-introduction to the sales line. We do not expect
that this compression would result in emissions. Similarly, since the
composition of these emissions is typically high in methane, the heat
content would make it amendable to being used as fuel, or introduced
with the primary fuel stream for use in an engine without the need for
additional processing that could result in emissions.
This request for information includes information on the
installation of VRUs. Note that the analysis above did not include the
installation of a new VRU. As discussed in section IV.D.1.b.iii for
pneumatic controllers, we do not believe that a VRU would be needed to
enable the use of the emissions from pneumatic pumps (in contrast to
emissions from storage vessels and centrifugal compressor wet seal
fluid degassing systems). Despite this belief, in the analysis for the
November 2021 proposal, we did analyze the costs to install a new VRU
to process the emissions from pneumatic pumps to enable the routing to
a process. We determined that these costs were unreasonable, given the
emission reductions. One commenter felt that our VRU costs were
inflated. We are interested in learning about situations where a VRU
would be needed to enable the use of emissions from a pneumatic pump in
a process, as well as the costs of those VRUs.\168\ These costs are
included in the November 2021 TSD.
---------------------------------------------------------------------------
\168\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
---------------------------------------------------------------------------
We also recognize that there could be situations at sites without
access to electricity where not only is it technically infeasible to
utilize zero-emission pneumatic pumps that are not driven by natural
gas, but it is also technically infeasible to route the emissions to a
process. Therefore, we also considered the option to route to a control
device. The analysis conducted for the November 2021 proposal concluded
that while it was reasonable to route the emissions from a pneumatic
pump to an existing control device, the cost effectiveness of
installing a new control device dedicated to the pneumatic pump was
higher than the EPA considers reasonable. This finding is still valid
for this proposal for sites with a single pneumatic pump. However, as
noted above, the EPA changed the pneumatic pump affected facility
definition for this proposal to be the collection of natural gas
pneumatic pumps at a site. Therefore, we updated the analysis to
consider the cost effectiveness of installation of a new control device
that would control emissions from multiple natural gas-driven pneumatic
pumps.
This analysis found that where there are four or more natural gas-
driven pneumatic diaphragm pumps at a site, the cost effectiveness of a
new combustion device that reduces emissions by 95 percent from all the
pumps is within the ranges considered reasonable by the EPA. For the
production segment, the cost effectiveness values for a site with four
diaphragm pumps are $1,869 per ton of methane reduced and $6,723 per
ton of VOC reduced on a single pollutant basis. On a multipollutant
basis, these values are $934 per ton of methane and $3,361 per ton of
VOC. Therefore, these cost effectiveness values are considered
reasonable for methane on a single pollutant basis as well as on a
multipollutant basis. For the transmission and storage segment, the
single pollutant methane cost effectiveness was $1,430, which is in the
range considered reasonable by the EPA.
Therefore, the proposed NSPS OOOOb includes the requirement for
production and transmission and storage sites as follows: if an owner
or operator demonstrates that it is technically infeasible to install
zero-emission non-natural gas-driven pumps, and it is technically
infeasible to route to a process, the emissions must be routed to a
control device to achieve 95 percent reduction of the methane and VOC
if the pneumatic pump affected facility includes four or more diaphragm
pumps. Note that emissions from all piston pumps at the site would also
be required to be reduced by 95 percent. For pneumatic pump affected
facilities with less than four diaphragm pumps, where it has been
demonstrated that it is technically infeasible to use zero-emission
non-natural gas-driven pumps and infeasible to route to a process, the
proposed NSPS OOOOb mirrors the November 2021 proposal. That is, the
pneumatic pump emissions must be routed to an existing control device
(if one is available) to achieve 95 percent reduction.
There are several instances in this hierarchical structure of the
proposed NSPS OOOOb where less stringent requirements may apply if it
is determined that the more stringent requirement is technically
infeasible. The proposed rule requires that these demonstrations be
made by a qualified professional engineer or an in-house engineer with
relevant expertise. While several commenters stressed that in-house
engineers should be allowed to make required certifications and
determinations, other commenters expressed concerns that only certified
professional engineers should be allowed to certify technical
infeasibility. The EPA concluded that the flexibility to allow in-house
engineers to make these determinations and certifications is warranted,
especially given the potential shortage of professional engineers with
specific expertise required for these determinations (that is,
expertise in solar-powered pneumatic pumps or routing pneumatic pump
emissions to a process).
However, the EPA is also committed to ensuring that this technical
infeasibility provision is not abused or used as a loophole to avoid
implementing important pollution reduction measures. The EPA stresses
that each technical infeasibility determination must be documented, and
the following statement submitted to the EPA (or delegated enforcement
authority): ``I certify that the assessment of technical infeasibility
was prepared under my direction or supervision. I further certify that
the assessment was conducted, and this report was prepared, pursuant to
the requirements of 40 CFR 60.5393b(c)(1). Based on my professional
knowledge and experience, and inquiry of personnel involved in the
assessment, the certification submitted herein is true, accurate, and
complete.'' The EPA wants to make it clear that in the case that such a
certification is determined by the Agency to be fraudulent, or
significantly flawed, not only will the owner or operator of the
affected facility be in violation of the standards, but the person that
makes the certification will also be subject to civil and potentially
criminal penalties.
c. Summary of Proposed NSPS OOOOb
The proposed NSPS OOOOb defines a pneumatic pump affected facility
as the collection of natural gas-driven diaphragm and piston pneumatic
pumps at all types of sites throughout the production, processing, and
transmission and storage segments of the source category. Specifically,
these sites include well sites, centralized production facilities,
onshore natural gas processing plants, and compressor stations.
Pneumatic pumps that are not driven by natural gas are not included
[[Page 74777]]
in the proposed pneumatic pump affected facility as long as records are
maintained to verify that non-natural gas-driven pumps are used.
Natural gas-driven pumps that are in operation less than 90 days
per calendar year are not part of an affected facility provided that
the owner or operator keeps records of the days of operation each
calendar year and submits such records to the EPA (or delegated
enforcement authority) upon request. Any period of operation during a
calendar day counts toward the 90-calendar day threshold.
In addition to the modification definition in 40 CFR 60.14 and the
reconstruction definition in 40 CFR 60.15, the proposed rule includes
clarification of these terms for the pneumatic pump affected facility.
A modification occurs when the number of natural gas-driven pneumatic
pumps at a site is increased by one or more, and reconstruction occurs
when either the cost of the pumps being replaced exceeds 50 percent of
the cost to replace all the pumps, or when 50 percent or more of the
pneumatic pumps at a site are replaced.
The proposed BSER is the use of pneumatic pumps not powered by
natural gas; the proposed standard of performance is zero emissions of
methane and VOC. As noted above, compliance with this standard
effectively eliminates the existence of a pneumatic pump affected
facility (which is a natural gas-driven pump or collection of pumps, by
definition). For sites in the production or transmission and storage
segment of the industry who do not have access to electricity, the
proposed standards include a hierarchical structure that allows the use
of natural gas-driven pneumatic pumps based on the technical
feasibility of pneumatic pump control measures. This hierarchy is not
available to natural gas processing plants, as the only proposed
requirement is the use of non-natural gas-driven pneumatic pumps at
these sites.
If it is demonstrated that it is technically infeasible to utilize
a pneumatic pump not driven by natural gas at a site in the production
or transmission and storage segment of the industry which does not have
access to electricity, compliance may be achieved by collecting methane
and VOC emissions from all pumps (diaphragm and piston pumps) in the
affected facility via a CVS and routed to a process, which we
understand results in 100 percent emissions reductions. The CVS is
required to comply with the CVS requirements specified in 40 CFR
60.5411b(a) and (c) of the proposed regulatory text, which includes
certification by a professional or in-house engineer that the CVS was
designed properly and was operated in accordance with the no detectable
emissions provisions. For this ``tier one'' technical infeasibility
determination, a demonstration must be made that using a solar-powered
electric pneumatic pump is not technically feasible. This demonstration
must be certified by either a qualified professional engineer or an in-
house engineer with expertise on the design and operation of solar-
powered pneumatic pumps. Alternatively, this demonstration can be
certified by a solar-powered pneumatic pump manufacturer that has
successfully installed solar-powered pneumatic pumps at other oil and
natural gas sites. In addition, the tier one technical infeasibility
demonstration must prove that it is not technically feasible to install
a compressed air system powered by either a natural gas-driven
generator or a solar-powered generator. This demonstration must
include, but not be limited to, the ability to operate a generator,
including access to natural gas; access to solar power; or the
inability of a compressed air system to power the pneumatic pump. This
demonstration must be certified by either a qualified professional
engineer or an in-house engineer with expertise on the design and
operation of natural gas-driven or solar-powered generators to power
pneumatic pumps. In addition to the records associated with the
technical infeasibility determination/certification, a record of the
certification of the design of the CVS must be maintained, along with
records of all inspections required to demonstrate compliance with the
no detectable emissions requirements.
If it is demonstrated that it is technically infeasible to collect
the emissions from all pneumatic pumps in the affected facility and
route them to a process (in addition to the demonstration that it is
infeasible to utilize a pneumatic pump not driven by natural gas),
compliance may be achieved by collecting methane and VOC emissions from
all pumps (diaphragm and piston pumps) in the affected facility via a
CVS and routing them to a control device that achieves 95 percent
reduction in methane and VOC emissions. The CVS would be subject to the
design requirements, specified in 40 CFR 60.5411b(a) and (c) of the
proposed regulatory text, and must comply with the no detectable
emissions requirements. The control device would be subject to testing
and continuous monitoring requirements. This ``tier two'' demonstration
must include, but is not limited to, safety considerations, distance
from a process, pressure losses and differentials which impact the
ability of the process to handle all the pneumatic pump affected
facility emissions routed to it, or other technical reasons the process
cannot handle all the pneumatic pump affected facility emissions routed
to it. This demonstration must be certified by either a qualified
professional engineer or an in-house engineer with expertise on the
design and operation of the pneumatic pump affected facility and the
process to which emissions will be routed. A demonstration of technical
infeasibility may not be based on the infeasibility of the design and
operation of CVS to collect emissions from all the pneumatic pumps in
the affected facility. In addition to the records associated with both
technical infeasibility determinations and certifications, a record of
the certification of the design of the CVS must be maintained, along
with records of all inspections required to demonstrate compliance with
the no detectable emissions requirements. Records must also be
maintained of either the performance testing of the control device
(whether at the site or by the manufacturer), or records demonstrating
compliance with 40 CFR 60.18 General Provisions flare requirements.
Finally, monitoring records must be maintained to demonstrate that the
control device is operating properly on a continuous basis.
``Tier three'' of the hierarchy applies if there are less than four
natural gas-driven diaphragm pumps at a site. In this situation, the
owner or operator is not required to install a new control device. The
proposed standard for the pneumatic pump affected facilities at sites
with less than four diaphragm pumps mirror those proposed in the
November 2021 proposal, which require that methane and VOC emissions be
reduced by 95 percent by routing to an existing control device if: (1)
A control device is onsite, (2) the control device can achieve a 95
percent reduction, and (3) it is technically feasible to route the
emissions to the control device. However, the proposed rule would
exempt an owner or operator from this requirement provided that they
document the technical infeasibility of routing the emissions to an
existing control device and submit it in an annual report. Similarly,
where it is feasible to route the emissions to a control device, but
the control cannot
[[Page 74778]]
achieve 95 percent reduction, the proposed rule would exempt the owner
or operator from the 95 percent reduction requirement, provided that
the owner or operator maintain records demonstrating the percentage
reduction that the control device is designed to achieve.
The EPA notes that inherent throughout these proposed pneumatic
pump requirements are demonstrations of technical infeasibility. Each
technical infeasibility determination must include a certification,
signed and dated by the qualified professional engineer or in-house
engineer. The EPA wants to make it clear that in the case that such a
certification is determined by the Agency to be fraudulent, or
significantly flawed, not only will the owner or operator of the
affected facility be in violation of the standards, but the person that
makes the certification will also be subject to civil and potentially
criminal penalties.
2. EG OOOOc
The proposed presumptive standards for methane emissions from
existing pneumatic pumps mirror those described above for NSPS OOOOb.
The EPA did not identify any circumstances that would result in a
different BSER for existing sources under the EG OOOOc.
In light of the proposal to require zero-emission pneumatic pumps
not powered by natural gas for both new and existing sources, the EPA
would like to highlight comments and solicit related information.
Commenters on the November 2021 proposal indicated that the proposed
rules would exacerbate demand, increase costs, and increase pressure on
the supply chain for zero-emissions systems. One commenter stated that
reliability and availability of alternate zero-emission options (i.e.,
solar-powered/battery backup systems, and electric, self-contained
systems) are a major concern for safe and reliable operations.\169\
Another commenter indicated that one of their members contacted a
vendor within the last six months to find out how much deployment there
has been of solar systems and electric controllers.\170\ The commenter
reported that the vendor indicated that in the past 10 years, they have
conducted 200 retrofits and 300 new installs, and the vendor estimates
that it can only service approximately 200 installs per year.
Additionally, the commenter indicated that operators are already
experiencing 6 to 12-month lead times for delivery of solar packages.
So that it may continue to gather information on this subject, the EPA
is specifically requesting comment on the availability of pneumatic
pump systems not powered by natural gas.
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\169\ See Document ID No. EPA-HQ-OAR-2021-0317-0739.
\170\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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F. Wells and Associated Operations
1. Affected and Designated Facility Definitions
a. NSPS OOOOb
The November 2021 proposal had three separate affected facilities
associated with oil and natural gas wells. These included: (1) The well
completion affected facility, defined as a single well that conducts a
well completion operation following hydraulic fracturing or
refracturing; (2) the associated gas affected facility, defined as any
oil well that produces associated gas; and (3) the well liquids
unloading affected facility, with two proposed options for the
definition. Under Option 1, a well liquids unloading affected facility
was defined as every well that undergoes liquids unloading. Under
Option 2, a well liquids unloading affected facility was defined as
every well that undergoes liquids unloading using a method that is not
designed to completely eliminate venting. Each of these three types of
affected facilities included proposed definitions of what would
constitute a modification to an oil and natural gas well. The result of
including all three definitions would have been that a single well
could have been three different affected facilities for three different
emissions sources. In addition, a single well could have been a new
source affected facility under NSPS OOOOb and a designated facility
under EG OOOOc.
To eliminate the potential confusion from this complex regulatory
structure, the EPA is proposing to change its approach as part of this
proposed action. Rather than three separate well affected facilities,
we are now proposing a definition of well affected facility, which is
defined as a single well, in the proposed NSPS OOOOb. A well is defined
as a hole drilled for the purpose of producing oil or natural gas. More
discussion of the rationale for this revision specific to each of the
three well operations is provided in sections IV.E.2, 3, and 4 below.
There are separate proposed standards for well completions,
associated gas from oil wells, and gas well liquids unloading
operations, all or some of which could apply to a well affected
facility. These proposed standards and their applicability are
discussed in more detail in sections IV.E.2, 3, and 4 of this preamble.
A well affected facility is only required to comply with the standards
that are applicable to the well. For example, a gas well would not be
subject to the oil well with associated gas standards. The proposed
NSPS OOOOb specifies that a modification to an existing well occurs
when the definition of modification in 40 CFR 60.14 is met, including
when an existing well undergoes hydraulic fracturing or re-fracturing.
b. EG OOOOc
The November 2021 proposal only included the oil wells with
associated gas designated facility, as the proposed definition of
modification for the NSPS OOOOb well liquids unloading affected
facility would have resulted in all wells that performed liquids
unloading being new or modified sources. As discussed above and in
section IV.E.3, the EPA has not retained the proposed well liquids
unloading modification definition in this supplemental proposal.
Therefore, this proposal includes standards for gas well liquids
unloading at designated facilities in the proposed EG OOOOc. However,
since the fracturing or re-fracturing of an existing well would
constitute a modification under NSPS OOOOb, which makes the well a well
affected facility under NSPS OOOOb, there would never be an existing
well subject to completion requirements.
The well designated facility definition in EG OOOOc is now proposed
to be defined as a single well and EG OOOOc would include presumptive
standards for associated gas from oil wells and gas well liquids
unloading.
2. Associated Gas From Oil Wells
a. NSPS OOOOb
i. November 2021 Proposal
Associated gas originates at wellheads that also produce
hydrocarbon liquids and occurs either in a discrete gaseous phase at
the wellhead or is released from the liquid hydrocarbon phase by
separation. In the November 2021 proposal, the EPA proposed standards
in NSPS OOOOb to reduce methane and VOC emissions resulting from the
venting of associated gas from oil wells. Specifically, the November
2021 proposal would have required owners and operators of oil wells to
route associated gas to a sales line. If access to a sales line was not
available, the EPA proposed that the gas could have been used as an
onsite fuel source, used for another useful purpose that a purchased
fuel or raw material would serve, or routed to a flare or other control
device that achieves at least 95 percent reduction of methane and VOC
[[Page 74779]]
emissions.\171\ The EPA also requested comment on whether to include
re-injecting associated gas for enhanced oil recovery or another
purpose should be included in the list of beneficial uses. The
following sections provide discussions of the comments submitted on the
November 2021 proposal, the changes resulting from these comments, and
our rationale for the changes. Section IV.E.2.iii summarizes the
resulting proposed requirements included in this supplemental proposal.
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\171\ The EPA solicited comment on whether to also include re-
injecting associated gas as an alternative (86 FR 63237; November
15, 2021) and based on comments in support of this option [EPA-HQ-
OAR-2021-0317-0844], is including such alternative in this
supplemental proposal.
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ii. Changes From November 2021 Proposal
The BSER determination for associated gas from oil wells was
discussed in section XII.J.1.e of the November 2021 proposal (86 FR
63237-63238; November 15, 2021). The EPA did not receive any comments
on the proposal that resulted in a change to the analysis that had
concluded that BSER for associated gas from oil wells was the routing
of the associated gas to a sales line.
In this action, we are proposing changes to the associated gas from
the oil wells affected facility definition, the hierarchy of the
standard, and the compliance options. In addition to proposed changes
associated with these topics, a significant addition to the proposed
rule is the establishment of requirements for situations when
associated gas from an oil well that is primarily either routed to a
sales line or used for another beneficial purpose is unable to utilize
the gas in that manner due to gathering system or other disruptions. In
addition, the EPA is soliciting additional information on potential
emerging technologies that provide uses for the associated gas in a
beneficial manner other than routing to a sales line, using as a fuel,
or reinjecting the gas. Examples of such emerging technologies provided
by commenters include methane pyrolysis \172\ and condensing the gas
and transporting it to other sites for use.\173\
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\172\ See Document ID No. EPA-HQ-OAR-2021-0317-0594.
\173\ See Document ID No. EPA-HQ-OAR-2021-0317-0558.
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Hierarchy of the Standard and Control Options. As discussed in
section IV.E.1.b.i, the standard for associated gas from oil wells in
the November 2021 proposal was to route the associated gas to a sales
line. If access to a sales line was not available, the proposal allowed
the gas to be used as an onsite fuel source, used for another useful
purpose that a purchased fuel or raw material would serve, or routed to
a flare or other control device that achieves at least 95 percent
reduction in methane and VOC emissions.
The EPA specifically solicited comment on how ``access to a sales
line'' should be defined. Several commenters \174\ stated that access
to a sales pipeline is based on numerous criteria that can be outside a
well operator's control. They indicated that, in most cases, the
midstream company that designs, builds, and operates the gas gathering
system (sales line) and gas processing plant is not the same as the
well owner and operator, landowner, and mineral lease owner. Thus,
commenters concluded that ``access to a sales line'' does not equate to
availability to route gas into that sales line.
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\174\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0793, EPA-HQ-
OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-0911.
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Commenters also objected to the overall construct of the proposal
where the standard required the routing to a sales line in situations
where access to sales line was available. They indicated that using the
gas as an onsite fuel source should be an option that was allowed on an
equal basis with routing to a sales line.
The EPA agrees with these commenters regarding the associated gas
from oil wells standards. First, the EPA understands that the sales
line is typically not under the control of the well owner, and that the
gathering system owner dictates when gas can be routed to a sales line.
We believe this understanding supports allowing other uses of
associated gas, which also avoid methane and VOC emissions from venting
or flaring of associated gas, as acceptable compliance options.
Specifically, while BSER was determined to be routing to a sales line,
we agree that beneficial uses of the associated gas should be allowed
as these options are equivalent in terms of emission reduction to the
identified BSER. Therefore, we are proposing to expand what is
considered beneficial use to include options beyond routing to the
sales line. This proposed rule would require any of the following
options for beneficial use: (1) Routing associated gas from oil wells
to a sales line; (2) using the associated gas as a fuel or for another
useful purpose that a purchased fuel or raw material would serve; (3)
or reinjecting the associated gas into the well or injecting the
associated into another well for enhanced oil recovery. Regarding re-
injection, commenters indicated that re-injection should be included as
one of the options allowed. One commenter stated that well operators
may prefer to reinject associated gas. They pointed out that
reinjection is used widely in Alaska, where 90 percent of associated
gas is injected into oil-bearing formations. They concluded that
reinjection as a method of gas capture has significant emissions
reduction benefits, because it largely eliminates emissions of methane
and other pollutants.\175\
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\175\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
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As noted above, commenters also mentioned examples of emerging
techniques that provide additional beneficial uses of the associated
gas, including compressing the gas and transporting it to a nearby
processing plant or pipeline and methane pyrolysis. The EPA interprets
the third criterion, ``used for another useful purpose,'' to include
these emerging techniques but is soliciting comment whether an
additional criterion should be added to make this clear. The EPA is
also soliciting comment on more specific technologies that have been
proven to be viable in the field to utilize associated gas and avoid
venting or flaring.
Some commenters stated that the proposed rule would not succeed in
ensuring that oil and gas operators will not flare associated gas in
situations where other options were available, and these commenters
opposed routine flaring as a compliance alternative on par with the
non-sales line ``beneficial'' use options. They urged the EPA to
abandon what they described as an ``unworkable framing,'' and instead
suggested that the EPA adopt a BSER that would eliminate routine
flaring except in specific and narrowly defined circumstances. We agree
that flaring of the gas should only be allowed in situations where it
is not feasible to route the associated gas to a sales line or use it
for one of the other useful purposes described above. Therefore, this
proposed rule would allow flaring of the associated gas only if the
owner or operator certifies that it is not feasible to route the
associated gas to a sales line or use it for another beneficial purpose
due to technical or safety reasons. This demonstration would need to
address the specifics regarding the lack of availability to a sales
line, including efforts by operators to get access to a sales line or
to facilitate alternative off-site transport and use of associated gas.
The demonstration would also need to demonstrate why all potential
beneficial
[[Page 74780]]
uses (including emerging techniques) are not feasible due to technical
or safety reasons. The first demonstration would require certification
by a professional engineer or other qualified individual and would be
submitted in the first annual report for the well affected facility. In
each subsequent annual report, the owner or operator would be required
to report whether any circumstances had changed regarding the need to
flare relative to the initial certification, and if so, which
beneficial use would be applied to the associated gas.
The EPA recognizes that several states have adopted standards to
further reduce routine flaring of associated gas, including Colorado
and New Mexico. As noted above, several commenters also urged the EPA
to take additional steps to eliminate routine flaring of associated
gas, except in very limited cases such as emergencies or for safety
reasons. Therefore, the EPA is taking comment on steps the Agency
should consider taking to disallow the indefinite continuation of
routine flaring. First, the EPA is taking comment on whether the
ongoing annual requirement to report whether circumstances had changed
regarding the need to flare should result in a need to perform a more
thorough analysis and engineering certification comparable to the
initial certification required once an owner or operator becomes
subject to the rule. For example, it may be appropriate to require an
owner or operator to provide an additional engineering certification
that flaring is the only option where a new gathering pipeline is
installed within a certain distance of an oil well. Second, the EPA is
taking comment on whether it would be appropriate to require more
rigorous consideration of alternatives to flaring after a set threshold
is reached (e.g., after a set time of flaring (such as 2 years) or
after a set volume of gas has been flared). Third, the EPA requests
comment on whether there are any provisions in existing state
regulations beyond what is already included in this supplemental
proposal, or other measures (such as minimum capture requirements or
volumetric limits on flaring), that the EPA should consider in its BSER
analysis. Finally, the EPA is also soliciting comment on whether there
are specific emerging technologies that should be required to be
addressed in this demonstration and listed in the rule.
Requirements when Gathering System or Other Disruption Occurs. The
EPA is aware that when associated gas is typically routed to a sales
line there could be situations that arise that can cause an
interruption of the ability to route the gas to the sales line. As
discussed above and pointed out by commenters, this situation is
usually not under the control of the owner or operator of the well. The
EPA agrees that interruptions where the gathering system owner is
suddenly unable to accept the associated gas from the well could also
occur that impact the ability to utilize the associated gas as a fuel
or for another useful purpose. The EPA has considered options for this
situation for this supplemental proposal. One option considered was
that this situation would constitute a deviation or violation of the
standard unless the owner or operator elected to shut the well in and
halt the production of the associated gas. The EPA did not select this
option in this supplemental proposal. The EPA concluded that such
situations could constitute a technical or safety reason that could be
used to justify the use of a control device that achieves 95 percent
reduction of methane and VOC emissions. Therefore, the EPA is proposing
to require that if owners and operators anticipate that there may be
interruptions in the ability to route the associated gas to a sales
line or to use it for another beneficial purpose, they must provide a
technical or safety demonstration in their annual report and install
and operate a control device that achieves the required reduction
during these temporary periods. It is anticipated this control device
would need to be permanently installed to account for these periods
when associated gas could not be routed to a sales line or used for
other beneficial purposes, but the EPA is soliciting comment on whether
the use of temporary controls could also serve this purpose. Further
the EPA is soliciting comment on what additional requirements would be
necessary to ensure a temporary control device is onsite and
operational to immediately control emissions when necessary for these
circumstances. Venting of the associated gas under any circumstances
would represent a violation of the proposed standards, even if for a
short period.
Potential Exemptions and Alternative BSER for Unique Circumstances.
Several commenters on the November 2021 proposal identified situations
where it would not only be infeasible to route the associated gas to a
sales line or use it for another beneficial purpose, but where it would
also be infeasible to route it to a flare or other control device to
achieve 95 percent reduction in methane and VOC emissions. Examples of
these situations include when the flow rate, pressure, or volume of the
associated gas is insufficient to route to a sales line or to support
the continuous operation of a flare or combustion device; when the
composition of the gas is such that it cannot be routed to a sales line
or used in some manner (e.g., 97 percent CO2 and 3 percent
methane) and it does not contain sufficient heat content to combust
without the addition of unreasonable amounts of propane; wildcat wells;
and delineation wells. One commenter provided detailed information
about the issues with certain wells in Wyoming,\176\ The EPA believes
that these situations could warrant an exemption or an alternative
standard. However, this proposed rule does not include any exemptions
or allowances for these situations due to lack of specific sufficient
information. Therefore, the EPA is interested in additional information
on gas compositions of associated gas that would make it both unusable
for a beneficial purpose and unable to be flared. The EPA is not only
interested in why commenters feel these situations warrant an exemption
from the associated gas standards as proposed, but also what methods
are currently in use, or could be used, to minimize methane and VOC
emissions in these situations.
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\176\ See Document ID No. EPA-HQ-OAR-2021-0317-0955.
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iii. Summary of Proposed Standards
In summary, this supplemental proposal allows owners and operators
four compliance options to reduce or eliminate emissions of methane and
VOC from associated gas from oil wells. These options are: (1) Recover
the associated gas from the separator and route the recovered gas into
a gas gathering flow line or collection system to a sales line, (2)
recover the associated gas from the separator and use the recovered gas
as an onsite fuel source, (3) recover the associated gas from the
separator and use the recovered gas for another useful purpose that a
purchased fuel or raw material would serve, or (4) recover the
associated gas from the separator and reinject the recovered gas into
the well or inject the recovered gas into another well for enhanced oil
recovery.
Associated gas cannot be routed to a flare or other combustion
device unless the owner or operator demonstrates that all four options
discussed above are infeasible due to technical or safety reasons, and
that demonstration is approved by a certified professional engineer.
Any combustion device must meet the requirements in 40 CFR
[[Page 74781]]
60.5412b and that monitoring, recordkeeping, and reporting be conducted
to ensure that the combustion device is constantly achieving the
required 95 percent reduction. More information on the control device
monitoring and compliance provisions is provided in section IV.H of
this preamble.
In each annual report, owners and operators would be required to
identify each well affected facility with associated gas that was
constructed, modified, or reconstructed during the reporting period.
The report would specify whether the associated gas will be routed into
a gas gathering flow line or collection system to a sales line, used as
an onsite fuel source, used for another useful purpose that a purchased
fuel or raw material would serve, reinjected into the well, or injected
into another well for enhanced oil recovery. If making a demonstration
that it is infeasible to utilize one of these options due to technical
or safety reasons, this demonstration would also be included in the
first annual report. This demonstration would clearly and
comprehensively justify why all of these options are infeasible,
including all emerging technologies that could represent a beneficial
use of the gas. This demonstration would be required in situations
where the associated gas is always routed to a control device, as well
as for situations where disruptions or interruptions result in the need
to route the associated gas to a control device for temporary periods.
In subsequent annual reports, owners and operators complying by
routing the associated gas to a gas gathering flow line or collection
system to a sales line, used as an onsite fuel source, used for another
useful purpose that a purchased fuel or raw material would serve,
reinjected into the well, or injected into another well for enhanced
oil recovery would be required to report all instances when associated
gas was vented to the atmosphere. Owners and operators complying by
routing the associated gas to a control device and achieving 95 percent
reduction in methane and VOC would be required to report all instances
when associated gas was vented to the atmosphere. In addition, these
owners and operators would be required to report any changes made at
the site since the original technical infeasibility demonstration and
whether the change impacted the feasibility to route the associated gas
to a gas gathering flow line or collection system to a sales line, use
the gas as an onsite fuel source, use the gas for another useful
purpose that a purchased fuel or raw material would serve, reinject the
gas into the well, or inject the gas into another well for enhanced oil
recovery. If the change did not impact this feasibility, a revised
demonstration and certification would be required. If the change did
impact the feasibility, the owner or operator would need to report the
new method of compliance that is utilized.
Required records would include documentation of the specific type
of compliance method (i.e., routed into a gas gathering flow line or
collection system to a sales line, used as an onsite fuel source, used
for another useful purpose that a purchased fuel or raw material would
serve, injected into another well for enhanced oil recovery) was used.
Owners and operators would also be required to maintain records that
demonstrate why the required capture and use requirements are not
feasible and why the use of a control device is the only option. If the
control device is only used on a temporary basis when disruptions or
interruptions occur in the primary compliance method for the associated
gas, the owner or operator would document the periods that the gas is
routed to the control device. All records associated that demonstrate
proper design and operation of the control device would also be
required to be maintained (see section IV.G of this preamble). Finally,
all instances where emissions are vented would be recorded, along with
records of actions that were taken during these periods to minimize
emissions to the atmosphere.
b. EG OOOOc
The proposed presumptive standards for associated gas from existing
oil wells mirror those described above for NSPS OOOOb. The EPA did not
identify any circumstances that would result in a different BSER for
existing sources under the EG OOOOc.
3. Gas Well Liquids Unloading Operations
a. NSPS OOOOb
i. November 2021 Proposal
In the November 2021 proposal, the EPA proposed to add standards to
reduce VOC and methane emissions from each new, modified, or
reconstructed gas well that conducts a well liquids unloading operation
in NSPS OOOOb. In that proposal, the EPA proposed a standard that would
require owners or operators to perform well liquids unloading with zero
methane or VOC emissions. In the event that it is technically
infeasible or not safe to perform well liquids unloading with zero
emissions, the EPA proposed to require owners and operators to
establish and employ BMPs to minimize methane and VOC emissions during
well liquids unloading operations to the extent possible. Two
regulatory approaches were co-proposed in the November 2021 proposal.
The first approach defined the affected facility as every well that
undergoes liquids unloading, while the second approach defined the
affected facility as every well that undergoes liquids unloading using
a method that is not designed to completely eliminate venting. Both
approaches require zero emissions unless technically infeasible, and
where infeasible, both approaches require minimizing venting using
BMPs.
ii. Changes From November 2021 Proposal
As described in section IV.E.1, the EPA is proposing to define the
``affected facility'' as a single well in this supplemental proposal,
instead of defining it as a well that undergoes liquids unloading.
Further, the EPA is revising the ``modification'' definition to apply
to a single well that undergoes hydraulic fracturing or refracturing.
This revised definition replaces the definition proposed in the
November 2021 proposal, where all well liquids unloading events would
have been considered a modification.
Several commenters stated that the November 2021 proposal's
definition of modification for well liquids unloading operations was
flawed in a number of respects. First, commenters asserted that not all
well liquids unloading operations result in an increase in emissions to
the atmosphere because some operations do not vent gas and therefore
have zero emissions. We agree with commenters on this point; therefore,
we are not maintaining the proposed definition that every well liquids
unloading operation is a modification. Second, commenters stated that
well liquids unloading operations are a part of the normal operation of
the well and do not result in a physical or operational change to the
well, and therefore do not meet the definition of modification in 40
CFR 60.2. The EPA agrees with the commenters that well liquids
unloading operations are not physical changes to the well itself. A
well liquids unloading operation does not change the shape, size, or
any other physical feature of the well (i.e., the hole drilled for the
purpose of producing oil or natural gas).
The question of whether well liquids unloading operations
constitutes an operational change to the well is more nuanced. The EPA
understands that every gas well will eventually need to have liquids
removed in order to improve or maintain production. While
[[Page 74782]]
the definition of modification in this proposal has been adjusted to
reflect the information commenters have provided, the EPA has yet to
reach a conclusion on whether certain types of liquids unloading events
could be an operational change to a well. The EPA is therefore
requesting comment on operational scenarios where a well liquids
unloading event could constitute a modification. Operational scenarios
that may be considered a modification regarding well liquids unloading
could include: (1) The first time, in the life of the well, that well
liquids unloading occurs, (2) the first time, after fracturing or
refracturing a well, that well liquids unloading occurs, (3) a change
in the type or method of well liquids unloading, or (4) ongoing liquids
unloading as part of a regular operational schedule. The EPA is
requesting specific comment on whether these operational scenarios, or
any additional ones, may or may not constitute a modification.
iii. Summary of Proposed Requirements
In this supplemental proposal, the EPA has provided regulatory text
similar to the November 2021 co-proposed option 1, where all gas well
liquids unloading operations would be subject to the regulatory
requirements. The EPA is proposing the same standard of performance as
discussed in the November 2021 proposal: perform well liquids unloading
with zero methane or VOC emissions. The BSER is to employ techniques or
technologies that eliminate methane and VOC emissions. Where it is
technically infeasible or not safe to meet the zero emissions standard,
employ BMPs to minimize methane and VOC emissions during well liquids
unloading operations to the maximum extent possible. While we received
multiple comments recommending regulating only well liquids unloading
events that result in vented emissions, we are not including proposed
regulatory text for the co-proposed option 2. Should the EPA decide to
finalize the standards as stated in the November 2021 co-proposed
option 2, the regulatory text specific to BMPs would remain relevant
and is already provided in this supplemental proposal. As stated above,
there are malfunctions that can result in vented emissions from well
liquids unloading operations that would otherwise meet the zero
emissions standard. Further, since each well liquids unloading
operation is conducted based on the site-specific circumstances at the
time the operation is planned, the EPA is concerned that a well might
fluctuate between falling within and out of the scope of the standards
if the standards only applied to well liquids unloading operations that
result in vented emissions. Therefore, for ease of implementation to
the owner or operator, the EPA is proposing to apply the proposed
standards to all well liquids unloading operations regardless of if the
operation results in vented emissions. The EPA is, however,
specifically requesting further comment and any additional information
regarding co-proposed option 2, where standards only apply to wells
with well liquids unloading operations that result in vented emissions.
The EPA is also proposing specific recordkeeping and reporting
requirements related to well liquids unloading operations. Wells that
utilize a non-venting method would have reporting and recordkeeping
requirements that would include records of the number of well liquids
unloading operations that occur within the reporting period and the
method(s) used for each well liquids unloading operation. A summary of
this information would also be required to be reported in the annual
report. The EPA also recognizes that under some circumstances, venting
could occur when a selected liquids unloading method that is designed
to not vent to the atmosphere is not properly applied (e.g., a
technology malfunction or operator error). Under this proposed rule,
owners and operators in this situation would be required to record and
report these instances, as well as document and report the length of
venting and what actions were taken to minimize venting to the maximum
extent possible.
Additionally, for wells that utilize methods that vent to the
atmosphere, the proposed rule would require: (1) Documentation
explaining why it is infeasible to utilize a non-venting method due to
technical, safety, or economic reasons; (2) development of BMPs that
ensure that emissions during liquids unloading are minimized; (3)
employment of the BMPs during each well liquids unloading operation and
maintenance of records demonstrating that the BMPs were followed; (4)
reporting in the annual report both the number of well liquids
unloading operations and any instances where the well liquids unloading
operations did not follow the BMPs.
b. EG OOOOc
Since the November 2021 proposal considered all well liquids
unloading events to be a modification, the EPA did not propose a
designated facility definition or presumptive standards for well
liquids unloading in the EG OOOOc. With the revisions to the affected
facility definition and what activities constitute a modification, the
EPA is now proposing to define a designated facility as a single well,
like in the revised proposal for NSPS OOOOb. Further, the EPA is
proposing presumptive standards for existing wells that conduct well
liquids unloading operations in EG OOOOc that are the same as the
standards proposed in NSPS OOOOb. Because the proposed standards
provide flexibility for owners and operators to make site-specific
decisions about what well liquids unloading operations to employ, the
EPA did not identify any circumstances that would result in a different
BSER for existing sources under EG OOOOc.
4. Well Completions
a. NSPS OOOOb
The EPA proposed to retain the requirements found in NSPS OOOO and
NSPS OOOOa for reducing methane and VOC emissions through reduced
emission completion (REC) and completion combustion in the November
2021 proposal. These standards would apply to well completions of
hydraulically fractured or refractured oil and natural gas wells. The
EPA is not proposing changes to the standards in this supplemental
proposal, and the proposed regulatory text at 40 CFR 60.5375b reflects
the standards of performance as proposed in the November 2021 proposal.
The proposed regulatory text included in this supplemental proposal
is similar to the regulatory text found in 40 CFR 60.5375a for NSPS
OOOOa. While the regulatory text is similar, the EPA has been made
aware of potential confusion related to the well completion
requirements and well completion recordkeeping requirements for wildcat
wells, delineation wells, and low-pressure wells. Therefore, the
proposed regulatory text for NSPS OOOOb includes language to clarify
these particular standards for new, modified, and reconstructed sources
moving forward. First, the EPA is proposing regulatory text at 40 CFR
60.5375b(f) to clearly state the requirement to route emissions from
wildcat well, delineation well, and low-pressure well completions to a
completion combustion device in any instance (unless combustion creates
a fire or safety hazard or can damage tundra, permafrost or waterways).
The EPA is aware from implementation of NSPS OOOOa that owners and
operators are unclear if they can choose to comply with 40 CFR
60.5375a(f)(3)(ii) and make
[[Page 74783]]
a claim of technical infeasibility for the separator to function, which
then precludes the requirement to route recovered emissions to a
completion combustion device. This was not the EPA's intent in NSPS
OOOOa and for this reason, we are proposing to clearly specify at 40
CFR 60.5375b(f) that an alternative to route to a separator (instead of
routing all flowback to a completion combustion device) is available
only when the owner or operator is able to operate a separator and has
the separator onsite (or otherwise available for use) and ready for use
to comply with the alternative during the entirety of the flowback
period.
Second, the EPA is proposing to eliminate recordkeeping
requirements which are not necessary for wildcat wells, delineation
wells, and low-pressure wells that had previously been included in NSPS
OOOOa. Specifically, the EPA is proposing to not require records for
``beneficial'' use of recovered gas (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) nor records of ``specific
reasons for venting in lieu of capture.'' These records are not
required for wildcat wells, delineation wells, and low-pressure wells
because the well completion standards at 40 CFR 60.5375b(f) require
that all flowback, or gas recovered from flowback through the operation
of a separator, be routed to a completion combustion device (i.e.,
there will not be an instance, when complying with 40 CFR 60.5375b(f),
that beneficial use of recovered gas will occur).
G. Centrifugal Compressors
As discussed in section XII.F of the November 2021 proposal
preamble (86 FR 63220; November 15, 2021), centrifugal compressors are
used throughout the natural gas industry to move natural gas along the
pipeline. These compressors are a significant source of methane and VOC
emissions. Centrifugal compressors are powered by turbines, which
utilize a small portion of the natural gas being compressed to fuel the
turbine. As an alternative to natural gas-fueled turbines, some
centrifugal compressors use an electric motor.
Centrifugal compressors require seals around the rotating shaft to
minimize gas leakage from the point at which the shaft exits the
compressor casing. There are two types of seal systems: wet seal
systems and mechanical dry seal systems.
Wet seal systems use oil, which is circulated under high pressure
between three or more rings around the compressor shaft, forming a
barrier to minimize compressed gas leakage. Very little gas escapes
through the oil barrier, but considerable gas is absorbed by the oil.
The amount of gas absorbed and entrained by the oil barrier is affected
by the operating pressure of the gas being handled; higher operating
pressures result in higher absorption of gas into the oil. Seal oil is
purged of the absorbed and entrained gas (using heaters, flash tanks
and degassing techniques) and recirculated to the seal area for reuse.
Gas that is purged from the seal oil is commonly vented to the
atmosphere.
Dry seal systems do not use any circulating seal oil. Dry seals
operate mechanically under the opposing force created by hydrodynamic
grooves and springs. Emissions occur from dry seals around the
compressor shaft vent.
1. NSPS OOOOb
a. November 2021 Proposal
i. Affected Facility
The November 2021 proposal defined the centrifugal compressor
affected facility as a single centrifugal compressor using wet seals
(including centrifugal compressors using wet seals located at
centralized production facilities). The November 2021 proposal excluded
centrifugal compressors using wet seals located at a standalone well
site from the affected facility definition under NSPS OOOOb.
ii. Summary of Proposed BSER Analysis
November 2021 Proposal BSER Analysis. The BSER analysis methodology
presented in the November 2021 proposal (86 FR 63221; November 15,
2021) was consistent with what was used to support the 2011 NSPS OOOO
and 2016 NSPS OOOOa BSER analyses. The EPA conducted emissions
reduction cost effectiveness analyses for various control options using
both the single pollutant and multipollutant approaches.\177\
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\177\ See section III.E of this preamble and 86 FR 63154
(November 15, 2021).
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The EPA used emissions factors for uncontrolled methane emissions
from wet seals in the November 2021 proposal analysis that were based
on the baseline uncontrolled methane emissions factors used for the
2016 NSPS OOOOa analysis, in addition to the capital costs for flares
and associated equipment (e.g., CVS) necessary to route emissions to
the flare (with costs updated to 2016 dollars). These baseline
estimates of uncontrolled emissions were higher than the emissions the
EPA estimated for these sources in both the 2015-2020 GHGRP subpart W
and 2019 GHGI for all industry segments, with the exception of the
GHGRP subpart W onshore production and gathering and boosting segments.
The reduction in emissions attributed to centrifugal compressors in the
2019 GHGRP subpart W and 2019 GHGI is likely due to the increased
deployment of emissions controls resulting from the 2012 NSPS OOOO and
2016 NSPS OOOOa, as well as a shift from the use of wet seals to dry
seals by the industry since these rules were promulgated.
Various control options were evaluated as part of the November 2021
proposal to reduce emissions from centrifugal compressors. Such options
included control techniques that limit emissions across the rotating
shaft of the wet seal centrifugal compressor and techniques to capture
and control emissions using a combustion device or by routing to a
process. Based on cost analyses conducted, the November 2021 proposal
for both the NSPS OOOOb and EG OOOOc rules required that VOC and/or
methane emissions from each centrifugal compressor wet seal fluid
degassing system be reduced by 95 percent by routing emissions to a
control device or to a process.
The November 2021 proposal solicited specific comment on emissions
from wet seal compressors, as well as information on lower-emitting wet
seal compressor designs. See 86 FR 63221 (November 15, 2021). The EPA
also solicited comments on dry seal compressor emissions, seeking
information on whether, and to what degree, operational or
malfunctioning conditions (e.g., low seal gas pressure, contamination
of the seal gas, lack of supply of separation gas, and mechanical
failure) have the potential to impact methane and VOC emissions. The
EPA further requested information on whether owners and operators of
dry seal compressors currently implement standard operating procedures
in order to identify and correct operational or malfunctioning
conditions that have the potential to increase emissions from dry seal
systems. Finally, the EPA also requested information on whether it
should consider evaluating BSER and developing NSPS standards for dry
seal compressors.
b. Changes to Proposal and Rationale
The EPA is proposing changes and clarifications to the November
2021 proposed standards for NSPS OOOOb. Specifically, we are proposing
to: (1)
[[Page 74784]]
Revise the affected facility definition to include all centrifugal
compressors (i.e., both wet seal and dry seal configurations), (2)
specify that self-contained wet seal centrifugal compressors meet the
NSPS OOOOb BSER requirements, and (3) set numerical emission limit
requirements for dry seal and self-contained wet seal centrifugal
compressors.
i. Wet Seal Centrifugal Compressors
The EPA received comments that included specific data on the
November 2021 proposal related to emissions, costs, and the proposed
standards/analyses for wet seal centrifugal compressors.\178\ These
commenters asserted that actual wet seal centrifugal compressor
baseline emissions are significantly lower than the emissions estimates
that the EPA used in the November 2021 proposal's BSER analysis and
recommended that the EPA use updated emissions information reported
under GHGRP subpart W. One of the commenters provided information on
wet seal centrifugal compressor emissions for their sources in the
transmission segment and requested the EPA consider using it in any new
BSER analysis.\179\ This commenter also opined that the proposed 95
percent reduction standard is unclear insofar as there is no indication
of what value the reduction is to be measured against. This commenter
stated that for seals that emit de minimis levels of VOC or methane, it
would be impracticable to further reduce such emissions and that
assuming emissions can be calculated, the proposed BSER of routing
emissions to a control device or to a process would be cost
prohibitive.
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\178\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0415 and EPA-HQ-
OAR-2021-0317-1375.
\179\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
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These same commenters also stated that the costs used by the EPA in
the November 2021 proposal's BSER analyses were not representative of
actual costs, and that the EPA had underestimated the costs for the
control options evaluated. One of the commenters provided detailed cost
information that they stated was more representative of actual costs
for three combustion scenarios, the option to route to a process for
control, and retrofit costs.
Finally, these same commenters suggested that the EPA consider a de
minimis exemption, such as an exemption for limited use wet seal
centrifugal compressors or the establishment of an emissions
applicability threshold (referring to California's centrifugal
compressor requirements as an example) \180\ where a wet seal
compressor that has a measured flow rate less than a specified
threshold would be exempt from regulatory requirements.
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\180\ California's Regulation for Greenhouse Gas Emission
Standards for Crude Oil and Natural Gas Facilities rule (California
Code of Regulations, Title 17, Division 3, Chapter 1, Subchapter 10
Climate Change, Article 4, Subarticle 13, Section 95668(d)(4-9)).
---------------------------------------------------------------------------
The EPA re-evaluated the November 2021 BSER in light of the
suggestions from commenters related to emissions and costs. We used
GHGRP subpart W emissions information because the GHGRP requires a
multi-step data verification process, which increases the confidence in
the reliability of data and resulting analyses.\181\ The methodology we
used for estimating emissions from compressors is consistent with the
methodology used for the November 2021 proposal. See 86 FR 63220
(November 15, 2021). The wet seal centrifugal compressor GHGRP subpart
W methane uncontrolled emissions/emissions factors are based on
volumetric emissions, which were converted to a mass emission rate for
this analysis. The resulting baseline uncontrolled emissions per wet
seal centrifugal compressor are 251 tpy methane (69.9 tpy VOC) from wet
seal compressors at gathering and boosting sites, 163 tpy methane (45.4
tpy VOC) from wet seal compressors at natural gas processing plants,
and 66 tpy methane (1.8 tpy VOC) from wet seal compressors at
transmission and storage facilities. These baseline uncontrolled
emissions per wet seal centrifugal compressor are higher than what we
used in the November 2021 proposal analysis for the gathering and
boosting segment (based on GHGRP subpart W emissions factor), but lower
for all other segments of the industry.\182\
---------------------------------------------------------------------------
\181\ EPA (2020) Greenhouse Gas Reporting Program. U.S.
Environmental Protection Agency. Data reported as of August 7, 2021.
\182\ U.S. Environmental Protection Agency. Supplemental
Background Technical Support Document for the Proposed New Source
Performance Standards (NSPS) and Emissions Guidelines (EG). August
2022.
---------------------------------------------------------------------------
The same control options from the analysis for the November 2021
proposal (routing to a control device and routing to a process) were
evaluated with the above updates. Additionally, we evaluated a new
option to address dry seal centrifugal compressor emissions, as
discussed in more detail later in this section.
Routing to a control device. As discussed in the November 2021
proposal, a combustion device generally achieves 95 percent reduction
of methane and VOC when operated according to the manufacturer
instructions. Therefore, for this analysis, we assumed that the
entrained natural gas from the seal oil that is removed in the
degassing process would be directed to a combustion device that
achieves a 95 percent reduction of methane and VOC emissions. The
combustion of the recovered gas creates secondary emissions of
hydrocarbons (NOX, CO2, and CO emissions).
Routing the captured gas from the centrifugal compressor wet seal
degassing system to a combustion device has associated capital and
operating costs. The capital and annual operating costs for the
installation of a combustion device used in the updated analysis
presented with this supplemental proposal are based on information
obtained from commenters regarding a new high-end enclosed
combustor.\183\ These costs were adjusted from 2021 dollars to 2019
dollars for consistency with the other analyses in this rulemaking. The
updated capital costs of $123,559 were annualized at 7 percent based on
an equipment life of 10 years. The total annualized capital costs were
estimated to be $17,592. The annual operating costs used are based, in
part, on costs assumed in the 2011 NSPS OOOO TSD and 2016 NSPS OOOOa
TSD,\184\ with the costs again updated to reflect 2019 dollars. The
resulting annual operating costs (including annual administrative,
taxes, and insurance costs) were estimated to be $105,472. Therefore,
the updated estimated total annual costs (including annualized capital
and operating costs) are $123,063 per compressor. There are no cost
savings estimated for this option because the recovered natural gas is
combusted.
---------------------------------------------------------------------------
\183\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
\184\ See Document ID Nos. EPA-HQ-OAR-2010-0505-0045 and EPA-HQ-
OAR-2010-0505-7631.
---------------------------------------------------------------------------
As a result of the analysis and cost-effectiveness shown in Table
32 below, the EPA has determined that the costs of routing the captured
gas from the centrifugal compressor wet seal degassing system to a
control device are reasonable for the control of methane for the
gathering and boosting, processing and transmission, and storage
segments using both the single and multipollutant approaches. The EPA
also determined that the costs of routing the captured gas from the
centrifugal compressor wet seal degassing system to a control device
are reasonable for the control of VOC for the gathering and boosting
and processing segments using both the single and multipollutant
approaches.
[[Page 74785]]
Routing to a process. As discussed above, another option for
reducing methane and VOC emissions from the compressor wet seal fluid
degassing system is to route the captured emissions back to the
compressor suction or fuel system or put them to another beneficial use
(referred to collectively as ``routing to a process''). One opportunity
to meet this requirement would be to route emissions via a CVS or to
any enclosed portion of a process unit (e.g., compressor or fuel gas
system) where the emissions are predominantly recycled, consumed in the
same manner as a material that fulfills the same function in the
process, transformed by chemical reaction into materials that are not
regulated materials, incorporated into a product, or recovered. For
purposes of this analysis, we assumed that routing methane and VOC
emissions from a wet seal fluid degassing system to a process reduces
methane and VOC emissions in amounts greater than or equal to the
emissions that would be reduced by a combustion device (i.e., greater
than or equal to 95 percent) because emissions are conveyed via a CVS
to an enclosed portion of a process that is operational where the
emissions are predominantly recycled and/or consumed in the same manner
as a material that fulfills the same function in the process. There are
no secondary impacts with the option to control emissions from
centrifugal wet seals by capturing gas and routing to a process. This
alternative is an existing compliance option under NSPS OOOO and NSPS
OOOOa. The EPA has historically assumed that the emissions reduced by
routing to a process are 95 percent or greater. Our understanding is
that routing gas from centrifugal compressor wet seal fluid degassing
systems to a process generally requires the use of a VRU or other
treatment to obtain a gas stream composition suitable to be returned to
the sales line or for use for another purpose. Unlike pneumatic
controllers and pneumatic pumps, (see section IV.D.1.b.iii of this
preamble for controllers and section IV.E.1.b.iii of this preamble for
pumps), the need to use a VRU or other treatment to obtain a gas stream
with a composition suitable to be returned to the sales line could
result in the use of treatment components that may vent to the
atmosphere or the need for maintenance where, for example, the VRU may
need to be bypassed for short periods (resulting in venting of some
emissions to the atmosphere). The EPA solicits comment on its
assumption that the emissions reduced by requiring the capture of gas
and routing to a process is 95 percent or greater. The EPA also is
soliciting comment on the prevalence of owners and operators complying
with NSPS OOOO and NSPS OOOOa or other rules by routing emissions from
the wet seal fluid degassing system to a process and the need for a VRU
in order to be able to route emissions from the wet seal fluid
degassing system to a process.
The capital and annual costs for routing the seal oil degassing
system to a process used in the updated analysis are based on
information obtained from commenters.\185\ The updated capital costs
are estimated to be $600,636, and the annual costs were estimated to be
$85,517 (without savings), assuming a 10-year equipment life at 7
percent interest. Because the natural gas is not lost or combusted, the
value of the natural gas represents a savings to owners and operators
in the production (gathering and boosting) and processing segments.
Savings were estimated using a natural gas price of $3.13 per thousand
cubic feet (Mcf), which resulted in annual savings of $43,329 per year
at gathering and boosting stations and $28,164 per year at processing
plants.
---------------------------------------------------------------------------
\185\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------
The updated analysis and cost effectiveness shown in Table 32
indicates that routing emissions to a process is cost effective for the
control of methane emissions for all of the evaluated segments using
the single pollutant approach and is also cost effective for methane
using the multipollutant approach for the gathering and boosting and
processing segments. Similarly, the updated analysis indicates that
routing emissions to a process for the control of VOC for the gathering
and boosting and processing segments is cost effective using both the
single and multipollutant approaches. However, as noted in the November
2021 proposal, although capturing leaking gas and routing to a process
has the advantage of both reducing emissions by at least 95 percent and
capturing the natural gas (which results in natural gas savings), the
EPA has received feedback that this option may not be viable in
situations where downstream equipment capable of handling a low-
pressure fuel source is unavailable.
Maintenance and repair activities to meet numerical emission limit.
The EPA evaluated a third BSER option for this supplemental proposal
not considered for the November 2021 proposal: maintenance and repair
activities conducted to maintain emissions at or below 3 scfm, with
annual flow rate monitoring on the wet seal degassing vent (also
referred to as the numerical emission limit). We did so based on
comments indicating that a threshold monitoring option is a more
practical option for low-emitting centrifugal compressors with wet
seals (as compared to the proposed requirement to route to a control
device or to a process). This option would require owners and operators
to perform periodic flow rate monitoring, as well as preventative
maintenance and repair as necessary, on the wet seal degassing vent to
ensure compliance with the 3 scfm emission limit. The 3 scfm volumetric
flow rate emission limit is the same monitoring limit included in
California's Regulation for Greenhouse Gas Emission Standards for Crude
Oil and Natural Gas Facilities.\186\ California developed the 3 scfm
emission standard because this was the equivalent to an average dry
seal emission rate.\187\ The commenters specifically noted that low
emissions from centrifugal compressors equipped with wet seals are
largely a function of proper maintenance and that requiring a 95
percent reduction standard or routing to a process creates an
unintended result--the more careful an operator is with maintaining its
wet seals, the more difficult and costly (on a cost-per-ton basis)
controlling emissions in compliance with these requirements
becomes.\188\
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\186\ California Code of Regulations, Title 17, Division 3,
Chapter 1, Subchapter 10 Climate Change, Article 4, Subarticle 13,
Section 95668(d)(4-9).
\187\ State of California. Air Resources Board Public Hearing to
Consider the Proposed Regulation for Greenhouse Gas Emission
Standards for Crude Oil and Natural Gas Facilities. Staff Report:
Initial Statement of Reasons. pg. 100.
\188\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
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The types of maintenance and repair actions that may be needed to
maintain emissions at or below 3 scfm will vary considerably. One
commenter,\189\ a company that institutes an annual monitoring plan,
indicated that the actions needed to reduce emissions or maintain a
compressor such that it is low-emitting can range from correcting an
identified issue immediately with minor maintenance, replacing o-rings
on the filtration system, or having to rebuild the entire oil system.
The costs associated with these maintenance and corrective actions vary
significantly, from limited labor costs for a short repair activity to
a significant capital cost of equipment and labor to repair and/or
replace parts of the compressor. The EPA does not have specific costs
for the range of maintenance and/or repairs
[[Page 74786]]
that may be necessary to maintain a flow rate at or below than 3 scfm.
For the purposes of this analysis, the EPA selected an annual cost of
$25,000 to represent the average cost of performing the monitoring and
the necessary compressor wet seal maintenance. While we recognize
certain types of maintenance or corrective actions may result in costs
higher than $25,000 in one year, we believe that this is a conservative
estimate to represent an average, annual cost. The EPA specifically
solicits comments on the types of maintenance or corrective actions
that may be required to maintain an emission rate of 3 scfm or less
from wet seal degassing, along with representative costs.
---------------------------------------------------------------------------
\189\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------
To estimate the cost effectiveness of this option, the EPA used the
same updated GHGRP subpart W ``uncontrolled'' emissions discussed above
for each centrifugal compressor with wet seals to represent baseline
emissions. The ``after control'' emissions levels were calculated based
on 3 scfm volumetric flow for 8,760 hours per year and the
representative composition of the gas in the different segments. This
calculation assumes that the emissions are, on average, 3 scfm for the
entire year. This represents a conservative estimate, as one commenter
\190\ indicated that the implementation of a similar program resulted
in average measured emissions of less than 0.5 scfm for compressors
with wet seals. Table 31 shows the baseline emissions, the emissions
after implementation of the numerical emission limit, and the emission
reductions for wet seal compressors.
---------------------------------------------------------------------------
\190\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
Table 31--Methane Baseline Emissions and Reductions After Implementation of the Numerical Emission Limit
(Requirement To Maintain Flow Rate at or Below 3 scfm) Option--Wet Seal Compressors
----------------------------------------------------------------------------------------------------------------
Methane emissions (tpy)/
compressor Methane
Segment -------------------------------- emission
After reduction
Baseline \a\ implementation (tpy)
----------------------------------------------------------------------------------------------------------------
Gathering and Boosting.......................................... 251 27 224
Processing...................................................... 163 27 136
Transmission and Storage........................................ 66 30 35
----------------------------------------------------------------------------------------------------------------
\a\ From GHGRP subpart W (Reporting Years 2015 to 2020--Average).
\b\ Calculated assuming total gas emissions are 3 scfm for 8,760 hours.
As noted above, we assumed annual maintenance, monitoring, and
corrective action costs of $25,000 (without savings). Because the
natural gas is not lost or combusted, the value of that natural gas
represents a savings to owners and operators in the production
(gathering and boosting) and processing segments. Savings were
estimated using the emission reductions noted above and a natural gas
price of $3.13 per Mcf, which resulted in annual savings of $33,719 per
year at gathering and boosting stations and $20,486 per year at
processing plants.
As a result of the wet seal centrifugal compressor analysis and
cost effectiveness shown in Table 32, the EPA has determined that the
costs of implementing a numerical emission limit are reasonable for the
control of methane for the gathering and boosting, processing, and
transmission and storage segments using both the single and
multipollutant approaches. The EPA has also determined that the costs
of implementation of a numerical emission limit is reasonable for the
control of VOC for the gathering and boosting and processing segments,
using both the single and multipollutant approaches.
The estimated cost effectiveness values that would be associated
with: (1) Capturing and routing emissions to a combustion device, (2)
capturing and routing emissions to a process, and (3) conducting
maintenance and repair activities to meet a numerical emission limit (3
scfm) (referred to as the ``numerical limit of 3 scfm'') for
compressors with wet seals are provided in Table 32. In addition to the
cost effectiveness values, Table 32 provides a conclusion regarding
whether the estimated cost effectiveness value is within the range that
the EPA has typically considered to be reasonable. The ``overall''
reasonableness determination is classified as ``Y'' if the cost
effectiveness of either methane or VOC is within the range that the EPA
considers reasonable for that pollutant, or ``N'' if both the methane
and VOC cost effectiveness values are beyond the range that the EPA
considers reasonable on a multipollutant basis.
Table 32--Summary of Wet Seal Centrifugal Compressor Cost Effectiveness by Regulatory Option and Industry
Segment
----------------------------------------------------------------------------------------------------------------
Cost effectiveness ($/ton) \a\--reasonable?
----------------------------------------------------------------
Segment/regulatory option Single pollutant Multipollutant Overall \a\
----------------------------------------------------------------
Methane VOC Methane VOC
----------------------------------------------------------------------------------------------------------------
Gathering and Boosting:
Regulatory Option One-- $515-Y $1,853-Y $258-Y $927-Y Y
Route Emissions to
Combustion Device.........
Regulatory Option Two-- 879-Y 3,163-Y 440-Y 1,582-Y Y
Route Emissions to the
Process...................
Regulatory Option Three-- 111-Y 401-Y 56-Y 201-Y Y
Numerical Limit of 3 scfm.
Processing:
[[Page 74787]]
Regulatory Option One-- 793-Y 2,851-Y 396-Y 1,425-Y Y
Route Emissions to
Combustion Device.........
Regulatory Option Two-- 1,353-Y 4,866-Y 676-Y 2,433-Y Y
Route Emissions to the
Process...................
Regulatory Option Three-- 183-Y 660-Y 92-Y 330-Y Y
Numerical Limit of 3 scfm.
Transmission and Storage:
Regulatory Option One-- 1,973-Y 71,240-N 987-Y 35,620-N Y
Route Emissions to
Combustion Device.........
Regulatory Option Two-- 3,369-N 121,607-N 1,684-Y 60,804-N Y
Route Emissions to the
Process...................
Regulatory Option Three-- 711-Y 25,650-N 355-Y 12,825-N Y
Numerical Limit of 3 scfm.
----------------------------------------------------------------------------------------------------------------
\a\ For the gathering and boosting and processing segments, the owners and operators realize the savings for the
natural gas that is not emitted and lost. The cost effectiveness values shown do not consider these savings.
Note that the consideration of savings does not impact whether the cost effectiveness of any of these options
falls within the ranges considered reasonable by the EPA.
\b\ For overall cost effectiveness to be considered reasonable, either the cost effectiveness of methane or VOC
on a single pollutant basis must be within the ranges considered reasonable by the EPA, or the cost
effectiveness of both methane and VOC on a multipollutant basis must be within the ranges considered
reasonable by the EPA.
Summary of Control Options Evaluated. In summary, the EPA evaluated
three options for wet-seal centrifugal compressors: (1) Route emissions
to a control device, (2) route emissions to a process, and (3) conduct
maintenance and repair to maintain emissions at or below 3 scfm. The
EPA's relevant analyses found that, for all segments, the costs in
relation to the emission reductions were reasonable for all three
options. However, the options to route captured gas to a control device
or to a process achieve greater emission reductions than conducting
maintenance and repair to maintain 3 scfm. For example, for the
gathering and boosting segment, we estimated that the emissions reduced
under the 3 scfm numerical limit option for a representative
centrifugal compressor to be 89 percent, which is less than the routing
to a control or process options, which achieve 95 percent.\191\
Therefore, the EPA finds that the standard of performance for each
centrifugal compressor using a wet seal is 95 percent reduction of
methane and VOC emissions based on a BSER of capturing and routing
emissions from the wet seal degassing system to a combustion device for
new sources in the gathering and boosting, processing, and transmission
and storage segments. These reductions can also be achieved by routing
emissions from the wet seal degassing system to a process. Therefore,
as a compliance alternative, the EPA proposes to allow owners and
operators to meet the 95 percent standard of performance by routing
emissions from the wet seal degassing system to a process. The EPA
notes that if an owner or operator chooses to route to a process to
meet the 95 percent level of control, there are no secondary impacts.
If an owner or operator chooses to route to a combustion device to meet
the 95 percent level of control, the combustion of the recovered gas
creates secondary emissions of hydrocarbons (NOX,
CO2, and CO emissions).
---------------------------------------------------------------------------
\191\ U.S. Environmental Protection Agency. Supplemental
Background Technical Support Document for the Proposed New Source
Performance Standards (NSPS) and Emissions Guidelines (EG).
Supporting Spreadsheets. August 2022.
---------------------------------------------------------------------------
As discussed in section III.D of this preamble, NSPS KKK includes
standards for controlling VOC emissions from centrifugal compressors
with wet seals at natural gas processing plants. The standards provide
several options for compliance, including: (1) Operating the
centrifugal compressor with the barrier fluid at a pressure greater
than the compressor stuffing box pressure; (2) equipping the
centrifugal compressor with a barrier fluid system degassing reservoir
that is routed to a process or fuel gas system or connected by a CVS to
a control device that reduces VOC emissions by 95 percent or more; or
(3) equipping the centrifugal compressor with a system that purges the
barrier fluid into a process stream with zero VOC emissions to the
atmosphere. NSPS KKK exempts compressors from these requirements if the
compressor is either equipped with a CVS to capture and transport
leakage from the compressor drive shaft back to a process or fuel gas
system or to a control device that reduces VOC emissions by 95 percent,
or if the compressor is designated for no detectable emissions.
For NSPS OOOOb, we are proposing that emissions from each
centrifugal compressor wet seal fluid degassing system require routing
to a control device that achieves a 95 percent reduction of VOC and
methane emissions, or by routing the emissions to a process that
achieves 95 percent reduction of VOC and methane emissions. Proposed
NSPS OOOOb is equivalent to one of the three options available under
NSPS KKK.
Owners and operators of wet seal centrifugal compressors have been
complying with NSPS KKK since 1984. The EPA is requesting comments on
whether it would provide more regulatory consistency for owners,
operators, and implementing agencies if NSPS OOOOb were to incorporate
all compliance options provided in NSPS KKK for wet seal centrifugal
compressors at natural gas processing plants, as opposed to only
proposing the compliance option of routing to a control or process
proposed in this supplemental proposal.
ii. Lower-Emitting/Self-Contained Wet Seal Compressor Designs
The November 2021 proposal solicited comment and information on
lower-emitting wet seal compressor designs. Commenters \192\ reported
that the process for wet seal degassing varies throughout the industry,
and some manufacturers have a configuration that is essentially a
closed process that ports the degassing emissions into the natural
[[Page 74788]]
gas line at the compressor suction. According to one industry commenter
that employs this type of wet seal centrifugal compressor, this
configuration typically includes a primary chamber where initial
degassing occurs (and is recovered), and chamber(s) with air sparging
to release and recover residual gas volumes entrained in the oil.
Rather than venting all of the de-gassing volumes, the emissions are
routed back to suction directly from the degassing/sparging chambers;
the oil is ultimately recycled to the lube oil tank where any small
amount of residual gas is released through a vent. One commenter stated
that field evaluation is not always feasible for this closed system
configuration but reported that testing and modeling demonstrates that
the residual natural gas volume vented is very small (much less than 1
percent of the total degassed natural gas volume). Another commenter
requested that the EPA clarify that certain existing closed-loop wet
seal systems be exempted from any regulatory proposal, or at a minimum,
that such systems should be considered in compliance with the BSER
currently applicable to wet seals.\193\
---------------------------------------------------------------------------
\192\ See Document ID No. EPA-HQ-OAR-2021-0317-0415.
\193\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------
Based on information indicating that closed-loop (self-contained)
systems are inherently low-emitting, the EPA is proposing that these
and similarly designed, self-contained wet seal centrifugal compressors
represent/meet BSER (consistent with the routing to a process or
control option). The EPA is proposing a definition for a ``self-
contained wet seal compressor'' as a ``wet seal compressor system that
is a closed process that ports the degassing emissions into the natural
gas line at the compressor suction (i.e., degassed emissions are
recovered).'' The de-gas emissions are routed back to suction directly
from the degassing/sparging chambers, and the oil is ultimately
recycled to the lube oil tank where any small amount of residual gas is
released through a vent. While the EPA recognizes the low emissions
associated with these self-contained wet seal centrifugal compressors,
we also recognize that there could be increased emissions due to leaks
or malfunctions. Therefore, the proposed rule includes the requirement
that owners or operators of self-contained wet seal centrifugal
compressors must comply with the 3 scfm numerical emission standard
described below for centrifugal compressors with dry seals. As
indicated above, the intent of requiring compliance with the 3 scfm
numerical standard is to ensure that self-contained wet seal
compressors are operating properly (without leaks or malfunctions)
since EPA understands that these compressors emit trivial amounts
(i.e., achieve greater than 99 percent control) when properly operated.
The EPA recognizes that where there is venting of any emissions from
these compressors, emissions would more than likely be nondetectable
for leaks, or would be at a rate lower than 3 scfm. The EPA solicits
comment on, and support for, whether a lower numerical limit is needed
to demonstrate proper operation of self-contained wet seal centrifugal
compressors and/or equivalency to the BSER. The EPA also solicits
comment on the feasibility of measuring the flow rate of self-contained
wet seal centrifugal compressors at a rate lower than 3 scfm.
In addition to wet seal compressor systems that are self-contained,
one commenter \194\ reported information on another wet seal compressor
that was inherently low-emitting. The commenter stated that it has
facilities that use mechanical wet seals that generally have zero
emissions. They explained that the metal (tungsten carbide) is seated
against carbide, with oil pressing against the outside of the actual
seal. They noted that because the oil is not in contact with the
natural gas for these mechanical seals, these wet seals generally have
zero degassing emissions. The commenter requested that the EPA exclude
compressors utilizing mechanical wet seals from the wet seal compressor
requirements otherwise applicable to wet seal compressors. The EPA is
continuing to evaluate mechanical wet seal designs and the comments it
has already received on the issue, and is soliciting additional
information on these and other wet seal compressor designs (with
supporting emissions information) that are inherently low-emitting
under operating conditions.
---------------------------------------------------------------------------
\194\ See Document ID No. EPA-HQ-OAR-2021-0317-0415.
---------------------------------------------------------------------------
iii. Dry Seal Compressors
The EPA solicited comments on dry seal compressor emissions and
whether, and to what degree, operational or malfunctioning conditions
(e.g., low seal gas pressure, contamination of the seal gas, lack of
supply of separation gas, mechanical failure) have the potential to
impact methane and VOC emissions. The EPA further requested information
on whether owners and operators implement standard operating procedures
to identify and correct operational or malfunctioning conditions that
have the potential to increase emissions from dry seal systems, and
whether EPA should consider evaluating BSER and developing NSPS
standards for dry seal compressors.
As the EPA has heard previously, the commenters noted that some dry
seal compressors have higher emissions than compressors with wet seals.
Based on input from a couple of commenters, we estimated the cost
effectiveness of conducting preventative maintenance and repair, as
needed, to maintain the volumetric flow rate from each centrifugal
compressor that uses a dry seal at or below 3 scfm (as done for those
with wet seals). The 3 scfm volumetric flow rate emission limit is the
same monitoring limit included in California's Regulation for
Greenhouse Gas Emission Standards for Crude Oil and Natural Gas
Facilities for wet seal compressors.\195\ California developed the 3
scfm emission standard because this was the equivalent to an average
dry seal emission rate.\196\ The EPA did not evaluate any other control
options for compressors with dry seals because they are inherently low-
emitting; increased emissions are generally the result of either
unforeseen upset conditions or poor maintenance.
---------------------------------------------------------------------------
\195\ California Code of Regulations, Title 17, Division 3,
Chapter 1, Subchapter 10 Climate Change, Article 4, Subarticle 13,
Section 95668(d)(4-9).
\196\ State of California. Air Resources Board Public Hearing to
Consider the Proposed Regulation for Greenhouse Gas Emission
Standards for Crude Oil and Natural Gas Facilities. Staff Report:
Initial Statement of Reasons. pg. 100.
---------------------------------------------------------------------------
To estimate the cost effectiveness of this option, we used the 2019
GHGI ``uncontrolled'' emissions for dry seal compressors as the
baseline.\197\ The ``after control'' emissions levels were calculated
based on a threshold of 3 scfm volumetric flow for 8,760 hours per year
and the representative composition of the gas in the different
segments. This calculation assumes that the emissions are, on average,
3 scfm for the entire year. Table 33 shows the baseline emissions, the
emissions after implementation of the numerical emission limit, and the
emission reductions for dry seal compressors. The 3 scfm volumetric
flow emission limit is the same as described above for wet seal
centrifugal compressors.
---------------------------------------------------------------------------
\197\ GHGI-Dry Seals.
[[Page 74789]]
Table 33--Methane Baseline Emissions and Reductions After Implementation of the Annual Emission Limit
(Requirement to Maintain Flow Rate at or Below 3 scfm) Option--Dry Seal Compressors
----------------------------------------------------------------------------------------------------------------
Methane emissions (tpy) Methane
-------------------------------- emission
Segment After reduction
Baseline \a\ implementation (tpy)
----------------------------------------------------------------------------------------------------------------
Gathering and Boosting.......................................... 36 6 30
Processing...................................................... 28 1 27
Transmission and Storage........................................ 44 6 38
----------------------------------------------------------------------------------------------------------------
\a\ Based on GHGI. Emissions from dry-seal compressors are not estimated for gathering and boosting in the GHGI.
The baseline emissions were calculated from the transmission and storage emissions (adjusted for the
difference in gas composition).
As discussed above for wet seal centrifugal compressors, there is a
wide range in the types of repairs needed (and associated costs) for
dry seal compressors. Given the lack of specific information on these
repairs and costs, we assumed the annual costs to comply with this
option to be $15,000 (without savings). This assumption is lower than
the comparable assumption for wet seals because annual operating and
maintenance costs for compressors with dry seals are lower than for
compressors with wet seals. The EPA specifically solicits comments on
the types of maintenance and corrective actions that may be required to
maintain an emissions rate of 3 scfm or less from centrifugal
compressors with dry seals, along with representative costs.
Because natural gas emissions from a centrifugal compressor with
dry seals would be reduced by maintaining the emission rate at or below
3 scfm, the value of the retained natural gas that would have otherwise
been emitted represents a savings to owners and operators in the
production (gathering and boosting) and processing segments. Savings
were estimated using the emission reductions noted above and a natural
gas price of $3.13 per Mcf, which resulted in annual savings of $2,425
per year at gathering and boosting stations and $1,170 per year at
processing plants.
The estimated cost effectiveness values that would be associated
with conducting maintenance and repair activities to meet a numerical
emission limit of 3 scfm for dry seal compressors are provided in Table
34. In addition to the cost effectiveness values, Table 34 provides a
conclusion regarding whether the estimated cost effectiveness value is
within the range that the EPA has typically considered to be
reasonable. The ``overall'' reasonableness determination is classified
as ``Y'' if the cost effectiveness of either methane or VOC is within
the range that the EPA considers reasonable for that pollutant, or
``N'' if both the methane and VOC cost effectiveness values are beyond
the range the EPA considers reasonable on a multipollutant basis.
Table 34--Summary of Dry Seal Centrifugal Compressor Cost Effectiveness by Industry Segment--Numerical Limit of 3 scfm
--------------------------------------------------------------------------------------------------------------------------------------------------------
Cost effectiveness ($/ton) \a\--reasonable?
----------------------------------------------------------------------------
Segment Single pollutant Multipollutant Overall \b\
----------------------------------------------------------------------------
Methane VOC Methane VOC
--------------------------------------------------------------------------------------------------------------------------------------------------------
Gathering and Boosting..................................... 930-Y 3,346-Y $465-Y $1,673-Y Y
Processing................................................. 1,927-Y 6,933-N 964-Y 3,467-Y Y
Transmission and Storage................................... 831-Y 29,997-N 415-Y 14,999-N Y
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ For the gathering and boosting and processing segments, the owners and operators realize the savings for the natural gas that is not emitted and
lost. The cost effectiveness values shown do not consider these savings. Note that the consideration of savings does not impact whether the cost
effectiveness of any of these options falls within the ranges considered reasonable by the EPA.
\b\ For overall cost effectiveness to be considered reasonable, either the cost effectiveness of methane or VOC on a single pollutant basis must be
within the ranges considered reasonable by the EPA, or the cost effectiveness of both methane and VOC on a multipollutant basis must be within the
ranges considered reasonable by the EPA.
Based on the consideration of the costs in relation to the emission
reductions for methane shown in Table 34, the costs to implement the
option to conduct preventative repair and maintenance so that each
centrifugal compressor with a dry seal maintains a volumetric flow rate
at or below 3 scfm is reasonable for all segments under both the single
pollutant and multipollutant approaches. Based on the consideration of
the costs in relation to the emission reductions for VOC, the costs of
this option are reasonable for the gathering and boosting segment under
both the single pollutant and multipollutant approaches. For the
processing segment, the costs for reducing VOC emissions are reasonable
under the multipollutant approach, but not the single pollutant
approach. Costs for reducing VOC emissions would not be reasonable for
implementing this approach for the transmission and storage segment.
Given that the costs of conducting preventative repair and maintenance
activities in order to maintain the volumetric flow rate from each
centrifugal compressor with a dry seal at or below 3 scfm are
reasonable, the EPA is proposing this option as BSER for compressors
with dry seals.
c. Summary of 2022 Proposal
i. Affected Facility
Based on changes made and discussed in section IV.G.1.b of this
preamble, the EPA is proposing to redefine the affected facility to
include dry seal centrifugal compressors in addition to wet seal
centrifugal compressors. Therefore, a centrifugal compressor affected
facility would be defined as a single centrifugal compressor. Further,
the EPA is maintaining the proposed
[[Page 74790]]
specifications from the November 2021 proposal as applicable to
centrifugal compressors located at well sites and centralized
production facilities. Specifically, centrifugal compressors located at
centralized production facilities would be considered affected
facilities, while those located at well sites would not be affected
facilities under NSPS OOOOb.
ii. Requirements
Wet Seal Centrifugal Compressors. The EPA is proposing that owners
or operators of centrifugal compressor affected facilities with wet
seals must comply with the GHG and VOC standards by reducing methane
and VOC emissions from each centrifugal compressor wet seal fluid
degassing system by 95 percent. As an alternative to routing the CVS to
a control device, an owner or operator may also route the CVS to a
process or utilize a self-contained wet seal centrifugal compressor. If
an owner or operator chooses to comply with this requirement either by
using a control device to reduce emissions or by routing to a process
to reduce emissions, an owner or operator must equip the wet seal fluid
degassing system with a cover and the cover must be connected through a
CVS meeting specified requirements (40 CFR 60.5411b(a) through (c)),
such as design and operation with no identifiable emissions, as
described in section IV.K of this preamble. If an owner or operator
uses a self-contained wet seal centrifugal compressor, an owner or
operator must ensure a volumetric flow rate at or below 3 scfm. In
addition to the flow rate monitoring required every 8,760 hours,
additional preventative or corrective measures may be required to
ensure compliance.
Dry Seal Centrifugal Compressors. The EPA is proposing that the
standard of performance for centrifugal compressor dry seals is 3 scfm.
The proposed BSER is for an owner or operator to conduct preventative
maintenance and repair of their centrifugal compressors that use dry
seals, as needed, to maintain the volumetric flow rate from each
centrifugal compressor that uses a dry seal at or below 3 scfm. Owners
and operators of centrifugal compressors with dry seals must conduct
volumetric emissions measurements from each centrifugal compressor dry
seal vent on or before 8,760 hours of operation or previous measurement
and must use specified methods (similar to the flow rate monitoring
requirements specified under the GHGRP subpart W) in doing so. Owners
or operators must ensure that the volumetric emission measurements (in
operating mode or in stand-by-pressurized-mode) from each centrifugal
compressor dry seal vent are less than or equal to a flow rate 3 scfm
(in operating or standby pressurized mode) or a manifolded dry seal
compressor flow rate less than or equal to the number of compressors
multiplied by 3 scfm (in operating or standby pressurized mode). As
discussed in section IV.I the EPA is proposing the use of volumetric
flow rate which meet the requirements of Method 2D (40 CFR part 60,
appendix A) for testing emissions from reciprocating compressor rod
packing and the use of a high-volume sampler to measure the emissions
from either the reciprocating compressor rod packing or centrifugal
compressor seal vent (dry seals for NSPS OOOOb and all centrifugal
compressor wet and dry seals for EG OOOOc). For the high-volume
sampler, instead of relying on manufacturer defined procedures required
in GHGRP Subpart W, the EPA is proposing a defined set of procedures
and performance objectives to ensure consistent application of these
samplers. In an effort to allow for additional innovation for these
types of measurements, the EPA is also proposing to allow other
methods, subject to Administrator approval, that have been validated
according to Method 301 (40 CFR part 63, appendix A). Preventative
maintenance or other corrective actions may be necessary (in addition
to the monitoring every 8,760 hours of operation) in order for owners
or operators to ensure compliance at all times (consistent with the
general duty clause 40 CFR 60.5470b(b)) with the required flow rate of
3 scfm or less.
Recordkeeping and Reporting Requirements. Specific recordkeeping
and reporting requirements would also apply for each wet seal
centrifugal compressor affected facility. Specifically, records and
annual reporting that identifies each centrifugal compressor using a
wet seal system that was constructed, modified, or reconstructed during
the reporting period would be required. In instances where a deviation
from the standard occurred during the reporting period and recorded, an
owner or operator would be required to provide information on the date
and time the deviation began, the duration of the deviation, and a
description of the deviation.
For centrifugal compressors where compliance is achieved by using a
control device to reduce emissions, the following information would be
required in the annual report: dates of the cover and CVS inspections,
whether defects or leaks are identified, and the date of repair or the
date of anticipated repair if repair is delayed. Where bypass
requirements apply, reporting of the date and time of each bypass alarm
or each instance the key is checked out would be required.
If complying with the centrifugal compressor requirements for wet
seal fluid degassing system by reducing VOC and methane emissions by 95
percent using a control device tested by the device manufacturer, the
annual report must include: the identification of the compressor with
the control device and the make, model, and date of purchase of the
control device. An owner or operator would also be required to record
and report the following: (1) Each instance where there is an inlet gas
flow rate exceedance, (2) each instance where there is no indication of
a pilot flame, and (3) each instance where there was a visible
emissions exceedance. The annual report would be required to include
the date and time the deviation began, the duration of the deviation,
and a description of the deviation. Finally, for each visible emissions
test following return to operation from a maintenance or repair
activity, the annual report would be required to include the date of
the visible emissions test, the length of the test, and the amount of
time visible emissions were present.
If complying with the centrifugal compressor requirements for a wet
seal fluid degassing system by reducing VOC and methane emissions by 95
percent by using a control device not tested by the device
manufacturer, the following information must be included in the annual
report: identification of the control device not tested by the device
manufacturer, the identification of the compressor with the tested
control device, the date the performance test was conducted, the
pollutant(s) tested, and the performance test report conducted to
demonstrate that the control device is achieving, at a minimum, the
required 95 percent reduction.
For each dry seal centrifugal compressor affected facility and
self-contained wet seal centrifugal compressor affected facility,
owners and operators would be required to track and report the
cumulative number of hours of operation since startup since the
previous screening/volumetric emissions measurement in order to
demonstrate compliance with their volumetric emissions measurements.
Additionally, a description of the method used and the results of the
volumetric emissions measurement or
[[Page 74791]]
emissions screening, as applicable, would be required in the annual
report.
2. EG OOOOc
a. Summary of 2021 Proposal
The summary of the November 2021 proposal for EG OOOOc is
consistent with what was proposed for NSPS OOOOb (see section IV.G.1.a
of this preamble).
b. Changes to Proposal and Rationale
The EPA is proposing changes and specific clarifications to the
November 2021 proposal presumptive standards for the EG OOOOc.
Specifically, we are proposing to: (1) Revise the designated facility
definition to include all centrifugal compressors, (2) include a
numerical emission limit requirements for dry and wet seal compressors,
and (3) allow owners and operators the option to comply with EG OOOOc
by reducing methane emissions by 95 percent by either routing to a
control device or to a process. The basis for these changes is
presented below.
Wet Seal Centrifugal Compressors. Industry commenters expressed
particular concern about having to retrofit existing wet seal
centrifugal compressors to accommodate the November 2021 proposal that
would have required owners and operators to reduce methane emissions
from each centrifugal compressor wet seal fluid degassing system by 95
percent or greater. One commenter \198\ stated that the November 2021
proposal for wet seal centrifugal compressors would require
installation of an enclosed combustion device or a process flare in
nearly every case for their facilities. The commenter noted that, while
theoretically an enclosed combustion device could be installed to
control the minimal emissions on an individual wet seal compressor, a
combustion device cannot be located just anywhere, especially not in
close proximity to a transmission compressor station. The commenter
noted that a combustion device must be strategically located away from
combustible materials, which typically requires a significant
footprint, aboveground piping (above roadways), and in an elevated
location. In order to install such a device, they stated that they
would likely have to apply for and receive state and local permit
modifications, which are not certain to be approved in each case. The
commenter also stated that routing to a control device could present
safety concerns. For example, they note that attempts to capture a low-
pressure natural gas vent stream, such as that of the wet seal, could
result in inducing air into the gas stream, potentially creating a
combustible mixture. The commenter reports that one manufacturer has
previously ``caution[ed] the use of flaring with gas seal vented
emissions due to risk of the potential explosive hazard and back-
flashing.'' \199\ The commenter reports that it is ``[their] view
(concurrent with many users of our equipment) [that] flaring of
compressor seal emissions can introduce inherently dangerous conditions
with the potential for back-flashing and serious risk of explosion.
Solar therefore discourages flaring for this reason although some
customers have successfully implemented it.''
---------------------------------------------------------------------------
\198\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
\199\ See Document ID No. EPA-HQ-OAR-2021-0317-1375.
---------------------------------------------------------------------------
With respect to the routing to process option, the same commenter
notes that, while theoretically feasible, a low flow gas stream (like
their facilities' gas streams) cannot be safely or technically re-
introduced back into their processes without significant, resource-
intensive, attention to that minor emissions stream. According to the
commenter, the unintended result would be that the additional equipment
that would need to be installed to accomplish this routing back to
process would not only be costly (discussed below) but could also
result in additional emissions from other sources.
Based on these concerns, for existing wet seal centrifugal
compressors, the EPA is no longer proposing that BSER is 95 percent
reduction of methane emissions by routing emissions to a control device
or process. Instead, based on the updated analysis presented in this
supplemental proposal, the EPA is proposing that the standard of
performance for existing sources is a numerical emission limit of 3
scfm; the BSER is for an owner or operator to conduct preventative
maintenance and repair of their centrifugal compressors that use wet
seals, as needed, to maintain the volumetric flow rate from each
centrifugal compressor that uses a wet seal at or below 3 scfm. Owners
or operators would be required to conduct volumetric flow rate
measurements at least every 8,760 hours. As a compliance alternative,
the EPA is proposing to allow owners and operators the option to reduce
methane emissions by 95 percent or greater by routing emissions to a
control device or to a process, which would achieve emissions
reductions equal to or greater than the standard of performance of 3
scfm. The cost of application of the numerical emission limit
requirement at an existing source is the same as at a new source, and
the methane cost effectiveness would be the same as discussed in the
previous section for wet seal centrifugal compressors subject to NSPS
OOOOb. The cost effectiveness (without natural gas savings) of
complying with the numerical emission limit for methane emissions is
approximately $111 per ton of methane emissions reduced for the
gathering and boosting segment, $183 per ton of methane emissions
reduced for the processing segment, and $711 per ton of methane
emissions reduced for the transmission and storage segment. Considering
natural gas savings, the cost effectiveness of complying with the
numerical emission limit for methane emissions is an overall net
savings for the gathering and boosting segment, and $28 per ton of
methane emissions reduced for the processing segment.
As discussed in section IV.G.1.i of this preamble NSPS KKK includes
standards for controlling VOC emissions from centrifugal compressors
with wet seals at natural gas processing plants. The standards provide
several options to comply, including: (1) Operating the centrifugal
compressor with the barrier fluid at a pressure that is greater than
the compressor stuffing box pressure; (2) equipping the centrifugal
compressor with a barrier fluid system degassing reservoir that is
routed to a process or fuel gas system or connected by a CVS to a
control device that reduces VOC emissions by 95 percent or more; or (3)
equipping the centrifugal compressor with a system that purges the
barrier fluid into a process stream with zero VOC emissions to the
atmosphere. NSPS KKK exempts compressors from these requirements if the
compressor is either equipped with a CVS to capture and transport
leakage from the compressor drive shaft back to a process or fuel gas
system or to a control device that reduces VOC emissions by 95 percent,
or if the compressor is designated for no detectable emissions.
For EG OOOOc, the proposed presumptive standard would be a
numerical emission limit of 3 scfm and include an alternative
compliance method of reducing methane emissions by 95 percent by
routing to a control or process. The proposed presumptive standard of 3
scfm is less stringent than the regulatory compliance options under
NSPS KKK for centrifugal compressor at natural gas processing plants.
Owners and operators of wet seal centrifugal compressors have been
complying with NSPS KKK since 1984. The EPA is requesting comments on
whether it would provide more
[[Page 74792]]
regulatory consistency for owners, operators, and implementing agencies
if EG OOOOc were to incorporate all compliance options provided in NSPS
KKK for wet seal centrifugal compressors at natural gas processing
plants instead of the 3 scfm emission limitation.
Dry Seal Compressors. The application of the numerical emission
limit option at an existing source is the same as at a new source
because no additional equipment must be installed in order to comply
with the standards. Therefore, the cost of control would also be the
same (see section IV.G.1.b.i of this preamble). As a result, based on
the consideration of the costs in relation to the emission reductions
for methane, the costs to implement the numerical emission limit is
reasonable for all segments. Given that the costs of reducing methane
emissions by the implementation of the numerical emission limit are
reasonable, the EPA is proposing this option as BSER for existing
centrifugal compressors with dry seals.
c. Summary of 2022 Proposal
i. Designated Facility
Based on changes made and discussed under section IV.F.2.b of this
preamble, the EPA is proposing to redefine the designated facility to
include dry seal compressors in addition to wet seal compressors.
Specifically, the designated facility is defined as a single
centrifugal compressor. Further, the EPA is proposing that centrifugal
compressors located at centralized production facilities would be
designated facilities, while centrifugal compressors located at well
sites would not be designated facilities, consistent with the November
2021 proposal.
ii. Requirements
Wet and Dry Seal Centrifugal Compressors. The EPA is proposing that
owners or operators of centrifugal compressors with wet and dry seals
be required to conduct volumetric emission measurements (in operating
mode or in stand-by-pressurized-mode) from each centrifugal compressor
dry and wet seal vent using specified methods (similar to the flow rate
monitoring requirements specified under GHGRP subpart W). Owners and
operators would be required to conduct volumetric emissions
measurements from each centrifugal compressor wet and dry seal vent on
or before 8,760 hours of operation or previous measurement.
The volumetric emissions measurement of the centrifugal compressor
wet and dry seal vent must be maintained to be less than or equal to a
flow rate of 3 scfm (in operating or standby pressurized mode) or a
manifolded dry and wet seal compressor flow rate less than or equal to
the number of compressors multiplied by 3 scfm (in operating or standby
pressurized mode). The same requirements specified in IV.G.1.c of this
preamble for dry seal compressors complying with the numerical emission
limit being proposed for NSPS OOOOb are being proposed for self-
contained wet seal centrifugal compressors under NSPS OOOOb and for dry
and wet seal centrifugal compressors complying with this option under
EG OOOOc.
Compliance Alternative for Wet Seal Compressors. As a compliance
alternative to maintaining a flow rate at or below 3 scfm, the EPA is
proposing that an owner or operator of a centrifugal compressor
equipped with wet seals can comply with EG OOOOc by reducing methane
emissions from each centrifugal compressor wet seal fluid degassing
system by 95 percent, which achieves emission reductions greater than
or equal to the 3 scfm proposed presumptive standard. Options to meet
this emission reduction requirement include routing emissions via a CVS
to a control device or to the process. This standard can also be met by
an owner or operator utilizing a self-contained wet seal centrifugal
compressor. The same requirements specified in IV.G.1.c for wet seal
compressors complying with the requirements to reduce methane emissions
from each centrifugal compressor wet seal fluid degassing system by 95
percent are being proposed for wet seal compressors complying with this
option under EG OOOOc.
H. Combustion Control Devices
1. November 2021 Proposal
The EPA proposed requiring 95 percent methane and VOC reduction for
certain affected/designated facilities (i.e., storage vessels, wet seal
centrifugal compressors, and associated gas from oil wells when a sales
line is not available) and solicited comments on several aspects of the
operational efficiency of combustion control devices and methods to
ensure continuous compliance with the required control efficiency.
Specifically, in the November 2021 proposal, the EPA solicited comments
on whether additional measures to ensure proper performance of flares
would be appropriate to ensure that flares meet the current 95 percent
control requirement. The EPA solicited similar comments for enclosed
combustion devices, particularly regarding creating comprehensive
specifications for an operating envelope under which a make/model can
achieve 98 percent reduction. The EPA also solicited comments on the
practicality of requiring combustion and non-combustion control systems
to meet a 98 percent reduction control requirement under operating
conditions present in the oil and gas industry. Finally, the EPA
solicited comment on new technologies that would provide real-time or
near real-time measurement of control efficiency, particularly for
flares.
2. Changes From November 2021 Proposal
The EPA received comments on most aspects of the solicitation for
comments in the November 2021 proposal related to combustion control
devices, ranging from opposition to requirements as specific as
continuous pilots to recommendations for the use of advanced
technologies to continuously monitor flare combustion efficiency. As
described throughout this section, the EPA is proposing specific
additional requirements in response to comments on the November 2021
proposal and clarifying other requirements that were proposed in that
action.
In this supplemental proposal, the EPA is proposing requirements
for various combustion control devices to develop consistent
monitoring, recordkeeping, and reporting requirements, regardless of
the affected/designated facility with which the control device is
associated. This is different than the compliance requirements for
control devices in NSPS OOOOa, which has separate requirements for
control devices used on storage vessel affected facilities, than those
used on centrifugal compressor affected facilities. The proposed
monitoring, recordkeeping, and reporting requirements related to
control devices are designed to ensure that these systems achieve the
required control efficiency, and they were established using methods
that limit the burden for owners and operators, while still ensuring
compliance with the required control efficiency.
Flares. The EPA is proposing to include in both NSPS OOOOb and EG
OOOOc more comprehensive monitoring requirements for flares as
referenced to the General Provisions at 40 CFR 60.18. Specifically, the
General Provisions at 40 CFR 60.18 indicate four criteria needed for
good flare performance. These are: (1) Continuous pilot flame; (2) no
visible emissions except for a total of 5 minutes in a 2-
[[Page 74793]]
hour period; (3) minimum net heating value of gas sent to the flare;
and (4) maximum flare tip velocity. In NSPS OOOO and NSPS OOOOa, the
compliance requirements for flares include criteria to address
compliance with items 1 and 2 but do not include any requirements that
would ensure compliance with items 3 and 4 for any affected facilities
which reference flares as a control device option. That is, those
rules, which adopt by reference the flare requirements in 40 CFR 60.18
(i.e., the General Provisions to 40 CFR part 60) do not include
specific requirements specifying the minimum net heating value of gas
sent to the flare or the maximum flare tip velocity. One commenter on
the November 2021 proposal stated that the EPA must establish
continuous monitoring requirements for flares regardless of the control
efficiency required.\200\ One commenter noted that the General
Provisions at 40 CFR 60.18 state that the referencing subpart will
specify the monitoring requirements and indicated that the EPA must
specify these requirements in the new standards.\201\ The EPA agrees
with these commenters, especially noting that recent studies suggests
that 10 percent of flares in the Permian basin are either unlit or are
only burning a portion of the gas sent to the flare.\202\ Consequently,
the EPA concludes that the current operating and monitoring practices
and requirements for well sites and centralized production facilities
are not adequate to ensure flare control systems are operated
efficiently and is therefore, proposing compliance requirements to
ensure all aspects of the General Provisions at 40 CFR 60.18 are met at
all times. These include requirements to ensure a pilot flame is
present at all times through monitoring with a device such as a
thermocouple, ultraviolet beam sensor, or infrared sensor and
monitoring of NHV through use of a calorimeter, unless a demonstration
has been made that the NHV of the inlet gas to the flare consistently
exceeds the operating limit established in the rule. In other
rulemakings, for example recent amendments to the refining \203\ and
chemical sector \204\ rules, monitoring of the net heating value in the
combustion zone, instead of the heating value of the vent gas is
required. While this is important for an assisted flare, we anticipate
the oil and gas source category predominately will use unassisted
flares, because air-assisted flares require electricity and not all
sites will have access to electricity. The EPA finds that the
provisions at 40 CFR 60.18 are sufficient for unassisted flares because
the heat content of the gas at the flame is not diluted by an assist
stream of gas or air. The EPA requests comment on the universe of
unassisted and assisted flares in the oil and gas sector. See section
IV.H.3 of this preamble for details of the proposed compliance
requirements for flares.
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\200\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0844 and EPA-HQ-
OAR-2021-0317-1282.
\201\ See Document ID No. EPA-HQ-OAR-2021-0317-1282.
\202\ Permian Methane Analysis Project (PermianMAP) reporting
the results of 4 Environmental Defense Fund (EDF) surveys of over a
thousand flare stacks from February to November 2020. See https://www.permianmap.org/flaring-emissions.
\203\ See 80 FR 75266 (December 1, 2015).
\204\ See 85 FR 49132 (August 12, 2020).
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Enclosed Combustors. The EPA is proposing the same monitoring
requirements for enclosed combustion devices for all affected
facilities that use such devices to meet the applicable standards. We
are also proposing monitoring requirements for enclosed combustion
devices (which are not tested by the manufacturer) for which the
performance test does not correlate the combustion efficiency achieved
by the combustion device with temperature. (i.e., temperature is not
well correlated with combustion efficiency). NSPS OOOO and OOOOa have
separate monitoring requirements for control devices used for
centrifugal compressor affected facilities than for control devices
used for storage vessel affected facilities. This difference goes back
to the EPA's understanding of the landscape of the oil and gas industry
during the rulemaking process for NSPS OOOO and subsequent amendments
through 2016 which resulted in the promulgation of NSPS OOOOa.
Centralized production facilities were not identified within the EPA's
emissions inventory, and the EPA found that storage vessels were mostly
located at well sites which did not have other affected facilities
requiring control. The EPA expected these sites to take advantage of
the reduced compliance burden by using control devices tested by the
manufacturer. Further, during the reconsideration of aspects of NSPS
OOOO, the EPA determined that streamlined compliance options were
warranted for storage vessel affected facilities, in part because of
implementation issues at remote sites and the large number of storage
vessel affected facilities.\205\ In this action, the EPA is proposing
standards for additional affected facilities at well sites (i.e., oil
wells with associated gas that is routed to a control device) and
defining centralized production facilities (which include storage
vessel and compressor affected facilities requiring 95 percent
control). The EPA finds that the rationale used in NSPS OOOO and NSPS
OOOOa supporting streamlined monitoring for storage vessels no longer
holds true. Remote well sites still exist, but these sites also may be
subject to standards for oil well with associated gas and the
compliance burden is shared between those affected facilities to ensure
emissions from both storage vessels and oil wells with associated gas
are reduced by 95 percent. Further, the centralization of production
activities makes moot the concern about remote wells sites for these
centralized production facilities. As mentioned previously, recent
studies such as the study conducted in the Permian, indicate pervasive
issues with combustion sources \206\ and enforcement activities
conducted by the EPA and states have uncovered issues with proper
operation of enclosed combustors on storage vessels.\207\ For these
reasons, the EPA is proposing to align the monitoring requirements in
NSPS OOOOb and EG OOOOc to ensure that all control devices are subject
to the same monitoring requirements, regardless of the affected
facility being controlled.
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\205\ See 78 FR 58438 (September 23, 2013) and 81 FR 35897 (June
3, 2016).
\206\ Permian Methane Analysis Project (PermianMAP) reporting
the results of 4 Environmental Defense Fund (EDF) surveys of over a
thousand flare stacks from February to November 2020. See https://www.permianmap.org/flaring-emissions.
\207\ ``EPA Observes Emissions from Controlled Storage Vessels
at Onshore Oil and Gas Production Facilities.'' See https://www.epa.gov/sites/default/files/2015-09/documents/oilgascompliancealert.pdf.
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For thermal oxidizers/enclosed combustors for which temperature is
correlated with combustion efficiency and for catalytic oxidizers, the
EPA is proposing to include in NSPS OOOOb and EG OOOOc the same
monitoring requirements as required under NSPS OOOOa for centrifugal
compressor affected facilities, and consistent with the rationale in
this discussion, we are proposing to require these monitoring
requirements for all enclosed combustion devices, regardless of the
affected facility being controlled. Further, the EPA is proposing
additional initial compliance requirements for vapor recovery devices
and catalytic vapor incinerators, to ensure owners and operators have a
clear roadmap for initial compliance. Similarly, the EPA is proposing
additional continuous compliance requirements which specify how to
determine continuous compliance with the requirements for
[[Page 74794]]
catalytic vapor incinerators, regenerative-type carbon adsorption
systems, and carbon management for regenerative-type and
nonregenerative-type carbon adsorption systems.
The EPA is also proposing monitoring requirements for enclosed
combustion devices not tested by a manufacturer for which temperature
is not well correlated with combustion efficiency. For enclosed
combustors for which temperature is not well correlated with combustion
efficiency, the EPA is proposing to incorporate requirements similar to
those proposed for flares, as the operation of these devices is similar
to the operation of a flare in that the combustibility of the gas
(NHV), operation without smoking (visible emissions) and a continuous
burning pilot flame are fundamental to ensuring 95 percent combustion.
One commenter suggested that monitoring of the pilot flame for enclosed
combustors was sufficient to provide assurance of effective emission
control.\208\ However, no data were provided to support this assertion
and available data and combustion theory science suggests that the net
heating value of the gas being sent to the combustor is also critical
to ensure proper combustion. As good combustion depends upon the fuel
having a minimum amount of heat content, if the gases from the affected
facility required to be controlled have low heat content at times, then
auxiliary fuel may be necessary to ensure good combustion during those
periods. That is, the same requirements that are needed to ensure
proper performance of flares also apply to enclosed combustors. Because
enclosed combustors often are associated with storage vessels which
have variable emissions events depending on working, breathing,
standing, or flashing losses, the EPA also is proposing that enclosed
combustors monitor inlet flow rate to ensure the control device
operates within the compliance envelope at which compliance with the 95
percent control efficiency was demonstrated.
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\208\ See Document ID No. EPA-HQ-OAR-2021-0317-0749.
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Condensers and Carbon Adsorption Systems. The EPA is proposing
consistent monitoring requirements for condensers and carbon adsorption
systems independent of the affected facility. NSPS OOOOa has specific
compliance requirements for condensers and carbon adsorption systems
used to control emissions from centrifugal compressor affected
facilities but less specific compliance requirements for vapor recovery
devices used for storage vessel affected facilities. In NSPS OOOOa,
owners and operators are required to conduct specific parameter
monitoring for condensers and carbon adsorption systems used to control
emissions from centrifugal compressor affected facilities, while owners
and operators are only required to conduct monthly inspections ``. . .
to ensure physical integrity of the control device according to the
manufacturer's instructions'' for vapor recovery devices used to
control storage vessel affected facilities. Monthly inspections do not
ensure the condenser temperature is adequate or that the carbon beds
are changed out or regenerated at a frequency to ensure the control
device is achieving at least 95 percent control efficiency. Therefore,
in NSPS OOOOb and EG OOOOc, the EPA is proposing that all affected and
designated facilities that use condensers or carbon adsorption systems
must meet the same monitoring requirements as outlined for centrifugal
compressor affected facilities in NSPS OOOOa.
Manufacturer Tested Control Devices. The EPA is proposing to
require the same initial requirements for manufacturer testing of
control devices and ancillary monitoring requirements as required in
NSPS OOOO and NSPS OOOOa. In NSPS OOOO and NSPS OOOOa, the EPA included
this alternative to minimize issues associated with performance testing
of certain combustion control devices in the field. The requirements
were based on similar requirements in the oil and natural gas NESHAP
(40 CFR part 63, subparts HH and HHH) and which had been successfully
implemented for some time prior to the promulgation of NSPS OOOO and
NSPS OOOOa. In the 2011 proposal of the provisions for NSPS OOOO, we
stated ``[w]e believe that testing units that are not configured with a
distinct combustion chamber present several technical issues that are
more optimally addressed through manufacturer testing, and once these
units are installed at a facility, through periodic inspection and
maintenance in accordance with manufacturers' recommendations. One
issue is that an extension above certain existing combustion control
device enclosures will be necessary to get adequate clearance above the
flame zone. Such extensions can more easily be configured by the
manufacturer of the control device rather than having to modify an
extension in the field to fit devices at every site. Issues related to
transporting, installing and supporting the extension in the field are
also eliminated through manufacturer testing. Another concern is that
the pitot tube used to measure flow can be altered by radiant heat from
the flame such that gas flow rates are not accurate. This issue is best
overcome by having the manufacturer select and use the pitot tube best
suited to their specific unit. For these reasons, we believe the
manufacturers' test is appropriate for these control devices with
ongoing performance ensured by periodic inspection and maintenance. (76
FR 52785; August 23, 2011).
Control Efficiency. As mentioned earlier in this section, the EPA
requested comment on whether the EPA should require 98 percent
reduction of methane and VOC emissions instead of 95 percent in the
November 2021 proposal. The EPA received comments stating that flares
can be designed to meet 98 percent control efficiency,\209\ but we also
received comments stating that variability in gas flow, pressure, and
quality would present challenges to achieving 98 percent control
efficiency, especially at low production wells.\210\
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\209\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0604, EPA-HQ-
OAR-2021-0317-0605, EPA-HQ-OAR-2021-0317-0844, and EPA-HQ-OAR-2021-
0317-1286.
\210\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0599, EPA-HQ-
OAR-2021-0317-0808, and EPA-HQ-OAR-2021-0317-0831.
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The EPA evaluated the costs associated with requiring 98 percent
reduction of methane and VOC emissions from storage vessels in order to
compare the cost-effectiveness for this option against the costs
associated with requiring 95 percent reduction. While the analysis was
specific for storage vessels, the conclusions drawn from this analysis
are generally applicable to other affected facilities because the size
range of control devices evaluated cover the range of controls used for
other affected facilities. Based on this evaluation, we conclude that
the additional reduction is not cost effective and would therefore not
represent the BSER for affected sources requiring an emissions
reduction through the use of a pollution control device. Specifically,
using this example for storage vessel affected facilities, the EPA
added the additional monitoring and operational costs expected to
ensure a 98 percent minimum destruction efficiency and found that it
would not be cost-effective to require control of storage vessels with
the potential for VOC emissions below 12 tpy or methane emissions below
40 tpy. However, at 95 percent reduction, it is considered cost-
effective to require control of storage vessels with potential VOC
emissions of 6 tpy and methane
[[Page 74795]]
emissions of 20 tpy.\211\ Therefore, requiring 98 percent reduction of
methane and VOC results in the control of fewer storage vessels, and
thus result in fewer overall emissions reductions. Consequently, the
EPA is proposing to maintain that the BSER for storage vessel affected
facilities is 95 percent reduction, as described in section IV.J of
this preamble. Because the analysis conducted covers the range of
control device sizes utilized by other affected facilities, similar
impacts on the BSER analysis are expected. Furthermore, because
individual sites would utilize a single control device for all
affected/designated facilities, it does not make sense to require
different emissions reduction standards for different affected/
designated facilities. For more detail on the analysis conducted to
assess the costs of control device monitoring see memorandum Analysis
of Monitoring Costs to Ensure 98 Percent Destruction Efficiency,
available in the docket for this action (Docket ID No. EPA-HQ-OAR-2021-
0317).
---------------------------------------------------------------------------
\211\ The costs associated with the monitoring requirements
necessary to ensure a 95 percent reduction in methane and VOC
emissions is achieved were included in the cost analysis provided in
the November 2021 proposal. See the 2021 TSD for additional details
at Document ID No. EPA-HQ-OAR-2021-0317-0166 and accompanying
spreadsheets at Document ID No. EPA-HQ-OAR-2021-0317-0039.
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3. Summary of Proposed Requirements for NSPS OOOOb and EG OOOOc
The EPA is proposing that control devices used for any affected
facility must demonstrate that they meet a 95 percent VOC and methane
emission reduction requirement through a performance test (or for
condensers and carbon absorbers, through a design evaluation) or
manufacturer's performance test.
In NSPS OOOOb and EG OOOOc, we are proposing the same control
device requirements for thermal vapor incinerators (including thermal
oxidizers and enclosed combustors) for which temperature is correlated
with destruction efficiency, catalytic vapor incinerators, condensers,
and carbon adsorption systems as were required in NSPS OOOOa (for
centrifugal compressor affected facilities). We are proposing that
these requirements apply to all affected facilities complying with the
standards by using one of these control devices.
The EPA is proposing requirements for flares to be designed and
operated according to the provisions in 40 CFR 60.18 for all flares,
regardless of the affected facility type, except as noted below for
pressure-assisted devices. Further, we are proposing to require these
same general requirements for enclosed combustors not tested by the
manufacturer and for which temperature is not correlated with control
device performance. NSPS OOOO and NSPS OOOOa do not include criteria to
determine that temperature is (or is not) correlated with control
device performance. Criteria where temperature is well correlated could
include requirements that air flow to the burner is controlled and that
there is sufficient refractory in the stack to maintain high
temperature even at low flows. The EPA requests comment on whether
criteria should be developed for NSPS OOOOb and EG OOOOc, which
delineate when temperature is (or is not) correlated with control
device performance, and if so, in addition to the criteria above, what
criteria would be appropriate. The EPA is proposing to include
consistent initial and continuous compliance requirements to ensure
flares and enclosed combustion devices are maintaining efficient
combustion. As discussed previously in this section, there are 4
critical requirements in 40 CFR 60.18 that must be met to ensure proper
destruction efficiency.\212\ The proposed continuous compliance
requirements for each of these critical elements are described in the
following paragraphs.
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\212\ The four requirements are: (1) Continuous pilot flame; (2)
no visible emissions except for a total of 5 minutes in a 2-hour
period; (3) minimum net heating value of gas sent to the flare; and
(4) maximum flare tip velocity.
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First, the EPA is proposing to require all flares and enclosed
combustion devices \213\ to have a continuous pilot flame and install a
continuous parameter monitoring system capable of continuously (at
least once every 5 minutes) monitoring for the presence of a pilot or
combustion flame. This is in keeping with the requirements of the
General Provisions to require a continuous pilot flame. The EPA is
specifying more frequent monitoring intervals for the pilot light than
for other continuous parameter monitoring systems (which require a
minimum of one reading per hour) because the destruction efficiency
will rapidly fall to zero in the absence of a pilot or combustion
flame. Therefore, we determined that more frequent readings were needed
for the pilot flame monitoring system to ensure the flare or enclosed
combustion device achieves 95 percent destruction efficiency at all
times.
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\213\ This discussion in the rest of this section applies to
those enclosed combustion devices for which temperature is not
correlated with destruction efficiency.
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Second, the EPA is proposing to require inspections to monitor for
visible emissions using section 11 of EPA Method 22 of appendix A-7 of
part 60 (EPA Method 22). The observation period for the EPA Method 22
inspection would be 15 minutes. Visible emissions longer than 1 minute
during the 15-minute period would be a deviation of the standard. This
is consistent with similar requirements in NSPS OOOOa. The EPA is
proposing that these inspections would occur monthly, and at other
times as requested by the Administrator. For example, if the
Administrator observed a flare with intermittent visible emissions, the
Administrator may require the owner or operator to conduct an EPA
Method 22 inspection to determine whether the flare is exceeding the
visible emissions limit.
Next, the EPA is proposing that flares and enclosed combustion
devices monitor the net heating value of the vent gas sent to the flare
or combustor. Owners and operators would install a continuous parameter
monitoring system, such as a calorimeter, to continuously determine the
net heating value of the gas sent to the flare or combustor.
Alternatively, the owner or operator could conduct an initial
assessment to demonstrate that the net heating value of the vent gas
sent to the flare or combustor consistently exceeds the required
minimum net heating value in 40 CFR 60.18 or the minimum net heating
value proposed for pressure-assisted flares.\214\ The proposed initial
demonstration consists of hourly monitoring over 10 days. The EPA is
proposing this frequency and duration of monitoring in order to provide
a large sampling set by which to assess the variability of the vent gas
sent to the combustion device and to adequately characterize the tails
of the distribution. When actively controlling net heating value,
operators will generally control at a set point 10 to 20 percent higher
than the limit to ensure they are meeting the limit at all times.
Therefore, the EPA concluded that a 20 percent cushion was a reasonable
minimum value for ``well above the threshold.'' To be considered
consistently above the net heating value threshold, greater than 90
percent of the measurements would need to be ``well above the
threshold,'' with no readings below the threshold. Based on these
considerations, the EPA
[[Page 74796]]
is proposing that if there are no hourly gas samples with a net heating
value below the required minimum net heating value and 20 or fewer
hourly gas samples are less than 1.2 times the required minimum net
heating value, then the gas stream is considered to be ``consistently
above the threshold'' and on-going continuous monitoring is not
required.
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\214\ Pressure-assisted devices are not required to comply with
the vent gas net heating value in 40 CFR 60.18. The EPA is proposing
alternative net heating value requirements for these devices as
discussed in detail below.
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Lastly, to ensure compliance with the maximum flare tip velocity
requirement in 40 CFR 60.18, for flares and enclosed combustion
devices, the EPA is proposing to require installation of a continuous
parameter monitoring system to determine the flow of gas sent to the
flare or combustor, except as noted below for pressure-assisted
devices. Alternatively, the owner or operator may conduct an initial
engineering assessment of the sources vented to the flare to
demonstrate that, based on the maximum pressure of these sources, the
maximum possible gas flow rate would not exceed the allowed maximum
flare tip velocity in 40 CFR 60.18 or the maximum design flow rate of
the enclosed combustor.
The EPA has also determined that combustion devices may be
operating at gas flow rates that are too low to support efficient
combustion, resulting in uncombusted vented emissions. To address this
issue, the EPA is proposing to require that manufacturers establish
both a minimum and maximum flow rate during the testing performed under
40 CFR 60.5413b(d) and 40 CFR 60.5413c(d) to ensure these devices
operate efficiently in the field. Combustion control devices previously
tested by the manufacturer for which the manufacturer was able to
demonstrate the control device meets the performance requirements would
not need to perform new performance tests. The zero-level at which the
combustion control device was tested will be extracted from the
previously submitted performance test report and added to the
information on the EPA's website.\215\ For flares and enclosed
combustion devices not tested by the manufacturer under 40 CFR
60.5413b(d) or 40 CFR 60.5413c(d), the owner or operator would be
required to establish a minimum vent gas flow rate based on
manufacturer recommendations. Owners and operators would be required to
continuously monitor the vent gas flow rate to ensure that it is above
this minimum level whenever vent gas is sent to the flare or enclosed
combustion device. As an option, the owner or operator could install a
backpressure preventer which is set to operate at or above the minimum
inlet gas flow rate. The EPA is soliciting comment on this additional
requirement and whether there are additional situations where
continuous monitoring of the vent gas flow rate is unnecessary.
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\215\ Information on combustion control devices tested by the
manufacturer can be found at: https://www.epa.gov/stationary-sources-air-pollution/performance-testing-combustion-control-devices-manufacturers.
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For pressure-assisted devices, the EPA is proposing to include
special provisions in NSPS OOOOb/EG OOOOc, which include a minimum net
heating value (NHV) of the gas sent to the flare/combustor of 800
British thermal units per standard cubic feet (Btu/scf) and an
exemption from the maximum velocity requirements in 40 CFR 60.18.\216\
Pressure-assisted devices are designed to operate at high flare or
burner tip velocities and use this velocity to improve mixing of the
flared gas with surrounding air. For good combustion efficiency at
these high velocities, the flared gas must have higher heat content
than a non-pressure-assisted flare. The EPA evaluated pressure-assisted
flares and determined that these flares must have flare gas with an NHV
of 800 Btu/scf or higher to work efficiently.217 218 Also,
because the burners are specifically designed to have high flow rates,
the burner tip velocity typically exceeds the maximum flare tip
velocity limit in 40 CFR 60.18. The maximum velocity limits in 40 CFR
60.18 were set to prevent flame ``lift off'' or flame instability from
conventional flare tips. However, pressure-assisted flare tips are
specifically designed to operate efficiently at much higher velocities.
The EPA found that pressure assisted flares can operate efficiently at
these higher velocities. Therefore, the EPA is proposing that pressure-
assisted devices would not be subject to the maximum flare tip velocity
limit.
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\216\ Pressure-assisted devices would still be subject to the
requirements for a continuous pilot flame and the visible emissions
requirement, as well as the requirement to continuously monitor (or
perform an assessment) on the NHV of the vent gas.
\217\ ``Notice of Final Approval for the Operation of a
Pressure-Assisted Multi-Point Ground Flare at Occidental Chemical
Corporation,'' 81 FR 23480, April 21, 2016, and ``Notice of Final
Approval for an Alternative Means of Emission Limitation at
ExxonMobil Corporation; Marathon Petroleum Company, LP (for Itself
and on Behalf of Its Subsidiary, Blanchard Refining, LLC); Chalmette
Refining, LLC; and LACC, LLC,'' 83 FR 46939, September 17, 2018.
\218\ Because pressure-assisted flares generally do not use
assist gas, combustion zone NHV is the same as the flare gas NHV.
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Finally, the EPA is proposing operating requirements at 40 CFR
60.5417b(f) (and 40 CFR 60.5417c(f)) and specifying what constitutes a
deviation at 40 CFR 60.5417b(g) (and 40 CFR 60.5417c(g)) that are
consistent with the operating and monitoring requirements outlined in
this section and that are consistent across all affected facilities
using control devices. Further, these sections are referenced in the
recordkeeping and reporting requirements for each affected facility so
that the reporting requirements for affected facilities that use
control devices to comply with the standard have consistent control
device reporting requirements regardless of the type of affected
facility. The EPA is soliciting comment on all proposed requirements
for control devices described within this section.
I. Reciprocating Compressors
In a reciprocating compressor, natural gas enters the suction
manifold and then flows into a compression cylinder, where it is
compressed by a piston driven in a reciprocating motion by the
crankshaft, which is powered by an internal combustion engine.
Emissions occur when natural gas leaks around the piston rod when
pressurized natural gas is in the cylinder. The compressor rod packing
system consists of a series of flexible rings that create a seal around
the piston rod to prevent gas from escaping between the rod and the
inboard cylinder head. However, over time, during operation of the
compressor, the rings become worn, and the packaging system needs to be
replaced to prevent excessive leaking from the compression cylinder.
1. NSPS OOOOb
a. November 2021 Proposal
Based on the analysis presented in section XII.E.1 of the November
2021 proposal preamble (86 FR 63214-63220; November 15, 2021), the
proposed BSER for NSPS OOOOb for reducing GHGs and VOC from new
reciprocating compressors was the replacement of the rod packing based
on an annual monitoring threshold. Under the November 2021 proposal,
the owner or operator of a reciprocating compressor affected facility
would have been required to monitor the rod packing emissions annually
by conducting flow rate measurements. When the measured flow rate
exceeded 2 scfm (in pressurized mode), replacement of the rod packing
would have been required. As indicated at proposal, the 2 scfm flow
rate threshold was established based on manufacturer guidelines
indicating that a flow rate of 2 scfm or greater was considered
indicative of rod packing failure.\219\ Alternatively, the November
2021 proposal would have
[[Page 74797]]
also provided owners and operators the option of routing rod packing
emissions to a process via a CVS under negative pressure in order to
comply with the rule. The proposed option to route to a process is
allowed as an alternative under NSPS OOOOa because implementing this
option, where feasible, would achieve greater emission reductions than
the primary fixed schedule rod packing replacement BSER requirement
under NSPS OOOOa.
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\219\ 86 FR 63218 (November 15, 2021).
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b. Changes From November 2021 Proposal
The BSER analysis is unchanged from what was presented in the
November 2021 proposal (see 86 FR 63214-63220, section XII.E.
Reciprocating Compressors). The EPA is proposing changes and specific
clarifications to the November 2021 proposal standards for NSPS OOOOb.
For the proposed replacement of the rod packing based on an emission
limit and annual measurement requirement, we are proposing: (1) To
clarify that the standard of performance is a numeric standard (not a
work practice standard) of 2 scfm, (2) to allow for repair (in addition
to replacement) of the rod packing in order to maintain an emission
rate at or below 2 scfm; (3) to allow for monitoring based on 8,760
hours of operation instead of based on a calendar year. We are also
proposing regulatory text that clearly defines the required flow rate
measurement methods and/or procedures, repair and replacement
requirements, and recordkeeping and reporting requirements. For the
alternative option of routing rod packing emissions to a process via a
CVS under negative pressure, we are proposing to remove the negative
pressure requirement. These changes take into account comments received
on the November 2021 proposal, as explained below.
The basis for the proposed changes and clarifications to the
replacement of the rod packing based on a flow rate monitoring
measurement for reciprocating compressors is presented in section
IV.I.1.b.i of this preamble. The basis for the proposed change to the
alternative option of routing rod packing emissions to a process via a
CVS under negative pressure is presented in section IV.I.1.b.ii of this
preamble. A summary of the proposed reciprocating compressor standards
is presented in section IV.I.1.b.iii of this preamble.
i. Numerical Emission Limit Standard Proposed Changes
Changes to Format of the Standard. In re-considering the BSER
determination and standards for reciprocating compressors proposed in
November 2021, the EPA recognized that it is feasible to prescribe a
standard of performance, rather than a work practice standard,\220\ for
reciprocating compressors. Accordingly, the EPA is now proposing a
numerical emission limit requirement. The major difference between this
standard and what the EPA proposed in November 2021 is that under this
supplemental proposal, owners and operators would be required to
maintain emissions at or below the emission limit (emission flow rate
of 2 scfm) whereas under the November proposal, owners or operators
would have been required to change out the rod packing only after
discovering an exceedance of 2 scfm. The BSER is replacement of the rod
packing and/or other necessary repair and maintenance activities to
maintain emissions at or below 2 scfm.
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\220\ Under CAA section 111(h)(1), work practice standards are
appropriate only where ``it is not feasible to prescribe or enforce
a standard of performance.'' CAA section 111(h)(2) defines such
infeasibility as ``any situation in which the Administrator
determines that (A) a pollutant or pollutants cannot be emitted
through a conveyance designed and constructed to emit or capture
such pollutant, or that any requirement for, or use of, such a
conveyance would be inconsistent with any Federal, state, or local
law, or (B) the application of measurement methodology to a
particular class of sources is not practicable due to technological
or economic limitations.''
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Repair or Replacement. Commenters on the November 2021 proposal
urged the EPA to allow for repair as an alternative to complete
replacement of rod packing. The commenters pointed out that allowing
repair would be consistent with California's reciprocating compressor
rule requirements. See 17 California Code of Regulation section
95668(c)(3)(D).\221\ One commenter noted that, for older units,
replacing the rod packing does not always address emissions levels, as
other maintenance issues can contribute to cylinder emissions, such as
issues with the rod itself. The commenter added that providing the
flexibility to repair as well as replace the rod packing could
significantly impact personnel costs--while rod packing replacement on
older units can require approximately 32-man hours per cylinder, a
repair may entail a significantly lower level of effort and hours of
labor.\222\
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\221\ Final Regulation Order. California Code of Regulations,
Title 17, Division 3, Chapter 1, Subchapter 10 Climate Change,
Article 4. Subarticle 13: Greenhouse Gas Emission Standards for
Crude Oil and Natural Gas Facilities.
\222\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
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The EPA agrees with the commenters' suggestion. The intent of the
proposed reciprocating compressor standard was to require that the
volumetric flow rate be maintained at or below 2 scfm. If repair can
maintain the volumetric flowrate at or below 2 scfm without the need to
replace the rod packing, the intent of the proposed standards would be
met. Thus, under the proposed numerical emission limit, an owner or
operator would be allowed to repair or replace the rod packing in order
to maintain the volumetric flow rate at or below the 2 scfm emission
limit.
Hours of Operation Versus Calendar Year. Commenters \223\ on the
November 2021 proposal recommended that the EPA consider requiring flow
rate monitoring based on a compressor's hours of operation totaling one
year (i.e., 8,760 hours) in lieu of requiring annual flow rate
measurements based on a calendar year. Commenters stated that using the
compressor's hours of operation would ensure that undue burden is not
placed on owners and operators where compressors are not operational
for multiple months or are used intermittently. The commenters
explained that basing flow rate measurement requirements on a
reciprocating compressor's hours of operation would allow owners and
operators to stagger maintenance activity throughout the year. The
comments further suggested that the EPA consider exemptions from the
rule for limited-use reciprocating compressors and changing the flow
rate measurement monitoring requirement frequency to every 2 years.
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\223\ See Document ID No. EPA-HQ-OAR-2021-0317-0415.
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In order to address limited-use reciprocating compressors and to
allow owners and operators flexibility when planning maintenance, the
EPA agrees that it makes sense to require periodic reciprocating
compressor flow rate monitoring based on the hours of operation (i.e.,
8,760 hours) in lieu of requiring monitoring based on a calendar year.
Thus, we are proposing to allow for periodic flow rate monitoring based
on 8,760 hours of operation instead of requiring monitoring on a
calendar year basis.
Regulation Clarifications. Several commenters \224\ requested that
the EPA clearly state in the rule that the GHGRP subpart W methods be
allowed for the flow rate measurements. These commenters also requested
that the EPA clearly state the proposed reciprocating compressor annual
monitoring threshold and the repair and rod packing replacement
requirements. Specifically, they sought certainty
[[Page 74798]]
regarding the schedule for repair and ``delay of repair'' criteria to
ensure unnecessary restrictions are not placed on repair schedules, and
a clear explanation of operating requirements for measurement (i.e.,
when the unit is operating).
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\224\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0415, and EPA-
HQ-OAR-2021-0317-1375.
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The EPA considered the commenters' specific requests for clarity
within the requirements when developing the proposed regulatory text
and the desire to be consistent with the GHGRP subpart W. We recognize
this desire however we are concerned the flow rate measurements methods
under GHGRP subpart W are not as well-defined or prescriptive as the
methods the EPA requires for demonstrating compliance with an emission
standard. Instead, the EPA is proposing the use of volumetric flow rate
which meet the requirements of Method 2D (40 CFR part 60, appendix A)
for testing emissions from reciprocating compressor rod packing and the
use of a high-volume sampler to measure the emissions from proposing
either the reciprocating compressor rod packing or centrifugal
compressor seal vents (dry seals for NSPS OOOOb and all centrifugal
compressor wet and dry seals for EG OOOOc).\225\ For the high-volume
sampler, instead of relying on manufacturer defined procedures required
in GHGRP Subpart W, the EPA is proposing a defined set of procedures
and performance objectives to ensure consistent application of these
samplers. In an effort to allow for additional innovation for these
types of measurements, the EPA is also proposing to allow other
methods, subject to Administrator approval, that have been validated
according to Method 301 (40 CFR part 63, appendix A). The EPA solicits
comment on the use of the proposed performance test methods and
solicits comment on other methodologies that could be used to
demonstrate compliance with the centrifugal compressor dry seal vent,
centrifugal compressors for EG OOOOc, and reciprocating compressor rod
packing emission standards.
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\225\ See section IV.G. for discussion on centrifugal
compressors.
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The proposed NSPS OOOOb regulatory text also specifies that flow
rate monitoring be conducted in operating or standby pressurized mode,
and ``repair'' and ``delay of repair'' schedules, in addition to other
clarifying requirements. The EPA is proposing to require conducting
flow rate measurements during operating or standby pressurized mode
because the measured emissions would be representative of actual
emissions during operations. Repair schedules are proposed to require
repair of equipment in a timely manner to mitigate emissions. Delay of
repair would be allowed when owners and operators required more time to
repair equipment based on scenarios beyond the owner or operator's
control (e.g., issues with availability of equipment or where repair
necessitates a compressor shutdown when redundancy of compressors is
not available).
ii. Routing Emissions to a Process Via a Closed Vent System Under
Negative Pressure
The EPA received comments on the November 2021 proposal related to
its proposed compliance alternative of routing rod packing emissions to
a process via a CVS under negative pressure. One commenter \226\ noted
that routing emissions to a process should not require negative
pressure, stating that some pressure differential is required to take
gas out of the rod packing vent and into the desired location. This
commenter further stated that the use of negative pressure can raise
safety and operational issues, and that operating a crankcase
collection system under negative pressure (i.e., in a vacuum) creates
the possibility of introducing oxygen into the system. This commenter
added that allowing for pressure differential without requiring
operation under negative pressure could lead to larger emission
reductions overall, and that the proposed negative pressure requirement
eliminates the ability to use technologies that could reduce emissions
further. Another commenter \227\ similarly reported that the use of
negative pressure presents safety concerns of creating an explosive
mixture of natural gas and atmospheric air, should there be any leak
between the negative pressure source and the packing vent. The
commenter stated that as long as the packing vent recovery system is at
a lower pressure; the packing vent gas will be recovered without
leaking to atmosphere and there will be no risk of introducing
atmospheric air to the natural gas.
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\226\ See Document ID No. EPA-HQ-OAR-2021-0317-0817.
\227\ See Document ID No. EPA-HQ-OAR-2021-0317-0745.
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The November 2021 proposal included the requirement to route rod
packing emissions to a process via a CVS under negative pressure based
on information submitted by a petitioner \228\ on NSPS OOOO that
requested/suggested an alternative standard that would result in equal
to or greater emissions reductions than the rod packing replacement
standard. The petitioner's suggested alternative standard was to
capture emissions under negative pressure, thus allowing all emissions
to be routed to the engine. The petitioner suggested achieving this by
recovering vented emissions from the rod packing under negative
pressure and routing these emissions of otherwise vented gas to the air
intake of a reciprocating internal combustion engine that would burn
the gas as fuel to augment the normal fuel supply. The petitioner
reasoned that emission reductions would be commensurate with, or better
than, the reductions from the rod packing replacement standard. The EPA
acknowledged at the time (2014) that this technology may not be
applicable or feasible for every compressor installation and situation.
However, the EPA proposed this option as an alternative to the rod
packing replacement standards for those instances where it could be
applied.\229\
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\228\ Letter from Veronica Nasser, REM Technologies, Inc., to
Lisa P. Jackson, EPA Administrator, Petition for Reconsideration.
\229\ See 79 FR 41760-41761 (July 17, 2014).
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In light of the comments received on the November 2021 proposal,
and an increased understanding of this type of approach, the EPA is
proposing to revise the compliance alternative by continuing to allow
emissions to be routed to a process via a CVS but removing the
requirement for this to occur under negative pressure. The intent of
requiring ``negative pressure'' was that there be sufficient pressure
differential such that emissions would be routed from the compressor
via the CVS to the process. The EPA did not intend to create a safety
issue or limit technologies that would achieve equivalent or greater
emission reductions than the work practice standard. Since such a
pressure differential would be created when the reciprocating
compressor is operating, specifying that emissions need to be routed to
a process via a CVS under negative pressure is unnecessary. As the
commenter noted, this is already understood for other sources where the
standards require routing of emissions through a CVS to a process or
control device.
As noted above, routing emissions to a process is an existing
compliance option under NSPS OOOO and NSPS OOOOa and the EPA has
assumed that the emissions reduced by this option, where feasible to
implement, are greater than those achieved by the proposed BSER
requirement to implement maintenance and repair activities to maintain
the flow rate (as a surrogate for emissions) from the reciprocating
compressor rod packing at or below 2
[[Page 74799]]
scfm. The EPA solicits comment on its assumption that the emissions
reduced by requiring the capture of gas and routing to a process are
greater than the requirement to maintain the flow rate from the
reciprocating compressor rod packing at or below 2 scfm. The EPA also
is soliciting comment on the prevalence of owners and operators
complying with NSPS OOOO and NSPS OOOOa by capturing and routing
emissions from the reciprocating compressor rod packing to a process.
iii. Summary of Proposed Standards
Affected Facility. The EPA is proposing to define a reciprocating
compressor affected facility as each reciprocating compressor, which is
a single reciprocating compressor. A reciprocating compressor located
at a well site is not an affected facility under this subpart. A
reciprocating compressor located at a centralized production facility
is an affected facility under this subpart.
Numerical Emission Limit Standards. The proposed NSPS OOOOb
standard of performance for reciprocating compressor affected
facilities is a numerical emission limit of 2 scfm (in operating or
standby pressurized mode). The volumetric flow rate measurement from
each reciprocating rod packing must be maintained to be less than or
equal to a flow rate of 2 scfm (in operating or standby pressurized
mode). The proposed BSER is to repair or replace the rod packing and to
conduct other necessary repair and maintenance in order to maintain the
emission rate at or below 2 scfm. The proposed monitoring requirements
are to conduct volumetric flow rate measurements from each
reciprocating compressor rod packing using the proposed monitoring
methods in 40 CFR 60.5386b (which includes similar screening and flow
rate measurement methods as required under GHGRP subpart W).
The EPA is proposing to require the first volumetric flow rate
measurements from a reciprocating compressor affected facility on or
before 8,760 hours of operation. Subsequent volumetric emissions
measurements from a reciprocating compressor affected facility would be
required on or before 8,760 hours of operation after the previous
measurement, or on or before 8,760 hours of operation after the date of
the most recent reciprocating compressor rod packing replacement,
whichever is later. Preventative maintenance or other corrective
actions may be necessary (in addition to monitoring every 8,760 hours
of operation) in order for owners or operators to ensure compliance at
all times (consistent with the general duty clause 40 CFR 60.5470b(b))
with the required flow rate of 2 scfm or less).
Routing Emissions From the Rod Packing to a Process. Alternatively,
an owner or operator may choose to comply with NSPS OOOOb by routing
emissions from the rod packing to a process through a CVS. This option
would achieve greater than or equal to the 2 scfm numerical limit as
emissions would be routed to a process via a closed system which would
limit emissions from the rod packing from being vented to the
atmosphere. An owner or operator must ensure that the CVS is designed
to capture and route all gases, vapors, and fumes to a process (40 CFR
60.5411b(a) and (c)). Additionally, an owner or operator would be
required to design and operate the CVS with no detectable emissions and
would be subject to bypass requirements (as applicable). Initial,
monthly, and annual inspections (using OGI, EPA Method 21, or AVO (for
monthly inspections only)) would be required to check for defects and
detectable emissions.
Recordkeeping and Reporting Requirements. Owners or operators
complying with the numerical emission limit must track and report in
their annual report the cumulative number of hours of operation of each
reciprocating compressor since startup, since the previous screening/
volumetric flow rate emissions measurement, or since the previous
reciprocating compressor repair/replacement of rod packing, as
applicable. Their annual report must also include a description of the
method used and the results of the volumetric flow rate measurement or
emissions screening, as applicable. Lastly, owners or operators must
maintain records and report each deviation from the emission limit
standard that occurred during the reporting period, the date and time
the deviation began, duration of the deviation and a description of the
deviation.
For a reciprocating compressor affected facility complying with the
routing emissions from the rod packing to a process through a CVS, an
owner or operator would be required to maintain records and report each
reciprocating compressor that was constructed, modified, or
reconstructed during the reporting period that is complying by using
this option. In instances where a deviation from the standard has
occurred during the reporting period, an owner or operator would be
required to provide information on the date and time the deviation
began, the duration of the deviation, and a description of the
deviation. Additionally, they would be required to report of the dates
of each cover and CVS inspection, whether defects or leaks are
identified, and the date of repair or the date of anticipated repair if
repair is delayed would be included in the annual report. Where bypass
requirements apply, the date and time of each bypass alarm or each
instance the key is checked out would be included in the annual report.
2. EG OOOOc
Based on the analysis presented in section XII.E.2 of the November
2021 proposal preamble (86 FR 63214-63220; November 15, 2021), the
proposed BSER for EG OOOOc for reducing methane emissions from existing
reciprocating compressors was the replacement of the rod packing based
on an annual monitoring threshold. Under the November 2021 proposal,
the owner or operator of a reciprocating compressor designated facility
would have been required to monitor the rod packing emissions annually
by conducting flow rate measurements. When the measured flow rate
exceeded 2 scfm (in pressurized mode), replacement of the rod packing
would have been required. Alternatively, the November 2021 proposal
would have also provided owners and operators the compliance
alternative of routing rod packing emissions to a process via a CVS
under negative pressure to comply with the rule.
a. Standard Proposed Changes
Based on the same public comment considerations and reasoning as
explained above (see sections IV.I.1.b.i and ii of this preamble) for
the proposed NSPS OOOOb reciprocating compressor rule changes, the EPA
is proposing the same changes and requirements under EG OOOOc as
presumptive standards for designated facilities.
b. Summary of Proposed Standards
Designated Facility. The EPA is proposing to define a reciprocating
compressor designated facility as each reciprocating compressor, which
is a single reciprocating compressor. A reciprocating compressor
located at a well site is not a designated facility under this subpart.
A reciprocating compressor located at a centralized production facility
is a designated facility under this subpart.
Proposed Presumptive Standards. The proposed presumptive standards
and BSER for existing reciprocating compressors are the same as those
being proposed for new reciprocating compressors (see section
IV.I.1.b.iii of this preamble). The requirements to
[[Page 74800]]
monitor the volumetric flow rate from a reciprocating compressor based
on hours of operation, and to repair or replace the rod packing and to
conduct any necessary repair and maintenance in order to maintain a
flow rate at or below 2 scfm, would not result in any additional
capital expenditures or retrofit considerations that would warrant
different requirements. Alternatively, as with new sources, owners or
operators of existing reciprocating compressors would be allowed to
comply by routing rod packing emissions to a process via a CVS.
J. Storage Vessels
1. NSPS OOOOb
a. November 2021 Proposal
Storage Vessel Affected Facility. In the November 2021 proposal,
the EPA proposed to retain the current VOC standards for storage
vessels (95 percent reduction) and proposed for the first-time
standards for reducing methane emissions from storage vessels (95
reduction). In addition, for both VOC and methane standards, the EPA
proposed to define a storage vessel affected facility as a tank battery
or a single storage vessel that is not part of a tank battery, with the
potential for VOC emissions of 6 tpy or greater.\230\ The standards in
NSPS OOOOa apply to single storage vessels with potential VOC emissions
of 6 tpy or greater, although the EPA has long observed that these
storage vessels are typically located as part of a tank battery. See 76
FR 52738, 52763 (August 23, 2011). Further, the 6 tpy applicability
threshold was established by directly correlating the cost to control
different levels of VOC emissions based on the use of a single vapor
recovery or combustion control device, regardless of the number of
storage vessels routing emissions to that control device, and control
of 6 tpy VOC was cost effective using that single control device. Id.
at 52763-64. Therefore, in the November 2021 proposal, the EPA proposed
to define a tank battery as a group of storage vessels that are
physically adjacent and that receive fluids from the same source (e.g.,
well, process unit, compressor station, or set of wells, process units,
or compressor stations) or which are manifolded together for liquid or
vapor transfer. The EPA proposed that to determine whether a single
storage vessel is an affected facility, the owner or operator would
compare the 6 tpy VOC threshold to the potential emissions from that
individual storage vessel; to determine whether a tank battery is an
affected facility, the owner or operator would compare the 6 tpy VOC
threshold to the aggregate potential emissions from the group of
storage vessels in the tank battery. For new, modified, or
reconstructed sources, the EPA proposed that if the potential VOC
emissions from a storage vessel or tank battery exceeds the 6 tpy
threshold, then it is a storage vessel affected facility and controls
would be required. Additionally, the EPA proposed an emissions limit
requiring 95 percent reduction as the BSER for reducing VOC and methane
emissions from new, modified, or reconstructed storage vessel affected
facilities. The EPA also requested comment on increasing combustion
efficiency to 98 percent control and on requiring additional monitoring
of the control device. See IV.G of this preamble for discussion related
to combustion control devices.
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\230\ For the reasons explained in the November 2021 proposal,
the 6 tpy VOC applicability threshold would apply to both methane
and VOC standards.
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Modification. In the November 2021 proposal, the EPA proposed
specific provisions to specify what circumstances constitute a
modification of an existing storage vessel or tank battery, and thus
subject it to the proposed NSPS OOOOb. The EPA proposed that a single
storage vessel or tank battery is modified when certain physical or
operational changes are made (86 FR 63178; November 15, 2021) to the
single storage vessel or tank battery which result in an increase in
the potential methane or VOC emissions. The EPA proposed that the owner
or operator would be required to recalculate the potential VOC
emissions when any of these actions occurred on an existing tank
battery, to determine if a modification occurred. The EPA proposed that
an existing tank battery would become subject to the proposed NSPS
OOOOb if it is modified pursuant to this definition of modification and
its potential VOC emissions exceeded the proposed 6 tpy VOC emissions
threshold.
Legally and Practicably Enforceable. The EPA proposed to clarify
the term ``legally and practicably enforceable'' as it related to
determining applicability of the storage vessel standards, The intent
of this proposed definition (86 FR 63201; November 15, 2021) was to
provide clarity to owners and operators claiming the storage vessel is
not an affected facility in NSPS OOOOb, due to legally and practicably
enforceable limits that limit their potential for VOC emissions below 6
tpy.
b. Changes From November 2021 Proposal
Storage Vessel Affected Facility. In this supplemental proposal,
the EPA is proposing that a storage vessel affected facility is a tank
battery which has the potential for VOC emissions equal to or greater
than 6 tpy or the potential for methane emissions equal to or greater
than 20 tpy. Specifically, the EPA is proposing to define a tank
battery as a group of all storage vessels that are manifolded together
for liquid transfer. A tank battery may consist of a single storage
vessel if there is only one storage vessel is present, or the
individual storage vessels at the site are not manifolded for liquid
transfer. Commenters generally supported basing the potential for
emissions on a tank battery instead of an individual storage vessel.
The EPA received several comments that suggested changes to the
definition of tank battery relating to how the tanks were manifolded
and the proximity of tanks within the tank battery. Specifically, these
commenters recommended that the definition of tank battery not include
the term ``adjacent'' and should be based on tanks that are manifolded
by liquid line.\231\ Commenters suggested these changes to avoid
confusion around applicability and to align with existing state
programs.\232\ The EPA agrees that these changes reflect our intent
that a group of storage vessels which are manifolded together by liquid
line operate as a system and, as such, share the same control, the cost
of which was the basis for defining the applicability threshold; the
total throughput to the tank battery is the basis for determining the
potential for VOC and methane emissions for the tank battery, based on
the maximum average daily throughput to the tank battery. This
rationale holds regardless of the physical proximity to each other and
therefore the term ``adjacent'' does not add additional clarity. Also,
because tank batteries with the potential for VOC and methane emissions
(greater than or equal to the thresholds) are: (1) Storage vessel
affected facilities which require control; and (2) those standards
require that all vapors from the tank battery are routed through a CVS
(i.e., manifolded), it is not necessary to include the provision that
vapor lines are manifolded in the definition of tank battery.
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\231\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0810, EPA-HQ-
OAR-2021-0317-0814 and EPA-HQ-OAR-2021-0317-0831.
\232\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808 and EPA-HQ-
OAR-2021-0317-0831.
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As stated above, the EPA is also proposing to include the 20 tpy
[[Page 74801]]
potential for methane emission threshold for determining applicability
to NSPS OOOOb. As discussed in the November 2021 proposal, the EPA
determined that it is cost-effective to reduce methane emissions by 95
percent from existing tank batteries with potential methane emissions
of 20 tpy. The EPA focused the November 2021 proposed NSPS OOOOb
requirements on the 6 tpy VOC threshold because the EPA expects that
most tank batteries will exceed the 6 tpy VOC threshold well before
they exceed the 20 tpy methane threshold. However, based on our cost
estimates, the EPA determined it is cost effective to control tank
batteries if their methane emissions exceed 20 tpy, but the potential
VOC emissions remain below 6 tpy. As such, in the unusual case that the
methane threshold is triggered prior to the VOC threshold, the EPA
determined it necessary to directly include the 20 tpy potential
methane emissions threshold in the storage vessel affected facility
definition.
The EPA also is proposing that a ``generally accepted model or
calculation methodology'' used to determine VOC and methane emissions
must account for flashing, working, and breathing losses. As discussed
in the November 2021 proposal, both methane and VOC emissions from
storage vessels are a result of working, breathing, and flashing
losses. Flashing losses occur when a liquid with dissolved gases is
transferred from a vessel with higher pressure (e.g., separator) to a
vessel with lower pressure (e.g., storage vessel), thus allowing
dissolved gases and a portion of the liquid to vaporize or flash. In
the Crude Oil and Natural Gas source category, flashing losses occur
when crude oils or condensates flow into a storage vessel from a
separator operated at a higher pressure. Typically, the higher the
operating pressure of the upstream separator, the greater the flash
emissions from the storage vessel. See 86 FR 63198 (November 15, 2021).
For tank batteries with flashing losses, those emissions can dwarf
working and breathing losses from the same tank battery. There are many
``generally accepted'' models or calculation methodologies for
estimating storage vessel emissions, but they do not all estimate flash
emissions. Therefore, it is important to specify in the rule the EPA's
requirement that emissions calculations account for such emissions when
flash emissions occur.
Additionally, the EPA is including in this supplemental proposal
regulatory text which instructs the owner or operator on how to
determine the potential for VOC or methane emissions as the cumulative
emissions from all storage vessels within the tank battery according to
certain timelines; for each tank battery located at a well site or
centralized production facility the determination must occur 30 days
after startup of production, or within 30 days after a physical or
operational action which may trigger a modification or reconstruction;
or for each tank battery located at a compressor station or onshore
natural gas processing plan, the determination must occur prior to
startup of the compressor station or onshore natural gas processing
plant (or within 30 days after an action which may trigger
reconstruction or modification). These timelines are consistent with
the timelines provided in NSPS OOOOa for determining the potential for
VOC emissions after startup of production (for a well site) or startup
of the compressor station or onshore natural gas processing plant but
are being proposed to also include timelines for centralized production
facilities as well as timelines for determining the potential for VOC
and methane emissions following an action which may trigger
reconstruction or modification. The EPA believes this proposed
regulatory text will provide direction and clarity to owners and
operators for when the potential for VOC and methane emissions
determinations must be made based on potentially triggering events. See
the following discussion regarding reconstruction and modification.
Reconstruction and Modification. The EPA is proposing the following
changes from the November 2021 proposal related to definitions for
reconstruction and modification for storage vessels. This proposal
includes a definition of ``reconstruction'' as well as ``modification''
at 40 CFR 60.5365b(e)(3) for determining if an existing tank battery
becomes a storage vessel affected facility subject to NSPS OOOOb. The
proposed rule will apply to sources that are new, reconstructed, and
modified sources after November 15, 2021. In the November 2021 proposal
the EPA discussed our rationale for proposing specific actions which
lead to an increase in VOC and methane emissions and therefore,
constitute a modification of an existing tank battery. Generally, that
rationale was to provide clarity on actions which are considered a
modification of a tank battery. See 86 FR 63198 (November 15, 2021).
In this proposed rule, the EPA is proposing two actions which
constitute reconstruction: (1) Over half of the storage vessels are
replaced in an existing tank battery that consists of more than one
storage vessel; or (2) the provisions of 40 CFR 60.15 are met for the
existing tank battery that consists of a single storage vessel. Section
60.15 of the General Provisions to part 60 states that reconstruction
occurs when the replacement of new components exceeds 50 percent of the
capital cost that would be required to construct a comparable entirely
new facility and it is technologically and economically feasible to
meet the applicable standard under part 60. Reconstruction applies
irrespective of any change in emissions rate. ``Fixed'' capital cost is
further defined at 40 CFR 60.15(c) as the capital needed to provide all
of the depreciable components and 40 CFR 60.15(g) allows for individual
subparts to include specific provisions to refine or delimit the
concept of reconstruction. Finally, 40 CFR 60.15(d) and (e) provide
that the owner or operator must notify the Administrator prior to the
proposed replacement with an estimate of the fixed capital cost of
replacement (among other items, see 40 CFR 60.15(d)) and upon receipt,
the Administrator will determine if the proposed replacement
constitutes reconstruction.
Based on our experience from NSPS OOOO and NSPS OOOOa, the
predominant type of storage vessel expected to be covered by the
proposed NSPS are fixed roof storage vessels, and as part of the
storage vessel affected facility, have limited depreciable components
beyond the storage vessel itself (e.g., thief hatches and pressure
relief devices). Because the EPA expects that each affected facility
will undertake similar fixed capital cost replacements at storage
vessel affected facilities, namely replacing one or more storage
vessels, replacing thief hatches, and replacing pressure relief
devices, we believe that it will serve as a burden reduction to
industry to establish uniform criteria which constitute reconstruction.
For a tank battery which consists of a single storage vessel, it may be
possible that the cost of replacing the thief hatch, pressure relief
device or other depreciable components could exceed 50 percent of the
cost of an entirely new storage vessel, therefore the EPA is proposing
that the provisions of 40 CFR 60.15 would apply. The EPA requests
comment on this assumption that the costs of replacement of all
depreciable components on a single storage vessel could exceed 50
percent of the cost of an entirely new storage vessel. For a tank
battery which consists of more than a single storage vessel, we believe
that the cost of replacing storage vessel components such as thief
hatches and pressure relief devices, in comparison to the cost of
constructing
[[Page 74802]]
an entirely new storage vessel affected facility, will not exceed 50
percent of the cost of constructing a comparable new storage vessel
affected facility. Therefore, the EPA is proposing to simplify and
streamline the reconstruction determination for tank batteries by
defining reconstruction at a tank battery with more than a single
storage vessel as replacement of 50 percent of the storage vessels in
the tank battery. This defined reconstruction action will eliminate the
need for the owner or operator to submit the notification in 40 CFR
60.15(d) and await the EPA's response under 40 CFR 60.15(e), before
undertaking a replacement.
An important factor in determining whether over 50 percent of the
storage vessels in an existing tank battery has been replaced is the
time period for making such assessment. Consider the following
scenario: an owner replaces one-third of the storage vessels in an
existing tank battery and, shortly thereafter, replaces another third
of the storage vessels in that tank battery. The owner has replaced 60
percent of the storage vessels in that tank battery in total; however,
without specifying the time frame for assessing reconstruction, it is
unclear whether the tank battery is ``reconstructed'' because over half
of the storage vessels in the tank battery have been replaced, or the
replacements are two separate programs and therefore should not be
aggregated for purposes of determining reconstruction. For the reasons
discussed in section IV.D and IV.E of this preamble, the EPA is
proposing to interpret natural gas-drive pneumatic controller and
pneumatic pump replacements to include all natural gas-driven pneumatic
controllers and pneumatic pumps which commence replacement (but are not
necessarily completed) within any 2-year period in determining whether
the replacements constitute reconstruction. The EPA solicits comment on
whether to similarly set a specific time period (or rolling time
period) within which replaced storage vessels in an existing tank
battery will be aggregated towards determining whether the 50 percent
replacement threshold has been exceeded, and if so, whether a 2-year
time frame or another time frame is appropriate for determining
reconstruction to a tank battery with more than a single storage
vessel.
Related to modifications, the EPA explained in the November 2021
proposal that actions occurring at a well site, such as refracturing a
well or adding a new well that sends these liquids to the tank battery
at the well site or centralized production facility, would result in an
increase in VOC and methane emissions based on an increase in
volumetric throughput to the tank battery. See 86 FR 63199 (November
15, 2021). However, this does not always hold true for tank batteries
located at a compressor stations or onshore natural gas processing
plants. In the September 15, 2020, rule (see 85 FR 57404), the EPA
finalized a different framework for determining the potential for VOC
emissions from storage vessels located at compressor stations and
onshore natural gas processing plants, based on comments received on
the September 15, 2020, rule that storage vessels located at these
types of facilities are designed to receive liquids from multiple well
sites that may startup production over a longer period of time.\233\ To
account for this future throughput to the storage vessels, compressor
stations and natural gas processing plants use analysis based on the
future maximum throughput capacity which is then used to obtain
permits. Therefore, the EPA agrees that when a tank battery at a
compressor station or onshore natural gas processing plant receives
additional throughput which has already been accounted for in the
design capacity of that tank battery and included as a legally and
practically enforceable limit in a permit for the tank battery, that
additional throughput does not result in an emission increase from the
tank battery because those emissions have already been accounted for in
the permit.
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\233\ See Document ID No. EPA-HQ-OAR-2017-0473-1261.
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In summary, the EPA is proposing that a modification occurs to an
existing tank battery located at a well site or centralized production
facility when the tank battery receives additional crude oil,
condensate, intermediate hydrocarbons, or produced water throughput and
the potential for VOC or methane emissions increases above the
applicable thresholds. Separately, the EPA is proposing that a
modification occurs to an existing tank battery located at a compressor
station or onshore natural gas processing plant when the tank battery
receives additional fluids which cumulatively exceed the throughput
used in the most recent determination for VOC or methane missions
(e.g., permit) based on the design capacity of such tank battery. In
addition, as proposed in November 2021, modification is also triggered
by the following two events: (1) A storage vessel is added to an
existing tank battery; and/or (2) one or more storage vessels are
replaced such that the cumulative storage capacity of the existing tank
battery increases.
One commenter expressed concerns that the change to a tank battery
(in NSPS OOOOb) versus a single tank (in NSPS OOOOa) will cause
confusion with the requirements of NSPS OOOOa because it creates a
disconnect with how the previous NSPS for this source category applies
the affected facility status to storage tanks. The commenter states
that creating separate ``classifications'' within the NSPS based on
dates of construction or modification will create additional burden
when reviewing authorizations within the specified legislatively
mandated time frames.\234\ The EPA discusses the interplay and
effective dates between prior standards applicable to the Crude Oil and
Natural Gas source category in sections III.B, III.C and III.D of this
preamble. However, to address specific questions regarding
applicability to storage vessels which may be subject to NSPS OOOO,
NSPS OOOOa, or EG OOOOc, the EPA is providing a discussion of
applicability for several anticipated scenarios which may be triggered
by a potential modification action described above. For purposes of the
scenarios below, the EPA is using the proposed definition of a tank
battery, which includes a single storage vessel if only one storage
vessel is present.
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\234\ See Document ID No. EPA-HQ-OAR-2021-0317-0763.
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Scenario One--An existing tank battery has the potential for
methane emissions greater than or equal to 20 tpy methane, therefore it
is a designated facility for purposes of EG OOOOc. Subsequently, one of
the proposed physical or operational changes in NSPS OOOOb at 40 CFR
60.5365b(e)(3)(ii) (i.e., adds a storage vessel to an existing tank
battery; adds capacity to an existing tank battery; or receives
additional fluids) occurs. In order to determine if modification has
occurred to the existing tank battery, the owner or operator would
calculate the potential for VOC and methane emissions in accordance
with the proposed 40 CFR 60.5365b(e)(2). If the potential for either
VOC or methane is above the proposed threshold, the tank battery is a
modified storage vessel affected facility subject to NSPS OOOOb. If the
potential for both VOC and methane is not above the threshold, the tank
battery is not a modified (or reconstructed) storage vessel affected
facility for purposes of NSPS OOOOb and remains a designated facility
for purposes of EG OOOOc.
[[Page 74803]]
Scenario Two--An existing tank battery is not a designated facility
under EG OOOOc (i.e., the potential for methane emissions is less than
20 tpy). Like scenario 1, subsequently, one of the proposed physical or
operational changes in NSPS OOOOb occurs and the owner or operator
calculates the potential for VOC and methane emissions. If the
potential for either VOC or methane emissions is above the proposed
threshold, the tank battery is a modified storage vessel affected
facility subject to NSPS OOOOb. If the potential for both VOC and
methane is not above the proposed threshold, the tank battery is not a
modified storage vessel affected facility for the purposes of NSPS
OOOOb and is also not a designated facility under EG OOOOc.
Scenario Three--An existing storage vessel is a single storage
vessel subject to either NSPS OOOO or NSPS OOOOa and is part of a tank
battery. One of the proposed physical or operational changes in NSPS
OOOOb occurs and the owner or operator calculates the potential for VOC
and methane emissions from the entire tank battery. If the potential
for either VOC or methane is above the threshold, the tank battery is a
modified storage vessel affected facility subject to NSPS OOOOb, and
the single storage vessel would continue to be subject to the
applicable NSPS OOOO or NSPS OOOOa. However, where a facility is
subject to multiple standards, the general practice is to streamline
compliance by complying with the more stringent standard, which would
in effect meet the less stringent standards. If the potential for both
VOC and methane is not above the proposed threshold, the single storage
vessel is not modified for the purposes of NSPS OOOOb and remains
subject to NSPS OOOO or NSPS OOOOa.
Scenario Four--An existing storage vessel is a single storage
vessel and is subject to either NSPS OOOO or NSPS OOOOa. The single
storage vessel is not a designated facility under EG OOOOc because the
potential for methane emissions is less than 20 tpy. One of the
proposed physical or operational changes in NSPS OOOOb occurs and the
owner or operator calculates the potential for VOC and methane
emissions from the single storage vessel. If the potential for either
VOC or methane is above the proposed threshold, the single tank is a
tank battery which is a modified storage vessel affected facility
subject to NSPS OOOOb, as well as NSPS OOOO or NSPS OOOOa. Where a
facility is subject to multiple standards, the general practice is to
streamline compliance by complying with the more stringent standard,
which would in effect meet the less stringent standards; however,
streamlining may not be necessary here if the EPA finalized the
proposed 95 percent reduction, which is the storage vessel standard in
NSPS OOOO and NSPS OOOOa. If the potential for both VOC and methane is
not above the threshold, the single tank is not modified for the
purposes of NSPS OOOOb and remains subject to NSPS OOOO or NSPS OOOOa.
Removed From Service. Finally, in NSPS OOOO and NSPS OOOOa, the EPA
includes provisions to address the status of storage vessel affected
facilities which are physically isolated and disconnected from the
process for purposes other than maintenance, which is referred to as
``removed from service''.\235\ Those regulations also include a
framework for determining the affected facility status of such storage
vessels when they are ``returned to service'', either by: (1) Being
reconnected to the original source of liquids, (2) used to replace any
storage vessel affected facility, or (3) installed in any location
covered by the subpart and introduced with crude oil, condensate,
intermediate hydrocarbon liquids or produced water. The EPA is
including these same provisions in the proposed NSPS OOOOb for
situations where there is more than one storage vessel in a tank
battery and the entire tank battery is removed from or returned to
service. Additionally, the EPA is proposing language to address
situations when only a portion of the tank battery is removed from, or
returned to, service. Specifically, the EPA is proposing to require
complete emptying and degassing of the entire tank battery, or the
portion of the tank battery that is being removed, for it to be
considered ``removed from service''. Submission of a notification that
these emptying and degassing requirements are met would also be
required. Further, when a portion of a storage vessel affected facility
is removed from service, in addition to the requirements above, the
portion of the tank battery must be disconnected from the tank battery
such that the portion is no longer manifolded to the tank battery by
liquid or vapor transfer. When a tank battery is returned to service,
it would retain the same applicability status that applied prior to
removal from service. For tank batteries where only a portion of the
tank battery is returned to service and it is reconnected to the
original source of liquids, it remains a storage vessel affected
facility subject to the same requirements that applied before being
removed from service. If a storage vessel is used to replace a storage
vessel affected facility, or portion of a storage vessel affected
facility, or used to expand a storage vessel affected facility, it
assumes the affected facility status of the storage vessel affected
facility being replaced or expanded.
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\235\ See 78 FR 58435 (September 23, 2013), 79 FR 79022
(December 31, 2014), 80 FR 48262 (August 12, 2015), and 81 FR 35824
(June 3, 2016).
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Request for Additional Comment. In addition to the proposed changes
or clarifications described above, the EPA is soliciting comment on
including a requirement to equip thief hatches with alarms, automated
systems to monitor for pressure changes, or use of automatically
closing thief hatches. Commenters noted that open thief hatches and
deteriorated seals around tank openings are significant emissions
sources at tank batteries. The EPA is aware that some owners and
operators utilize automated systems to alert when pressure changes
occur that could signal an open thief hatch. Additionally, where
automated systems are not available, there are alarms that could be
utilized to alert (via audible alarm or remote notification to the
nearest field office) that an unseated thief hatch is present.\236\ The
EPA is soliciting information on the costs, operation, and feasibility
of installing these automated systems, alarms, or the use of
automatically closing thief hatches.
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\236\ See Document ID No. EPA-HQ-OAR-2021-0317-0814.
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c. Summary of Proposed Requirements
In this proposed rule, owners and operators of storage vessel
affected facilities must reduce methane and VOC emissions by 95
percent. Consistent with provisions of NSPS OOOO and NSPS OOOOa, the
proposed rule also includes the option where if the owner or operator
maintains the uncontrolled actual VOC emissions at less than 4 tpy and
the actual methane emissions at less than 14 tpy as determined monthly
for 12 consecutive months, controls are no longer required. Storage
vessel affected facilities which use a control device to reduce
emissions must equip each storage vessel in the tank battery with a
cover and manifold all storage vessels in the tank battery such that
all vapors are shared among the headspaces of the storage vessel
affected facility. The tank battery must be equipped with a CVS which
routes all emissions to a control device. The proposed rule would
require that when using a flare, the flare must meet the requirements
in 40 CFR 60.18, which the EPA is proposing to strengthen by including
additional
[[Page 74804]]
requirements (as discussed in section IV.H of this preamble), and that
monitoring, recordkeeping, and reporting be conducted to ensure that
the flare is constantly achieving the required 95 percent reduction.
More information on the control device monitoring and compliance
provisions is provided in section IV.G of this preamble; additionally,
notifications made through the super-emitter response program could
help identify potential violations as provided in section IV.C of this
preamble. If the storage vessel affected facility does not have
flashing emissions and is not located at a well site or centralized
production site, the owner or operator may use an internal or external
floating roof to reduce emissions.
In each annual report, owners and operators would be required to
identify each storage vessel affected facility that was constructed,
modified, or reconstructed during the reporting period and must
document the emission rates of both VOC and methane individually. The
annual report must include deviations that occurred during the
reporting period and information for control devices tested by the
manufacturer or the date and results of the control device performance
test for control devices not tested by the manufacturer. The report
also must include the results of inspections of covers and CVS and the
identification of storage vessel affected facilities (or portion of
storage vessel affected facility) removed from service or returned to
service. For storage vessel affected facilities which comply with the
uncontrolled 4 tpy VOC limit or 14 tpy methane limit, the report must
include changes which resulted in the source no longer complying with
those limits and the dates that the source began to comply with the 95
percent reduction standard.
Required records include documentation of the methane and VOC
emissions determination and methodology, records of deviations and
duration, records for the number of consecutive days a skid-mounted or
permanently mobile-mounted storage vessel is on the site, the latitude
and longitude coordinates of each storage vessel affected facility, and
records associated with a manufacturer tested control device. Required
records also include records demonstrating continuous compliance
including inlet gas flow rate, presence of pilot flame, operation with
no visible emissions, maintenance and repair logs, manufacturer's
operating instructions, and dates that each storage vessel affected
facility (or portion of storage vessel affected facility) is removed
from service or returned to service. For storage vessel affected
facilities which comply with the uncontrolled 4 tpy VOC or 14 tpy
methane limit, records of changes which resulted in the source no
longer complying with those limits and the dates that the source began
to comply with the 95 percent reduction standard, including records of
the methane and VOC determination and methodology. All associated
records that demonstrate proper design and operation of the CVS, cover
and control device also must be maintained (see section IV.G and IV.J.
of this preamble).
2. EG OOOOc
The EPA is also proposing presumptive standards to reduce methane
for existing storage vessel affected facilities in this action that
remain unchanged from the November 2021 proposal and are similar to
those proposed for NSPS OOOOb. Because the BSER for reducing VOC and
methane emissions are the same, the proposed presumptive standard is to
reduce methane emissions by 95 percent. Some commenters expressed that
creating separate classifications (e.g., tank batteries vs single
tanks) within the NSPS based on dates of construction or modification
will create additional burden when reviewing authorizations within the
specified legislatively mandated time frames. Another commenter
requested that EPA clarify whether other individual storage vessels in
an existing tank battery remain affected facilities under NSPS OOOO or
NSPS OOOOa, as applicable, or become part of the modified tank battery
under NSPS OOOOb.\237\ The EPA discusses the interplay and effective
dates between prior standards applicable to the Crude Oil and Natural
Gas source category in sections III.B, III.C and III.D of this preamble
and provides example scenarios, which the EPA believes will provide
guidance to regulators and the regulated community.
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\237\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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K. Covers and Closed Vent Systems
1. NSPS OOOOb
a. November 2021 Proposal
In the November 2021 proposal, the EPA proposed CVS requirements
for certain affected facilities to ensure that emissions are captured
and routed to a process or control device, dependent on the standard
for the affected/designated facility. The affected/designated
facilities for which the EPA proposed the use of a CVS were wells (oil
wells when routing associated gas to a control device), storage
vessels, centrifugal compressors (wet seal), reciprocating compressors,
pneumatic pumps, and process unit equipment affected/designated
facilities. Additionally, for storage vessels using a control device to
reduce emissions and centrifugal compressors with wet seals using a
degassing system, the EPA proposed the use of covers to form a
continuous impermeable barrier over the entire surface area of the
liquid in the storage vessel or the centrifugal compressor wet seal
fluid degassing system. The cover requirements ensure that all
emissions are captured from those emissions sources and routed through
a CVS to a control device, or in the case of centrifugal compressors,
to a control device or to a process. This section discusses the cover
and CVS requirements for those affected/designated facilities that are
located at well sites, centralized production facilities, and
compressor stations. See the discussion on CVS in section IV.L of this
preamble for covers and CVS located at natural gas processing plants.
In the November 2021 proposal, the EPA proposed that covers and CVS
must be designed and operated with no detectable emissions (NDE).
Further, the EPA proposed that where a CVS is used to route emissions
from an affected facility, the owner or operator would demonstrate
there are no detectable emissions from the covers and CVS through OGI
or EPA Method 21 monitoring conducted during the fugitive emissions
survey. Where emissions are detected, the emissions would be considered
a violation of the NDE standard and thus a deviation,\238\ and
corrective actions to complete all necessary repairs as soon as
practicable would be required. The EPA also solicited comment on
whether to include the option to continue utilizing monthly AVO surveys
as demonstrations of NDE from a CVS associated with a pneumatic pump
but did not propose that option specifically. We stated that because we
anticipated that CVS associated with pneumatic pumps would be located
at well sites subject to fugitive emissions monitoring, the monthly AVO
option was not necessary. However, we solicited comment on whether
there are circumstances where a CVS associated with a pneumatic pump is
located at a well site not otherwise subject to
[[Page 74805]]
fugitive emissions monitoring and where OGI (or EPA Method 21) would be
an additional burden.
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\238\ A deviation includes any instance in which an affected
source fails to meet any emission limit, operating limit, or work
practice standard; a deviation suggests potential violation with the
applicable performance standard.
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b. Changes From November 2021 Proposal
In this supplemental proposal, the EPA is proposing specific
revisions to the requirements for CVS associated with the affected/
designated facilities located at well sites, centralized production
facilities, and compressor stations in the proposed NSPS OOOOb and EG
OOOOc. First, the EPA is proposing the same design and operational
requirements for all CVS when routing emissions to a control device or
when routing emissions to a process, regardless of which affected/
designated facility is using the CVS. These proposed standards would
apply to wells (oil wells when routing associated gas to a control
device), centrifugal compressor, reciprocating compressor, pneumatic
controller, pneumatic pump, storage vessel, and process unit equipment
affected/designated facilities. See section IV.L of this preamble for
additional discussion related to process unit equipment affected/
designated facilities at onshore natural gas processing plants.
For these affected/designated facilities, the EPA is proposing the
capture and routing of emissions through a CVS to a control device or
process as part of the BSER, or an alternative to the BSER for specific
situations such as technical infeasibility to apply BSER. The EPA finds
that the demonstration of continuous compliance for these CVS should
include the same robust standards to ensure the CVS are designed and
operated to capture and route all emissions to the control device
regardless of which affected/designated facility is using the CVS. The
proposed standards for CVS include upfront engineering (Professional
Engineer or in-house engineer) design analysis and certifications, an
emissions limit that requires design and operation with no identifiable
emissions, initial and periodic inspections of the CVS, and continuous
monitoring of CVS bypass systems (unless equipped with a seal or
closure mechanism). Therefore, in this proposal, the EPA is
standardizing the design and operational requirements for CVS,
regardless of their location or use (route to a control device or route
to a process).
The EPA is proposing to change the design and operational
requirements for CVS (except for those associated with self-contained
pneumatic controllers) from operation with NDE to operation with no
identifiable emissions. The proposed change of terminology is not
intended to change the stringency of the CVS requirements, which
require that each CVS capture and route all gases, vapors, and fumes to
a control device or a process, but it will clarify the design and
operational standards, and the obligations on the part of the owner or
operator if a leak is detected from the CVS during the inspections to
ensure compliance with the no identifiable emissions standard.
Based on comments received on the November 2021 proposal, there
appears to be confusion whether the proposed NDE standard would be an
emissions limit or a work practice standard. For example, one commenter
\239\ stated that as written, the NDE standard would be a work practice
standard because ``[a]s with all other fugitive emissions components,
detection of a leak (in this case, defined as detectable emissions)
through routine LDAR monitoring triggers the obligation to repair the
leak. If that repair is accomplished according to the specific
requirements in the rule, then there is no violation because the work
practice has been fully implemented.'' This interpretation of the
standard is not correct. In fact, CVS must be designed and operated to
route all gases, vapors, and fumes to a control device or to a process,
which is defined as an emission limit of NDE. The corrective actions
(in the form of the repair provisions) are provided to ensure that
owners and operators bring the CVS back into compliance with the NDE
emission limit as quickly as possible.
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\239\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
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Past efforts in NSPS OOOO and NSPS OOOOa to apply an NDE standard
as an emission limitation, while still allowing repair, delay of repair
or exceptions for unsafe and difficult to inspect equipment, may appear
to condone a ``grace period'' during which compliance with an emissions
limit is not required. Because the NDE standard in NSPS OOOO and NSPS
OOOOa was established as an emissions limit, operation in exceedance of
that limit is a deviation,\240\ even if the repair provisions are
followed.
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\240\ A deviation signals possible violation with the
performance standard for an affected facility because compliance is
no longer demonstrated due to such exceedance.
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Similarly, the EPA is proposing an emissions limit for covers and
CVS in this supplemental proposal for NSPS OOOOb and EG OOOOc. However,
NDE is a term closely linked with EPA Method 21, and is defined based
on an instrument reading in units of ppmv. Because the EPA is proposing
compliance inspections for covers and CVS using optical gas imaging and
AVO, no instrument reading in ppmv is available. Therefore, the EPA is
proposing the design and operational standard as an emissions limit of
no identifiable emissions, which is more appropriate for the methods of
detection required.
To ensure compliance with the no identifiable emissions design and
operational standard for covers and CVS located at well sites,
centralized production facilities, and compressor stations, the EPA is
proposing that owners or operators would conduct initial and quarterly
OGI inspections (except for the Alaska North Slope which is annually).
Any identified emissions would be a violation of this emissions limit
and would be subject to repair with a first attempt completed within 5
days and final repair within 30 days of identification. If the owner or
operator is using the EPA Method 21 alternative for their fugitive
emissions components, then any instrument reading greater than 500 ppmv
above background is considered identified emissions, would be a
potential violation of the no identifiable emissions standard, and
would require repair within the same 5- and 30-day timeframe to bring
the CVS back into compliance.
The EPA is also proposing to require AVO inspections for CVS and
covers located at well sites, centralized production facilities and
compressor stations. The EPA is proposing that AVO inspections of CVS
and covers must occur at the same frequency specified for fugitive
emissions components affected facilities located at the same type of
site. As discussed in section IV.A.1.a.ii of this preamble, the EPA is
proposing that CVS and covers located at a well site, centralized
production facility, or compressor station site, which are not
associated with a well, centrifugal compressor, reciprocating
compressor, pneumatic controller, pneumatic pump, or storage vessel
affected facility, are fugitive emissions components and subject to
those standards, which include periodic OGI (or EPA Method 21 as an
alternative) and monthly or bimonthly AVO inspections. Because we are
aligning the CVS associated with well, centrifugal compressor,
reciprocating compressor, pneumatic controller, pneumatic pump, or
storage vessel affected facilities inspections with the frequency of
inspections under the fugitives program, there should be no additional
cost associated with conducting these AVO inspections of CVS that are
not fugitive emissions
[[Page 74806]]
components at the same time and at the same place, and we believe that
identifying and repairing such leaks is consistent with the proposed
requirement at 40 CFR 60.5370b(b) in a manner consistent with good air
pollution control practice for minimizing emissions. See section IV.A
of this preamble for a full discussion of the fugitive emissions
requirements.
The EPA did not receive comment in response to our request
regarding the burden of OGI (or EPA Method 21) monitoring for CVS
associated with pneumatic pumps at well sites. Therefore, the EPA is
not proposing separate standards for those CVS associated with
pneumatic pumps and is proposing consistent standards for all CVS
associated with affected/designated facilities under NSPS OOOOb or EG
OOOOc.
As discussed in section IV.D of this preamble, the EPA is proposing
that pneumatic controllers may comply with the zero-emission methane
and VOC standard for pneumatic controllers by installing a self-
contained pneumatic controller, which is a natural gas-driven
controller designed so that there are no emissions to the atmosphere.
These controllers are designated as ``no identifiable emissions'' in
the proposed rule. Because these are designed to contain all gases,
vapors, or fumes from the controller, the EPA finds it appropriate to
apply the same continuous compliance requirements to self-contained
controllers as those for covers and CVS described in this section. That
is, the EPA is proposing to require the operation of self-contained
pneumatic controllers with no identifiable emissions, as demonstrated
through quarterly OGI monitoring. Any emissions identified would be a
violation of the zero emissions standard. The repair requirements
described for CVS would also apply to bring the self-contained
pneumatic controller back into compliance with the zero emissions
standard.
As discussed in section IV.B of this preamble, the EPA also is
proposing provisions for the use of alternative test methods that
employ alternative periodic screening technologies or continuous
monitoring systems. The EPA is proposing to allow use of alternative
test methods to replace the use of OGI for demonstrating continuous
compliance of the no identifiable emissions standard for covers and
CVS. The EPA recognizes that the allowable minimum detection thresholds
of the screening technologies used in the alternative periodic
screening approach may not be capable of identifying all of the
potential emissions from these sources; however we find that well
designed, maintained, and certified covers and CVS systems are not
prone to leaks, and the majority of emission events from these systems
can be attributed to short-term operational events or malfunctions that
would be at a level easily identified by screening technology meeting
the allowable minimum detection thresholds. The EPA considers the use
of more frequent surveys (monthly to quarterly) using approved
screening technologies and either annual (if required based on minimum
detection threshold and frequency) or OGI surveys resulting from
emissions detected during screening would ensure equivalent compliance
assurance of the no identifiable emissions standard as the quarterly
OGI surveys paired with monthly or bimonthly AVO inspections. The EPA
solicits comments on the use of the alternative periodic screening
approach as an alternative compliance assurance for covers and CVS
associated with affected/designated facilities, and we solicit comments
that the minimum detection thresholds summarized in Tables 20 and 21
(section IV.B of this preamble) are suitable for this purpose.
c. Summary of Proposed Requirements
The EPA is proposing standards which apply to CVS at a well,
centrifugal compressor, reciprocating compressor, pneumatic controller,
pneumatic pump, storage vessel, or process unit equipment affected/
designated facility. The EPA also is proposing standards for covers at
a centrifugal compressor and storage vessel affected/designated
facility. This summary is limited to covers and CVS located at well
sites, centralized production facilities, and compressor stations.
Covers and CVS located at natural gas processing plants (process unit
equipment affected/designated facilities) are discussed in section IV.L
of this preamble.
Each CVS must be designed and operated to capture and route all
gases, vapors, and fumes to a process or to a control device and comply
with an emissions limit of no identifiable emissions. Initial and
continuous compliance of the no identifiable emissions standard would
be demonstrated through OGI monitoring and AVO inspections conducted at
the same frequency as the fugitive emissions monitoring for the type of
site. Specifically, for the well sites and centralized production
facilities where a CVS is present, quarterly OGI and bimonthly AVO
would be required; for compressor stations, quarterly OGI and monthly
AVO would be required. If the CVS is equipped with a bypass, the bypass
must include a flow monitor and sound an alarm to alert personnel that
a bypass is being diverted to the atmosphere, or it must be equipped
with a car-seal or lock-and-key configuration to ensure the valve
remains in a non-diverting position. To ensure proper design, an
assessment must be conducted and certified by a qualified professional
engineer or in-house engineer. Covers must form a continuous
impermeable barrier over the entire surface area of the liquid in the
storage vessel or over the centrifugal compressor wet seal fluid
degassing system and each cover opening shall be secured in a closed,
sealed position (e.g., covered by a gasketed lid or cap) whenever
material is in the unit on which the cover is installed except during
those times when it is necessary to use an opening.
Each CVS must be inspected using OGI or EPA Method 21 to ensure
that the CVS operates with no identifiable emissions. Annual visual
inspections to check for defects, such as cracks, holes, or gaps) must
be conducted and monthly (compressor stations) or bimonthly (well sites
and centralized production facilities) AVO inspections for leaks must
be conducted would be a potential violation of the no identifiable
emissions standard. Further, any leak detected would be subject to
repair, with a first attempt at repair at five days and final repair
within 30 days. While awaiting final repair, covers must have a gasket-
compatible grease applied to improve the seal. Delay of repair is
allowed where the repair is infeasible without a shutdown, or it is
determined that immediate repair would result in emissions greater than
delaying repair. In all instances, repairs must be completed by the end
of the next shutdown. Unsafe to inspect and difficult to inspect parts
of the closed vent system may be designated as such but must be
inspected according to a plan as frequently as possible, or every five
years, respectively.
Records of CVS and cover inspections, CVS bypass monitoring, and
CVS design and certifications must be maintained. The CVS certification
must be submitted in the initial annual report. Because the
requirements for CVS and covers have been aligned for all affected
facilities which use a CVS or cover, a new reporting section has been
created to contain the similar requirements. Recordkeeping sections for
CVS inspections, covers, bypass monitoring and CVS design assessment
also have been created which are applicable to all sources which use
CVS and covers. This will streamline
[[Page 74807]]
compliance as all affected facilities using the CVS and cover
requirements of the rule will be subject to the same reporting and
recordkeeping requirements.
L. Equipment Leaks at Natural Gas Processing Plants
1. NSPS OOOOb
a. November 2021 Proposal
In the November 2021 proposal, the EPA proposed new standards of
performance for equipment leaks at natural gas processing plants by
revising the equipment leak standards for onshore natural gas plants to
apply more readily to process unit equipment that has the potential to
emit methane even though not ``in VOC service.'' The EPA also proposed
appendix K to provide a standard method for OGI monitoring, which
allowed the EPA to consider a wider range of LDAR programs when
evaluating BSER for equipment leaks at onshore natural gas processing
plants. Specifically, the EPA proposed to require bimonthly OGI
monitoring of valves, pumps, and connectors that have the potential to
emit methane and VOC following the protocol specified in the proposed
appendix K. As an alternative, the EPA proposed to allow for monthly
monitoring of pumps, quarterly monitoring of valves, and annual
monitoring of connectors that have the potential to emit methane and
VOC following EPA Method 21, with a leak defined as any instrument
reading above 2,000 ppm for pumps or 500 ppm for valves and connectors.
The EPA utilized a Monte Carlo analysis to compare these programs and
determined that they achieved equivalent emissions reductions. See 86
FR 63232 (November 15, 2021) for additional information. The November
2021 proposal also included requirements for a ``first attempt at
repair'' for all identified leaks within five days of detection, as
well as final repair completed within 15 days of detection (except when
delay would be allowed).
Finally, in the November 2021 proposal, the EPA requested comments
on certain topics. First, we requested comment on ways to streamline
approval of alternative LDAR programs using remote sensing techniques,
sensor networks, or other alternatives for equipment leaks at onshore
natural gas processing plants, including whether providing an emission
reduction target and equipment leak modeling tool to simulate LDAR
under similar ``ideal'' program implementation conditions might
facilitate future equivalency determinations. Second, we requested
comment on: (1) Adding a requirement of OGI monitoring (or EPA Method
21 monitoring for sources opting for the alternative) on open-ended
valves or lines equipped with closure devices to ensure no emissions
are going to the atmosphere (e.g., to ensure the cap seals the open
end); and (2) allowing the use of OGI monitoring according to the
proposed appendix K, to demonstrate compliance with the no detectable
emissions requirements (in lieu of EPA Method 21) such as those for CVS
at onshore natural gas processing plants.
b. Changes From November 2021 Proposal
In this supplemental proposal, the EPA is proposing specific
requirements for the individual process unit equipment type included in
the LDAR program at onshore natural gas processing plants. This section
describes those specific requirements for pressure relief devices,
open-ended valves or lines, and CVS.
Pressure Relief Devices. Consistent with the November 2021
proposal, the EPA is proposing to require bimonthly OGI monitoring (or
quarterly EPA Method 21 monitoring, if the alternative is used) as well
as monitoring of each pressure relief device within 5 calendar days
after each pressure release to detect leaks using either OGI or EPA
Method 21. A leak is detected if any emissions are observed using OGI,
or if an instrument reading of 500 ppm or greater is provided using EPA
Method 21. The EPA is proposing this requirement instead of requiring a
NDE demonstration (which is also required in NSPS OOOOa) because after
reviewing the record to NSPS KKK (the original LDAR requirements for
onshore natural gas processing plants), it was clear that the basis for
the standards for pressure relief devices was a routine LDAR
program.\241\ Because we have determined that OGI is BSER for equipment
leaks at onshore natural gas processing plants, it is appropriate to
require bimonthly OGI monitoring for this process unit equipment. In
addition to this bimonthly OGI monitoring requirement, the EPA is also
proposing to require OGI monitoring of each pressure relief device
after each pressure release, as it is important to ensure the pressure
relief device has reseated and is not allowing emissions to vent to the
atmosphere. The EPA is soliciting comment on this change from a no
detectable emissions standard to a bimonthly monitoring requirement.
Where the EPA Method 21 option is used, we are proposing quarterly
monitoring of the pressure relief device in addition of monitoring
after each pressure relief. A leak is defined as an instrument reading
of 500 ppm or greater when using EPA Method 21.
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\241\ See 49 FR 2645 (January 24, 1984) and EPA-450/3-82-024b.
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Open-Ended Valves or Lines. For open-ended valves or lines, the EPA
is proposing to require closure devices to seal the open end,
consistent with the requirements in NSPS OOOOa. Consistent with the
November 2021 proposal, the proposed regulatory text would require this
equipment standard (i.e., cap, blind flange, plug, or a second valve)
for open-ended valves and lines. The EPA solicited comment on whether
to require bimonthly OGI monitoring for open-ended valves and lines in
the November 2021 proposal. We are not proposing to require routine
periodic monitoring for open-ended valves or lines. The primary control
requirement for open-ended valves or lines is a closure device (i.e.,
caps, blind flanges, plugs, or a second valve) and this standard is
designed to achieve nearly 100 percent emission reductions. While it is
possible that leaks past the closure device could occur, the EPA does
not believe it would be cost-effective to require a full LDAR program
for each open-ended valve or line, and has previously found this type
of requirement not cost-effective for this type of facility.\242\
However, the EPA recognizes that there are opportunities to identify
when there is a leak past the closure device as part of daily operating
duties or required OGI surveys for other process unit equipment.
Therefore, the EPA is proposing a requirement to complete repairs on an
open-ended valve or line so that the closure device seals the open end
of the valve or line when emissions are identified through any means.
The EPA notes that repairs for this type of leak are generally
straightforward (e.g., install new plug or cap) and cost-effective to
complete. Further, the repair is necessary to comply with the general
duty provisions of 40 CFR 60.5370b(b).
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\242\ See Document ID Nos. EPA-HQ-OAR-2010-0505-0045 and EPA-HQ-
OAR-2010-0505-7631.
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Closed Vent Systems. In NSPS OOOO and NSPS OOOOa, the EPA relied on
separate CVS requirements for ones located at an onshore natural gas
processing facility than those requirements for CVS used for other
purposes in NSPS OOOO and NSPS OOOOa. In this proposal, the EPA is
standardizing the requirements for CVS, as described in section IV.K of
this preamble, with one difference.
For CVS associated with process unit equipment affected facilities
that are
[[Page 74808]]
used to route emissions from leaking equipment to a control device, the
EPA is proposing a requirement to monitor the CVS at the same frequency
(i.e., bimonthly OGI in accordance with appendix K or quarterly EPA
Method 21) as other equipment in the process unit and to repair any
leaks identified during the routine monitoring. Additionally, when
leaks are identified as part of daily operating duties by any means of
detection, we are proposing to require repairs in order to be
consistent with the good air pollution control practices for minimizing
emissions specified in 40 CFR 60.5370b(b). We believe it is most
efficient and cost effective to monitor the CVS at the same frequency
and according to the same methodology as other equipment in the process
unit equipment affected facility (i.e., bimonthly OGI in accordance
with appendix K or quarterly with EPA Method 21) and it is reasonable
and prudent to require any leaks identified to be repaired.
These proposed standards differ from our November 2021 proposal,
which maintained EPA Method 21 inspections for CVS associated with
process unit equipment, consistent with what is required in NSPS OOOO
and NSPS OOOOa. Both NSPS OOOO and NSPS OOOOa require initial
monitoring of a CVS used to comply with the equipment leak standards
using EPA Method 21 followed by annual monitoring using visual
inspections for defects (if constructed of hard piping) or annually
using EPA visual inspections for defects and EPA Method 21 inspections
(if constructed of ductwork). In this supplemental proposal, the EPA is
proposing to allow initial monitoring using OGI in accordance with
appendix K (or EPA Method 21 as an alternative) and annual visual
methods for CVS where each joint, seam, or other connection is
permanently or semi-permanently sealed (hard piping). This approach for
initial instrument monitoring and annual visual monitoring for defects
is consistent with the hard-piping requirements in NSPS OOOO and NSPS
OOOOa and is also consistent with the requirements for other affected
facilities which use a hard-piped CVS to route to a control device.
Potential To Emit Methane or VOC. Consistent with the November 2021
proposal, the EPA is proposing to apply the LDAR standards to process
unit equipment that has the potential to emit methane or VOC.\243\
Further, the EPA is proposing that each piece of equipment is presumed
to have the potential to emit methane or VOC unless an owner or
operator demonstrates that the piece of equipment does not have the
potential to emit methane or VOC. For a piece of equipment to be
considered not to have the potential to emit methane or VOC, the owner
or operator would need to demonstrate that the process fluids in
contact with the process unit equipment do not contain either methane
or VOC. Commenters \244\ suggested that the EPA maintain the 10 percent
by weight VOC concentration threshold and add a one percent by weight
methane concentration threshold so as to exclude ethane product
streams, produced water streams, and wastewater streams. However, no
additional data or analyses were provided to demonstrate that a
threshold of one percent by weight methane would be appropriate.
Further, recent studies indicate that produced water and wastewater
streams can be significant sources of VOC and/or methane
emissions.\245\ Therefore, the EPA maintains that a definition based on
the potential to emit VOC or methane is appropriate to determine which
process unit equipment must be monitored and repaired.
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\243\ See 86 FR 63182 (November 15, 2021).
\244\ See Document ID No. EPA-HQ-OAR-2021-0317-0808.
\245\ ``Measurement of Produced Water Air Emissions from Crude
Oil and Natural Gas Operations.'' Final Report. California Air
Resources Board. May 2020. Available at: Measurement of Produced
Water Air Emissions from Crude Oil and Natural Gas Operations
(ca.gov).
And ``Inventory of U.S. Greenhouse Gas Emissions and Sinks 1990-
2019: Updates for Produced Water Emissions.'' April 2021. Available
at: https://www.epa.gov/sites/default/files/2021-04/documents/2021_ghgi_update_-_water.pdf.
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Repair Requirements. In this supplemental proposal, the EPA is
proposing a definition of ``first attempt at repair'' consistent with
the November 2021 proposal, which means an action taken for the purpose
of stopping or reducing fugitive emissions to the atmosphere. First
attempts at repair include, but are not limited to, the following
practices where practicable and appropriate: tightening bonnet bolts;
replacing bonnet bolts; tightening packing gland nuts; or injecting
lubricant into lubricated packing. Further, we are proposing a
definition of ``repaired,'' specific to process unit equipment affected
facilities, meaning that equipment is adjusted, or otherwise altered,
in order to eliminate a leak, and is re-monitored to verify that
emissions from the equipment are below the applicable leak definition.
Pumps subject to weekly visual inspections which are designated as
leaking and repaired are not subject to remonitoring. We are adding
these definitions to clarify the requirements for leak repair
associated with process unit equipment. The EPA is not proposing to
require replacement of leaking equipment with low-emissions (``low-e'')
valves or valve packing or require drill-and-tap with a low-e
injectable because it is not appropriate for all valve repairs.
However, because this low-e equipment, which meets the specifications
of API 622 or 624, generally will include a manufacturer written
warranty that it will not emit fugitive emissions at a concentration
greater than 100 ppm within the first 5 years, we believe that they can
be a viable option for repair in some instances, as demonstrated by the
remonitoring requirements in the rule.
As described in the November 2021 proposal, the EPA is proposing to
allow for delay of repair for leaks identified with OGI (or EPA Method
21), where it is technically infeasible to complete repairs within 15
days without a process unit shutdown. Generally, a process unit
shutdown will generate more emissions than allowing the leak to
continue; therefore, we are proposing to retain this delay of repair
provision.
Alternative Use of EPA Method 21. As discussed in the November 2021
proposal, the EPA is proposing to allow the use of EPA Method 21 as an
alternative to the required OGI monitoring. However, unlike NSPS OOOO
and NSPS OOOOa, the EPA is not cross-referencing the requirements in
NSPS VVa and is instead proposing regulatory text which incorporates
the requirements directly into 40 CFR 60.5401b, with conforming changes
consistent with the OGI standards, as described above for pressure
relief devices, CVS, and repairs.
c. Summary of Proposed Requirements.
The proposed standards will apply to the ``process unit equipment''
affected facility and will require that each piece of equipment that
has the potential to emit methane or VOC conduct bimonthly (i.e., once
every other month) OGI monitoring in accordance with appendix K to
detect equipment leaks from pumps, valves, connectors, pressure relief
devices, and CVS. As an alternative to the bimonthly OGI monitoring,
EPA Method 21 may be used to detect leaks from the same equipment as
frequencies specific to the process unit equipment type (e.g., monthly
for pumps, quarterly for valves).
Furthermore, this proposed rule requires that any leaks identified
by AVO, or other detection methods from any equipment in any service,
including open-ended valves or lines, must be repaired. The proposed
rule includes
[[Page 74809]]
requirements for a first attempt at repair for all leaks identified
within five days of detection, and final repair completed within 15
days of detection (unless the delay or repair provisions are
applicable). Delay of repair would be allowed where it is technically
infeasible to complete repairs within 15 days without a process unit
shutdown.
In addition to the monitoring and repair requirements summarized
above, this proposal includes requirements for specific types of
equipment. First, the EPA is proposing that each open-ended valve or
line must be equipped with a closure device (i.e., cap, blind flange,
plug, or a second valve) that seals the open end at all times except
during operations which require process fluid flow through the open-
ended valve or line. Next, CVS used to comply with the standards for
process unit equipment must be monitored bimonthly using OGI (or
quarterly using EPA Method 21 if the alternative is used). We are also
proposing that control devices used to comply with the equipment leak
provisions must comply with the requirements described in section IV.G
of this preamble.
The EPA is proposing that pressure relief devices must be monitored
bimonthly using OGI (or quarterly using EPA Method 21 if the
alternative is used) and five days after a pressure release to ensure
the device has reseated after a pressure release. The proposed rule
allows exceptions to the five-day post-pressure release monitoring
requirement for pressure relief devices that are located in a
nonfractionating plant (instead, the pressure relief device may
monitored after a pressure release the next time monitoring personnel
are onsite, but in no event may it be allowed to operate for more than
30 calendar days after a pressure release without monitoring) or that
are routed to a process, fuel gas system or control device.
This proposed rule requires AVO, or other detection methodologies
for pumps, valves, and connectors in heavy liquid service and pressure
relief devices in light liquid or heavy liquid service and requires
repair where a leak is found using any of those methods.
Reporting would be required semiannually, which differs from the
reporting for other affected facilities in NSPS OOOOb. In the initial
semiannual report, the proposed rule will require the owner or operator
to identify: each process unit associated with the process unit
equipment affected facility; the number of each type of equipment
subject to the monitoring requirements; for each month of the reporting
period, the number of leaking equipment for which leaks were
identified, the number of leaking equipment for which leaks were not
repaired and the facts that explain each delay of repair; and dates of
process unit shutdowns.
In subsequent semiannual reports, owners and operators would be
required to report the name of each process unit associated with the
process unit equipment affected facility; any changes to the process
unit identification or the number or type of equipment subject to the
monitoring requirements; for each month of the reporting period, the
number of leaking equipment for which leaks were identified, the number
of leaking equipment for which leaks were not repaired and the facts
that explain each delay of repair; and dates of process unit shutdowns.
Required records in the proposed rule include inspection records
consisting of equipment identification, date and start and end times of
the monitoring inspection, inspector name, leak determination method,
monitoring instrument identification, type of equipment monitored,
process unit identification, appendix K records (if applicable), EPA
Method 21 instrument readings and calibration results (if applicable)
and, for visual inspections, the date, name of inspector and result of
inspection. For each leak detected, the proposed rule requires
reporting of the instrument and operator identification (or record of
AVO method, where applicable), the date the leak was detected, the date
and repair method applied for first attempts at repair, indication of
whether the leak is still detected, and the date of successful repair,
which includes results of a resurvey to verify repair. For each delay
of repair, the proposed rule requires that the equipment is identified
as ``repair delayed'' along with the reason for the delay, the
signature of the certifying official, and the dates of process unit
shutdowns which occurred while the equipment is unrepaired.
Additionally, the proposed rule requires records of equipment
designated for no detectable emissions; the identification of valves,
pumps, and connectors that are designated as unsafe-to-monitor, an
explanation stating why it is unsafe-to-monitor, and the plan for
monitoring that equipment; a list of identification numbers for valves
that are designated as difficult-to-monitor, an explanation stating why
it is difficult-to-monitor, and the schedule for monitoring each valve;
a list of identification numbers for equipment that is in vacuum
service and a list of identification numbers for equipment designated
as having the potential to emit methane or VOC less than 300 hr/yr.
Finally, for CVS and control devices used to control emissions from
process unit equipment affected facilities, the reports and records
that demonstrate proper design and operation of the control device also
must be maintained (see sections IV.G and IV.J. of this preamble).
2. EG OOOOc
The application of an LDAR program at an existing source is the
same as at a new source because there is no need to retrofit equipment
at the site to achieve compliance with the work practice standard. The
cost effectiveness for implementing a bimonthly OGI LDAR program for
all process unit equipment that has the potential to emit methane is
approximately $850/ton methane reduced. As explained in section III.E
of this preamble, the cost effectiveness of this OGI monitoring option
is within the range of costs we believe to be reasonable for methane
reductions in this rule. Therefore, we consider a bimonthly OGI LDAR
program following appendix K that includes all process unit equipment
that have the potential to emit methane to be BSER for existing
sources. The presumptive standards that are proposed in this action are
the same as those described above for NSPS OOOOb.
M. Sweetening Units
The EPA proposed to retain the standards found in NSPS OOOO and
NSPS OOOOa for reducing SO2 emissions from sweetening units
in the November 15, 2021, proposal. The EPA is proposing regulatory
text at 40 CFR 60.5405b through 60.5408b reflect the standards of
performance as proposed in the November 15, 2021, proposal. To clarify
and align compliance requirements (including recordkeeping and
reporting) for sweetening units with those of other affected
facilities, the EPA is proposing specific language at 40 CFR 60.5405b
which ``points'' the owner or operator to the appropriate compliance
requirement sections (i.e., those containing initial compliance,
continuous compliance, recordkeeping and reporting) and is proposing to
enumerate the initial compliance requirements (of the unchanged
standards) in section 40 CFR 60.5410b(i) and the continuous compliance
requirements (of the unchanged standards) at 40 CFR 60.5415b(k).
N. Recordkeeping and Reporting
In the November 2021 proposal, the EPA proposed to require
electronic reporting of performance test reports, annual reports, and
semiannual reports through the Compliance and Emissions
[[Page 74810]]
Data Reporting Interface (CEDRI). CEDRI can be accessed through the
EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/). As noted in
that proposal, a description of the electronic data submission process
is provided in the memorandum Electronic Reporting Requirements for New
Source Performance Standards (NSPS) and National Emission Standards for
Hazardous Air Pollutants (NESHAP) Rules, available in the docket for
this action. The EPA also proposed to allow owners and operators the
ability to seek extensions for electronic reporting for circumstances
beyond the control of the facility (i.e., for a possible outage in CDX
or CEDRI or for a force majeure event).
In this action, the EPA is not proposing any changes from what was
proposed in the November 2021 proposal. As noted in the November 2021
proposal, owners and operators would be required to use the appropriate
spreadsheet template to submit information to CEDRI for annual and
semiannual reports. A draft version of the proposed templates for these
reports is included in the docket for this action.\246\ The EPA
specifically requests comment on the content, layout, and overall
design of the templates.
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\246\ See Part_60_Subpart_OOOOb_60.5420b(b)_Annual_Report.xlsm
and Part_60_Subpart_OOOOb_60.5422b(b)_Semiannual_Report.xlsx,
available in the docket for this action.
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V. Supplemental Proposal for State, Tribal, and Federal Plan
Development for Existing Sources
A. Overview
In the November 2021 proposal, the EPA proposed EG for states to
follow in developing their plans to reduce emissions of GHGs (in the
form of limitations on methane) from designated facilities within the
Crude Oil and Natural Gas source category.\247\ That proposal provided
a general overview of the state planning process triggered by the EPA's
finalization of EG under CAA section 111(d), the EG process and
proposed state plan requirements in more detail, and solicited comment
on various issues related to the EG. In this supplemental proposal, the
EPA is proposing some adjustments from the November 2021 proposal, and
additional requirements to provide states with information needed for
purposes of state plan development. In the following sections, in the
same six-part ordering as the November 2021 proposal, we summarize and
rationalize the updated and new proposed requirements. The EPA is not
soliciting additional comment on aspects of the November 2021 proposed
EG that are not substantively addressed or changed in this supplemental
proposal.
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\247\ See 86 FR 63110 (November 15, 2021).
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First, we discuss changes to the proposed requirements for
establishing standards of performance in state plans in response to a
finalized EG. Second, we discuss changes to the proposed components of
an approvable state plan submission. Third, we discuss the proposed
timing for state plan submissions, and changes to the proposed timeline
for designated facilities to come into final compliance with the state
plan. While this section describes the requirements of the implementing
regulations under 40 CFR part 60, subpart Ba, proposes requirements for
states in the context of this EG, and solicits comments in the context
of this EG, nothing in this proposal is intended to reopen the
implementing regulations themselves for comment.
B. Establishing Standards of Performance in State Plans
After the EPA establishes the BSER in the final EG, as described in
preamble section XII of the November 2021 proposal and preamble section
IV of this supplemental proposal, each state that includes a designated
facility must develop, adopt, and submit to the EPA its state plan
under CAA section 111(d). Under the Tribal Authority Rule (TAR) adopted
by the EPA, tribes may seek authority to implement a plan under CAA
section 111(d) in a manner similar to a state. See 40 CFR part 49,
subpart A. Tribes may, but are not required to, seek approval for
treatment in a manner similar to a state for purposes of developing a
tribal implementation plan (TIP) implementing the EG. The November 2021
proposal included proposed requirements regarding two key aspects of
implementation: establishing standards of performance for designated
facilities, and providing measures that implement and enforce such
standards. The November 2021 proposal additionally discussed and
solicited comments on accommodating state programs, remaining useful
life and other factors (RULOF), emissions inventories, and meaningful
engagement. In the subsections below, the EPA proposes updates to
certain presumptive standards included in the November 2021 proposal,
and further proposes requirements related to leveraging state programs,
RULOF, certain implementation and enforcement measures, emissions
inventories, and meaningful engagement with pertinent stakeholders. The
EPA believes these proposed requirements, in addition to those
described in the November 2021 proposal, will be necessary for states
to prepare their CAA section 111(d) state plans. The EPA is not
reopening for comment any aspect described in the November 2021
proposal that the EPA is not proposing to substantively address or
update in this supplemental proposal.
The November 2021 proposal included proposed requirements regarding
two key aspects of implementation: establishing standards of
performance for designated facilities and providing measures that
implement and enforce such standards. The November 2021 proposal
additionally discussed and solicited comments on accommodating state
programs, RULOF, emissions inventories, and meaningful engagement. In
the following subsections, the EPA proposes updates to certain
presumptive standards included in the November 2021 proposal, and
further proposes requirements related to leveraging state programs,
RULOF, certain implementation and enforcement measures, emissions
inventories, and meaningful engagement with pertinent stakeholders. The
EPA believes these proposed requirements, in addition to those
described in the November 2021 proposal, will be necessary for states
to prepare their CAA section 111(d) state plans. The EPA is not
reopening for comment any aspect described in the November 2021
proposal that the EPA is not proposing to substantively address or
update in this supplemental proposal.
1. Establish Standards of Performance for Designated Facilities
In the November 2021 proposal, the EPA proposed the degree of
emission limitation achievable through application of the BSER in the
form of presumptive standards for designated facilities.\248\ The EPA
described that there is a fundamental requirement under CAA section
111(d) that a state plan's standards of performance reflect the
presumptive standard, which derives from the definition of ``standard
of performance'' in CAA section 111(a)(1). The EPA is updating Tables
35 and 36 to reflect the updated presumptive standards in this
supplemental proposal.
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\248\ 86 FR 63249 (November 15, 2021).
\249\ As described in section IV.C of this preamble, the EPA is
proposing a super-emitter response program under the statutory
rationale that super-emitters are a designated facility. The EPA is
also proposing the program under a second rationale that the super-
emitter response program constitutes work practice standards for
certain sources and compliance assurance measures for other sources.
Under either rationale, state plans are required to adopt the super-
emitter response program either as presumptive standards or as
measures that provide for the implementation and enforcement of such
standards.
[[Page 74811]]
Table 35--Summary of Proposed EG Subpart OOOOc Presumptive Numerical
Standards
------------------------------------------------------------------------
Proposed presumptive numerical
Designated facility standards in the draft emissions
guidelines for GHGs
------------------------------------------------------------------------
Storage Vessels: Tank Battery with 95 percent reduction of methane.
PTE of 20 tpy or More of Methane.
Pneumatic Controllers: Natural gas- Methane emission rate of zero.
driven that Vent to the Atmosphere.
Pneumatic Pumps...................... Methane emission rate of zero.
Wet Seal Centrifugal Compressors Volumetric flow rate of 3 scfm.
(except for those located at well
sites).
Dry Seal Centrifugal Compressors Volumetric flow rate of 3 scfm.
(except for those located at well
sites).
Reciprocating Compressors (except for Volumetric flow rate of 2 scfm.
those located at well sites).
------------------------------------------------------------------------
Table 36--Summary of Proposed EG Subpart OOOOc Presumptive Non-Numerical
Standards
------------------------------------------------------------------------
Proposed presumptive non-
Designated facility numerical standards in the draft
emissions guidelines for GHGs
------------------------------------------------------------------------
Super-Emitters....................... Root cause analysis and
corrective action following
notification by an EPA-approved
entity or regulatory authority
of a super-emitter emissions
event.\249\
Fugitive Emissions: Single Wellhead Quarterly AVO inspections. Repair
Only Well Sites and Small Well Sites. for indications of potential
leaks within 15 days of
inspection.
Fugitive monitoring continues for
all well sites until the site
has been closed, including
plugging the wells at the site
and submitting a well closure
report.
Fugitive Emissions: Multi-wellhead Quarterly AVO inspections. Repair
Only Well Sites (2 or more for indications of potential
wellheads). leaks within 15 days of
inspection.
Semiannual OGI monitoring
(Optional semiannual EPA Method
21 monitoring with 500 ppm
defined as a leak).
First attempt at repair within 30
days of finding fugitive
emissions. Final repair within
30 days of first attempt.
Fugitive monitoring continues for
all well sites until the site
has been closed, including
plugging the wells at the site
and submitting a well closure
report.
Fugitive Emissions: Well Sites and Well sites with specified major
Centralized Production Facilities. production and processing
equipment: Quarterly OGI
monitoring. (Optional quarterly
EPA Method 21 monitoring with
500 ppm defined as a leak).
First attempt at repair within 30
days of finding fugitive
emissions. Final repair within
30 days of first attempt.
Fugitive monitoring continues for
all well sites until the site
has been closed, including
plugging the wells at the site
and submitting a well closure
report.
Fugitive Emissions: Compressor Monthly AVO monitoring.
Stations. AND
Quarterly OGI monitoring.
(Optional quarterly EPA Method
21 monitoring with 500 ppm
defined as a leak).
First attempt at repair within 30
days of finding fugitive
emissions. Final repair within
30 days of first attempt.
Fugitive Emissions: Well Sites and Annual OGI monitoring. (Optional
Compressor Stations on Alaska North annual EPA Method 21 monitoring
Slope. with 500 ppm defined as a leak).
First attempt at repair within 30
days of finding fugitive
emissions. Final repair within
30 days of first attempt.
Fugitive Emissions: Well Sites and (Optional) Alternative periodic
Compressor Stations. screening with advanced
measurement technology instead
of OGI monitoring.
Fugitive Emissions: Well Sites and (Optional) Alternative continuous
Compressor Stations. monitoring system instead of OGI
monitoring.
Pneumatic Controllers: Alaska (at Natural gas bleed rate no greater
sites where onsite power is not than 6 scfh.
available--continuous bleed natural
gas-driven).
Pneumatic Controllers: Alaska (at OGI monitoring and repair of
sites where onsite power is not emissions from controller
available--intermittent natural gas- malfunctions.
driven).
Gas Well Liquids Unloading........... Perform liquids unloading with
zero methane or VOC emissions.
If this is not feasible for
safety or technical reasons,
employ best management practices
to minimize venting of emissions
to the maximum extent possible.
Equipment Leaks at Natural Gas LDAR with OGI following
Processing Plants. procedures in appendix K.
[[Page 74812]]
Oil Wells with Associated Gas........ Route associated gas to a sales
line. If access to a sales line
is not available, the gas can be
used as an onsite fuel source or
used for another useful purpose
that a purchased fuel or raw
material would serve. If
demonstrated that a sales line
and beneficial uses are not
technically feasible, the gas
can be routed to a flare or
other control device that
achieves at least 95 percent
reduction in methane emissions.
------------------------------------------------------------------------
2. Leveraging State Programs
a. Overview
In the November 2021 proposal, the EPA acknowledged that many
states have programs they may want to leverage for purposes of
satisfying their CAA section 111(d) state plan obligations (86 FR
63252; November 21, 2021). The EPA proposed that a state plan which
relies on a state program must establish standards of performance that
are in the same form as the presumptive standards. The EPA further
solicited comment on whether states relying on state programs should be
authorized to include a different form of standard in their plans so
long as they demonstrate the equivalency of such standards to the level
of stringency required under the final EG, and how such equivalency
demonstrations can be made in a rigorous and consistent way.
The EPA also proposed to require that, in situations where a state
wishes to rely on state programs (statutes and/or regulations) that
pre-date finalization of the EG proposed in this document to satisfy
the requirements of CAA section 111(d), the state plan should identify
which aspects of the state programs are being submitted for approval as
federally enforceable requirements under the plan, and include a
detailed explanation and analysis of how the relied upon state programs
are at least as stringent as the requirements of the final EG. The EPA
noted that the completeness criteria in 40 CFR 60.27a(g) requires a
copy of the actual state law/regulation or document submitted for
approval and incorporation into the state plan. Put another way, where
a state is relying on a state program for its plan, a copy of the pre-
existing state statute or regulation underpinning the program would be
required by this criterion and would be a critical component of the
EPA's evaluation of the approvability of the plan. The EPA solicited
comment on various ways in which state programs can be adopted into
state plans particularly in situations where state programs that
regulate both designated facilities and sources not considered as
designated facilities under this EG could be tailored for a state plan
to meet the requirements of CAA section 111(d).
The EPA believes that for states to successfully leverage their
state programs to satisfy their CAA section 111(d) state plan
obligations, specific criteria need to be identified for states and the
EPA to follow in determining that a state plan meets the level of
stringency required under the final EG, and how such equivalency
demonstrations can be made in a rigorous and consistent way. The EPA is
proposing such criteria for a source-by-source equivalency
determination in this supplemental proposal.
Some commenters requested that the EPA make an equivalency
determination on a programmatic, rather than source-specific basis.
Some of these commenters suggested that the EPA approve plans that are
as stringent as EG even if they do not include identical standards or
sources.\250\ Commenters also suggested that the EPA allow states to
include a different form of numerical standard as long as it is
determined to be equivalent.\251\ In addition to the suggestion
provided, some commenters argued that the EPA is not authorized to
approve state limitations that were not derived using CAA section
111(d) standard setting methods.
---------------------------------------------------------------------------
\250\ See Docket ID Nos. EPA-HQ-OAR-2021-0317-0581, EPA-HQ-OAR-
2021-0317-0775, EPA-HQ-OAR-2021-0317-0926, and EPA-HQ-OAR-2021-0317-
1267.
\251\ See Docket ID Nos. EPA-HQ-OAR-2021-0317-0558, EPA-HQ-OAR-
2021-0317-0761, EPA-HQ-OAR-2021-0317-0769, and EPA-HQ-OAR-2021-0317-
1267.
---------------------------------------------------------------------------
The following sections discuss EPA's proposal for how states with
programs that regulate GHGs in the form of methane from oil and natural
gas sources may establish source-by-source equivalency with the EPA's
designated facility presumptive standards under EG OOOOc. Consistent
with that discussion, the EPA is also proposing to interpret CAA
section 111 to authorize states to establish standards of performance
for their sources that, in the aggregate, would be equivalent to the
presumptive standards. The 2019 Affordable Clean Energy (ACE) Rule
interpreted CAA section 111 to require that each state establish for
each source a standard of performance that reduces that source's
emissions, and to preclude the type of compliance flexibility that the
EPA is now proposing. 84 FR 32556-57 (July 8, 2019). In 2021, the D.C.
Circuit vacated the ACE Rule, holding, among other things, that CAA
section 111(d) does not preclude states from allowing certain
compliance flexibilities, including trading or averaging of emission
limits. American Lung Ass'n v. EPA, 985 F.3d 914, 957-58 (D.C. Cir.
2021). In 2022, the U.S. Supreme Court reversed the D.C. Circuit's
judgment regarding the ACE Rule's embedded repeal of the Clean Power
Plan on other grounds. West Virginia v. EPA, 142 S. Ct. 2587 (2022).
The Supreme Court made clear that CAA section 111 authorizes the EPA to
determine the BSER and the amount of emission limitation that state
plans must achieve, id. at 2601-02, but the Supreme Court did not
address the D.C. Circuit's interpretation of CAA section 111 as to the
state's compliance flexibilities. Id. at 2615-16.
The EPA has reconsidered the ACE Rule's interpretation of CAA
section 111, and now disagrees with it. Section 111(d) does not, by its
terms, preclude states from having flexibility in determining which
measures will best achieve compliance with the EPA's emission
guidelines. Such flexibility is consistent with the framework of
cooperative federalism that CAA section 111(d) establishes, which vests
states with substantial discretion. CAA section 111(d) thus permits
each state, when appropriate, to adopt measures that allow its sources
to meet their emission limits in the aggregate. In addition, the EPA
agrees with the separate set of reasons that the D.C. Circuit gave in
holding that CAA section 111(d) does not preclude a state from allowing
its sources compliance flexibilities. American Lung Ass'n v. EPA, 985
F.3d 914, 957-58. Thus, it is the EPA's
[[Page 74813]]
position that CAA section 111(d) authorizes the EPA to allow states, in
particular rules, to achieve the requisite emission limitation through
the aggregate reductions from their sources, and the EPA is accordingly
proposing to authorize states to leverage their state programs to
satisfy their CAA section 111(d) state plan obligations pursuant to EG
OOOOc, subject to requirements discussed in the following sections.
The EPA intends shortly to propose revisions to the implementing
regulations for CAA section 111(d) at 40 CFR part 60, subpart Ba. The
EPA intends, in that rulemaking, to further clarify that CAA section
111(d) and the implementing regulations authorize the EPA to, in
particular rules, allow states flexibility and discretion in
establishing standards of performance that meet the emission
guidelines, including standards that permit their sources to comply via
methods such as trading or averaging. The EPA encourages interested
persons to submit comments on this issue in that rulemaking for the
implementing regulations, and the EPA intends to finalize that
rulemaking before finalizing this oil and gas rulemaking.
b. Types of Equivalency Evaluations
For purposes of this supplemental proposal, the EPA contemplated
two types of equivalency evaluations that could be considered when
comparing state programs against the stringency of EG OOOOc. These
include: (1) Total program evaluation, and (2) source-by-source
evaluation.
i. Total Program Evaluation
The first type of equivalency evaluation the EPA assessed is a
total program evaluation, meaning assessing reductions and controls
across all or different designated facilities. A total program
evaluation could entail that some sources would get more reductions
than the presumptive standards in the EG and others less reductions,
but overall reductions are equal or greater than what would be achieved
in the aggregate across all designated facilities by implementing the
presumptive standards. A total program evaluation may look different
for states that have designated facilities in the production,
processing, and transmission and storage segments compared to states
that only have designated facilities in the transmission and storage
segment. The EPA recognizes that potentially allowing for total program
equivalency could, in theory, reduce burden on states by allowing
states with programs to rely more on those programs for their state
plan submittal without needing to revise standards for specific
designated facilities in order to match the presumptive standards.
Furthermore, the EPA recognizes that burden may be reduced for owners
and operators of designated facilities because they would not have to
comply with two different sets of regulations. However, the EPA has
identified the following challenges and complexities that are unique to
the Crude Oil and Natural Gas source category and is therefore
proposing to disallow state plans from using total program equivalence
to meet the requirements of a final OOOOc EG.
One such consideration is that state programs may include sources
that are not designated facilities. For example, New Mexico,
Pennsylvania, and Ohio have state standards for pigging activities. The
EPA is not proposing to determine a BSER or presumptive standards for
pigging activities in this supplemental proposal. Because CAA section
111(d)(1) only provides that state plans may include standards of
performance and certain other requirements for designated facilities,
the EPA interprets the statute as not allowing the EPA to approve, and
thereby render federally enforceable, state plan requirements that
extend to sources that are not designated facilities. Therefore, it is
not appropriate to allow a state to account for non-designated
facilities as part of their state plan submission for any purpose,
including for demonstrating program equivalency, even if a state
regulates such sources as a matter of state law.\252\
---------------------------------------------------------------------------
\252\ The EPA acknowledges that states may choose to regulate
non-designated facilities under state law for other purposes than to
satisfy their CAA section 111(d) state plan submission.
---------------------------------------------------------------------------
In addition, the EPA also interprets CAA section 111(d) as not
allowing the EPA to approve state plan requirements for different
pollutants than those designated pollutants that are regulated in the
EG. The EPA is aware that while numerous states have programs in place
that regulate emissions from the designated facilities that the EPA is
proposing presumptive standards for, many of those programs do not
regulate GHGs in the form of limitations on methane.
The EPA also proposed in the November 2021 proposal that states are
generally expected to establish the same non-numerical standards and if
a state chooses to utilize a different design, equipment, work
practice, and/or operational standard then the state must include in
its plan a demonstration of equivalency that is consistent with
alternative means of emissions limitations (AMEL) provisions. Some
state commenters agreed with the EPA that states are expected to
establish the same non-numerical standards.\253\ The EPA recognizes if
a state sought to utilize a different design, equipment, work practice,
and/or operational standard, a demonstration of equivalency that is
consistent with AMEL provisions would likely be technically difficult
because many of the presumptive standards in the EG OOOOc are work
practice standards that do not quantify emissions. This would suggest
that the equivalency evaluation would need to be a qualitative analysis
rather than a quantitative analysis because not all states have
comprehensive source and source-specific emissions inventory data to
base a stringency comparison on emissions reductions alone. The EPA
believes this qualitative comparison would be extremely complicated on
a holistic total program basis given that there are nine types of
designated facilities with proposed presumptive standards, of which,
five have numerical limits and two are in the format of work practice
standards. Without a clear structure for this evaluation to address the
complexities of the Crude Oil and Natural Gas source category, the EPA
is concerned that emission reductions and controls consistent with the
EG, and consistency of implementation across state plans, would be
compromised. Similarly, the EPA proposed that for designated facilities
with numerical presumptive standards, states are expected to establish
the same form of numerical standards, but the EPA also took comment on
whether to allow states to include a different form of numerical
standards for these facilities so long as states demonstrate
equivalency. Some state commenters suggested that the ability to
include a different form of numerical standard in state plans is
consistent with the cooperative federalism structure of CAA section
111(d).\254\ While states asked for this flexibility, state commenters
did not clearly provide specific examples of where a state already has
a different form of a numerical standard that would necessitate this
flexibility. The EPA is also concerned that there may be insufficient
state comprehensive source and source-specific emissions inventory data
to make the requisite technical evaluation.
---------------------------------------------------------------------------
\253\ See Docket ID No. EPA-HQ-OAR-2021-0317-1267.
\254\ See Docket ID No. EPA-HQ-OAR-2021-0317-1267.
---------------------------------------------------------------------------
[[Page 74814]]
Another complicating scenario informing the EPA's proposal to
disallow total program equivalence is that there are instances where a
state covers part or subset of the EG designated facility's
applicability definitions. For example, Colorado requires the use of
non-emitting \255\ pneumatic controllers with specific exceptions. One
exception is that operators do not have to retrofit their controllers
to become non-emitting if on a company-wide basis, the average
production from producing wells in 2019 is less than 15 barrel of oil
equivalent/day/well. However, the EPA's supplemental proposal for
pneumatic controllers, as discussed in section VII.D of this preamble,
proposes a methane emission rate of zero with no applicability site
wide production or other threshold thus covering a broader group of
pneumatic controllers. If the EPA were to permit total program
equivalence where state programs do not align with the EG, then there
could be situations where a state would be allowed to forgo regulating
some designated facilities that the EPA has determined are reasonable
to control.
---------------------------------------------------------------------------
\255\ The terms ``zero emissions'' and ``non-emitting'' are used
to describe pneumatic controllers. In Colorado, 5 CCR Regulation 7,
Part D, Section III, defines a ``non-emitting'' controller as ``a
device that monitors a process parameter such as liquid level,
pressure or temperature and sends a signal to a control valve in
order to control the process parameter and does not emit natural gas
to the atmosphere. Examples of non-emitting controllers include but
are not limited to: no-bleed pneumatic controllers, electric
controllers, mechanical controllers and routed pneumatic
controllers.'' A routed pneumatic controller is defined as ``a
pneumatic controller that releases natural gas to a process, sales
line or to a combustion device instead of directly to the
atmosphere.'' The EPA is proposing that pneumatic controllers must
be ``zero emission'' controllers. The difference in non-emitting, as
defined by Colorado and zero emissions, as proposed in this action,
is that pneumatic controllers for which emissions are captured and
routed to a combustion device are not considered to be ``zero
emission'' controllers. Therefore, routing to a combustion device is
not an option for compliance with the proposed EG OOOOc.
---------------------------------------------------------------------------
For these reasons and the critical need to provide clear regulatory
certainty to the hundreds of thousands of designated facilities in this
uniquely large source category, the EPA does not think a total program
evaluation would guarantee that the same emissions reductions as
required by the EG would be achieved. The EPA solicits comments on how
a total program evaluation could be established in a way that would
address the complexities of the Crude Oil and Natural Gas source
category and concerns the EPA has identified.
ii. Source-by-Source Evaluation
The second type of equivalency considered is a source-by-source
evaluation for a specific designated facility, such as between all
storage vessels located in a state or between a subset of centrifugal
compressors. A source-by-source evaluation could entail a state
conducting equivalency evaluation for one or more designated facilities
and their respective presumptive standards. In theory, if a state were
to do a source-by-source evaluation for each individual designated
facility in its state, this could be considered a form of total program
evaluation that is distinct from the type of total program evaluation
described above that the EPA is proposing to disallow, where
equivalence can be evaluated across different designated facilities
rather than designated facilities of the same type. A source-by-source
evaluation assumes that all sources in a state that meet the
applicability definition for a specific designated facility (e.g.,
pneumatic controllers, pneumatic pumps, and reciprocating compressors),
would in the aggregate have to achieve the same or better reductions of
the same designated pollutant as if the state instead imposed the
presumptive standards required under the EG. A source-by-source
evaluation, in theory, may push states to make changes to their state
rules, which may increase burden on states, but is likely a more
reliable way to determine that the state is achieving all emission
reductions equivalent to implementing the presumptive standards. Given
that state programs do vary considerably, a source-by-source evaluation
would allow states to pick and choose which state standards they want
to leverage for purpose of their state plan development. It is
theoretically less technically difficult to evaluate equivalency on a
source-by-source basis for the Crude Oil and Natural Gas source
category compared to total program equivalence. The EPA is proposing
five basic criteria for when states may use a source-by-source
evaluation as part of their state plans (discussed in section
V.B.2.b.iii of this preamble).
An example of a source-by-source stringency comparison is the
comparison the EPA prepared when assessing the stringency of state
fugitive emissions monitoring programs compared to what was required
under NSPS OOOOa.\256\ Similar to that example, the EPA proposes that
any stringency comparison conducted to determine equivalence with the
proposed presumptive standards that are work practices will need to be
designated facility specific and the qualitative assessment will need
to be tailored to ensure that the correct technical metrics are being
compared.
---------------------------------------------------------------------------
\256\ Memorandum: Equivalency of State Fugitive Emissions
Programs for Well Sites and Compressor Stations to Proposed
Standards at 40 CFR part 60, subpart OOOOa. See Document ID No. EPA-
HQ-OAR-2017-0483-2277.
---------------------------------------------------------------------------
iii. Source-by-Source Evaluation Criteria and Methodology
In order to implement a source-by-source evaluation, the EPA is
proposing five basic criteria to determine whether a source-by-source
evaluation can be considered for equivalency. The criteria are: (1)
Designated facility, (2) designated pollutant, (3) standard type/format
of standard (e.g., numeric, work practice), (4) emission reductions
(with consideration of applicability thresholds and exemptions), and
(5) compliance assurance requirements (e.g., monitoring, recordkeeping,
and reporting).
In the following paragraphs, the EPA proposes a source-by-source
equivalency step-by-step approach followed by an example for
hypothetical state rules illustrating how states could implement the
proposed approach when conducting a state rule equivalency
determination with the proposed presumptive standards.
Step One. Is state rule designated facility definition, pollutant,
and format the same? The first questions that a state needs to answer
is whether their program defines their regulated emissions source
similar to how the EPA defines a designated facility. Do their program
requirements for the designated facility regulate the same pollutant,
and is the format of the standard the same (e.g., work practice or
performance based numerical standard)? If the answer is no to any of
these questions (e.g., state program regulates VOC and not methane),
then the state plan cannot include an equivalency determination with
the EPA's proposed presumptive standards for the designated facility.
If the answer is yes to all of these questions, a state would proceed
to Step Two.
Step Two. Emissions Reductions. A state plan needs to include a
demonstration that the state requirements for designated facilities
achieve the same or greater emissions reduction as the designated
facility presumptive standards. A state would have several options to
make this demonstration.
[[Page 74815]]
The first option would be to make a demonstration that the
designated facility state standard achieves the same emission reduction
as the designated facility BSER analysis using the EPA model plant/
representative facility. The second option would be to make a
demonstration that the designated facility state standard achieves the
same or greater emissions reduction ``in real life'' as the designated
facility model plant/representative facility emission reduction in the
BSER analysis. The third option would be that a state could apply the
designated facility presumptive standard to ``real life'' (e.g., using
activity (number of sources) and actual emissions data) and calculate
the state-wide emission reduction that would be achieved, and then
demonstrate that the state program requirements for a designated
facility would achieve the same or greater emissions reduction. If
emissions reductions from the implementation of the state rule are less
than would be achieved from the implementation of the presumptive
standards, the state cannot make an equivalency determination with the
EPA's proposed presumptive standards. If emissions reductions from the
implementation of the state rule are the same or greater than would be
achieved from the implementation of the presumptive standards, a state
would proceed to Step Three.
Step Three. Make demonstration that compliance measures included
for a designated facility under a state program are at least as
effective as those in the presumptive standard. Once a state has
determined that the emission reductions from the implementation of the
state requirements for a designated facility are the same or greater
than would be achieved by the implementation of the presumptive
standards for a designated facility under Step Two, a state plan would
need to include a demonstration that compliance measures (e.g.,
monitoring, recordkeeping and reporting requirements) are sufficient to
ensure continued compliance with the standards and projected emission
reductions.
Centrifugal Compressor Examples--Comparison of Primary Presumptive
Standards With 4 Hypothetical Examples.
Table 37 provides examples of the application of the steps outlined
above for five hypothetical state rules for reciprocating compressors
at gathering and boosting stations in the production segment. The
parameters for the presumptive standard for reciprocating compressors
are as follows.
(1) The designated facility is a single reciprocating compressor.
(2) The designated pollutant is methane, using volumetric flow rate
as a surrogate for methane).
(3) The standard type/format of standard is a numerical standard (2
scfm volumetric flow rate).
(4) The estimated methane emission reductions for the model
compressor in the BSER analysis for the presumptive standard was 92
percent reduction.
(5) The compliance assurance requirements include the requirement
to measure the flow rate once every 8,760 operating hours and maintain
records.
Table 37--Reciprocating Compressor Designated Facility Presumptive Standards Equivalency Evaluation Examples
----------------------------------------------------------------------------------------------------------------
Equivalency determination steps
---------------------------------------------------------------------------
Designated facility requirements Step one--
applicability and Step two--emission Step three-- compliance
format of standard reduction assurance measures
----------------------------------------------------------------------------------------------------------------
Example A:
Designated Facility: Single FAIL--format of
Reciprocating Compressor at standard not
Gathering and Boosting. equivalent.
Designated Pollutant: Methane...
Format of Standard: Work
Practice (Change out rod
packing every 3 years).
Estimated Emission Reduction
(Basis): 56% (model compressor
basis).
Compliance Assurance
Requirements: Records of
changeout.
Example B:
Designated Facility: Single PASS................... PASS.................. PASS.
Reciprocating Compressor at
Gathering and Boosting.
Designated Pollutant: Total
hydrocarbon as Surrogate for
Methane.
Format of Standard: Numerical
(Collect and route to control
to achieve 95% reduction).
Estimated Emission Reduction
(Basis): 95% (model compressor
basis).
Compliance Assurance
Requirements: Performance test
of control device, continuous
parameter monitoring,
recordkeeping and reporting.
Example C:
Designated Facility: Single FAIL--format of
Reciprocating Compressor at standard not
Gathering and Boosting. equivalent.
Designated Pollutant: Total Gas
Flow rate as surrogate for
methane.
Format of Standard: Directed
Inspection and Maintenance
(Measure flow rate annually and
replace or repair if volumetric
flow is greater than 3 scfm).
Estimated Emission Reduction
(Basis): 92% (model compressor
basis).
----------------------------------------------------------------------------------------------------------------
[[Page 74816]]
Table 37--Reciprocating Compressor Designated Facility Presumptive Standards Equivalency Evaluation Examples--
Continued
----------------------------------------------------------------------------------------------------------------
Equivalency determination steps
---------------------------------------------------------------------------
Designated facility requirements Step one--
applicability and Step two--emission Step three-- compliance
format of standard reduction assurance measures
----------------------------------------------------------------------------------------------------------------
Compliance Assurance
Requirements: Records of
measurements, records of
corrective actions if greater
than 3 scfm, records of new
measurement to demonstrate less
than 3 scfm after corrective
action.
Example D:
Designated Facility: Single
Reciprocating Compressor at
Gathering and Boosting.
Designated Pollutant: Total gas
flow rate as surrogate for
methane.
Format of Standard: Numerical: 5
scfm.
Estimated Emission Reduction
(Basis): using analysis of
state-wide emissions from
actual reciprocating
compressors, estimated that
presumptive standard would
achieve 85% reduction over the
state, state rule would achieve
87% reduction..
Compliance Assurance PASS................... PASS Demonstrated that PASS.
Requirements: Measure the ``real life''
volumetric flow rate once every state-wide emission
six months, record results.. reduction for state
rule was greater than
the ``real-life''
reduction for the
presumptive standard..
Example E:
Designated Facility: Single PASS................... FAIL--did not .........................
Reciprocating Compressor at demonstrate that the
Gathering and Boosting. BSER presumptive
standard model
facility reduction
was met.
Designated Pollutant: Total gas
flow rate as surrogate for
methane.
Format of Standard: Numerical: 4
scfm.
Estimated Emission Reduction
(Basis): 88% (analysis of state-
wide emissions from actual
reciprocating compressors).
Compliance Assurance
Requirements: Measure
volumetric flow rate once every
six months, record results.
----------------------------------------------------------------------------------------------------------------
The EPA solicits comment on the EPA's proposed state program
equivalency demonstration methodology and evaluating criteria for when
state plans may include standards of performance based on an
equivalency demonstration. Specifically, the EPA solicits comments on
other criteria than what the EPA is proposing should be considered; and
whether there are other additional qualitative factors/criteria need to
be included to make an effective stringency evaluation for different
types of different design, equipment, work practice, and/or operational
standards.
c. General Permitting Programs
The EPA also recognizes that some states may regulate the
designated facilities proposed to be regulated under the EGs through a
general permit program. For example, general permits often include
standardized terms and conditions related to emissions control,
compliance certification, notification, recordkeeping, reporting, and
source testing requirements. The EPA is not proposing a regulatory
amendment on this point but confirms that the implementing regulations
under subpart Ba allows for standards of performance and other state
plan requirements to be established as part of state permits and
administrative orders, which are then incorporated into the state plan.
See 40 CFR 60.27a(g)(2)(ii).
However, the EPA notes that the permit or administrative order
alone may not be sufficient to meet the requirements of an EG or the
implementing regulations, including the completeness criteria under 40
CFR 60.27a(g). For instance, a plan submission must include supporting
material demonstrating the state's legal authority to implement and
enforce each component of its plan, including the standards of
performance. Id. at 40 CFR 60.27a(g)(2)(iii). In addition, EG OOOOc may
also require demonstrations that may not be satisfied by terms of a
permit or administrative order. To the extent that these and other
requirements are not met by the terms of the incorporated permits and
administrative orders, states will need to include materials in a state
plan submission demonstrating how the plan meets those requirements.
3. Remaining Useful Life and Other Factors (RULOF)
Under CAA section 111(d), the EPA is required to promulgate
regulations under which states submit plans establishing standards of
performance for designated facilities. While states establish the
standards of performance, there is a fundamental obligation under CAA
section 111(d) that such standards reflect the degree of emission
limitation achievable through the application of the BSER, as
determined by the EPA. As previously described, this obligation derives
from the definition of ``standard of performance'' under CAA section
111(a)(1). The EPA identifies the degree of emission limitation
achievable through application of the BSER as part of its EG. 40 CFR
60.22a(b)(5).
While standards of performance must generally reflect the degree of
emission limitation achievable through application of the BSER, CAA
section 111(d)(1) also requires that the EPA regulations permit the
states, in
[[Page 74817]]
applying a standard of performance to a particular designated facility,
to take into account the designated facility's RULOF. The EPA's
implementing regulations under 40 CFR 60.24a(e) allows a state to
consider a designated facility's RULOF in applying a standard of
performance less stringent than the presumptive level of stringency
given in an EG to a particular source, provided that the state makes
the required demonstration under this provision. However, as described
further below, this provision does not provide clear parameters for
states on how and when to apply a standard less stringent than the
presumptive level of stringency given in an EG to a particular source.
The EPA intends to propose clarifying revisions to this provision under
the implementing regulations in an upcoming rulemaking that would apply
generally to new EG promulgated under CAA section 111(d). While
inviting comments on the application of these proposed revisions in the
context of the oil and gas sector in this rulemaking, the EPA also
encourages the public to provide comments on these proposed revisions
more generally in that upcoming rulemaking process to amend the
implementing regulations. The EPA intends to finalize that rulemaking
before finalizing this oil and gas rulemaking.
Consistent with its intended revisions to the implementing
regulations, the EPA is proposing to supersede the current 40 CFR
60.24a(e) by providing requirements specific to EG OOOOc for the
consideration of RULOF in state plans to set a less stringent standard
for a particular source. The EPA notes that the EPA considers the
application of the proposed RULOF provisions to apply in circumstances
distinct from source-by-source evaluation discussed earlier in section
V.B.2. In other words, these provisions apply where a state intends to
depart from the presumptive standards in EG OOOOc and propose a less
stringent standard for a designated facility (or class of facilities),
and not where a state intends to comply by demonstrating that a
facility or group of facilities subject to a state program would, in
the aggregate, achieve equivalent or better reductions than if the
state instead imposed the presumptive standards required under the EG.
The EPA's proposed RULOF requirements for the application of a less
stringent standard and rationale are as follows.
The RULOF provision currently under 40 CFR 60.24a(e) allows states
to consider RULOF to apply a less stringent standard of performance for
a designated facility or class of facilities if they demonstrate one of
the three following circumstances: unreasonable cost of control
resulting from plant age, location, or basic process design; physical
impossibility of installing necessary control equipment; or other
factors specific to the facility (or class of facilities) that make
application of a less stringent standard or final compliance time
significantly more reasonable. The implementing regulations also
specify that, absent such a demonstration, the state's standards of
performance must be ``no less stringent than the corresponding'' EG. 40
CFR 60.24a(c). This supplemental proposal largely retains the substance
of this threshold provision for purposes of EG OOOOc, including the
three circumstances under which a less stringent standard of
performance may be applied, and provide further clarification of what a
state must demonstrate in order to invoke RULOF when submitting a state
plan. Specifically, the EPA proposes to require the state to
demonstrate that a particular facility cannot reasonably achieve the
degree of emission limitation achievable through application of the
BSER, based on one or more of the three circumstances. The EPA is also
proposing to clarify the third circumstance by specifying that states
may apply a less stringent standard if factors specific to the facility
are fundamentally different than those considered by the EPA in
determining the BSER. Subsection a. describes the statutory and
regulatory background, and subsection b. explains the agency's
rationale for its proposal. Subsections c-h describe further proposed
additions to the RULOF provision in cases where states seek to apply a
standard that is less stringent than the degree of emission limitation
achievable through application of the BSER. These proposed additions
include requirements for the calculation of a less stringent standard,
contingency requirements in cases where an operating condition is the
basis for RULOF, and the consideration of disproportionately impacted
communities. Finally, subsection i. describes the proposal to address
cases where states seek to apply a more stringent standard.
a. Statutory and Regulatory Background
The 1970 version of CAA section 111(d) made no reference to the
consideration of RULOF in the context of standards for existing
sources. In the 1975 regulations promulgating subpart B, however, the
EPA included a so-called variance provision. For health-based
pollutants, states could apply a standard of performance less stringent
than the EPA's EGs based on cost, physical impossibility, and other
factors specific to a designated facility that make the application of
a less stringent standard significantly more reasonable. 40 CFR
60.24(f). For welfare-based pollutants, states could apply a less
stringent standard by balancing the requirements of an EG ``against
other factors of public concern.'' 40 CFR 60.24(d). As part of the 1977
CAA amendments, Congress amended CAA section 111(d)(1) to require that
the EPA's regulations under this section ``shall permit the State in
applying a standard of performance to any particular source under a
plan submitted under this paragraph to take into consideration, among
other factors, the remaining useful life of the existing source to
which such standard applies.'' At the time, the EPA considered the
variance provision under subpart B to meet this requirement and did not
revise the provision subsequent to the 1977 CAA amendments until
promulgating new implementing regulations in 2019 under subpart Ba. As
part of the 2019 revisions, the EPA removed the health and welfare-
based pollutants distinction and collapsed the associated requirements
of the previous variance provision into a single, new RULOF provision
under 40 CFR 60.24a(e). 84 FR 32520, 32570. The D.C. Circuit vacated
several timing-related provisions under 40 CFR part 60, subpart Ba;
however, Petitioners did not challenge, and the court did not vacate,
the new RULOF provision under 40 CFR 60.24a(e). Am. Lung Assoc. v. EPA,
985 F.3d at 991 (D.C. Cir. 2021) (ALA).\257\
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\257\ The Supreme Court subsequently reversed and remanded the
D.C. Circuit's opinion. West Virginia v. EPA, 142 S.Ct. 2587 (June
30, 2022). However, no Petitioner sought certiorari on, and the West
Virginia decision did not implicate, the D.C. Circuit's vacatur of
portions of subpart Ba.
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b. Rationale for the Proposed Revisions
As previously described, the statute expressly requires the EPA to
permit states to consider RULOF for a particular designated facility
when applying a standard of performance to that facility. The
consideration of remaining useful life in particular can be an
important consideration, as the cost of control for a specific
designated facility that is not expected to operate in the long term,
relative to other designated facilities in the source category, could
significantly vary from the average cost calculations done as part of
the BSER determination for the source category as a whole. In such an
instance, and in others as described throughout this section, a less
stringent standard may be more reasonable to
[[Page 74818]]
apply than a standard of performance that reflects the presumptive
level of stringency.
In order to understand how states may have dealt with this issue in
their programs, the EPA examined several existing state oil and natural
gas regulations and programs. Based on our examination, we did not
identify any provision in any of the state oil and natural gas
regulations that included a less stringent standard for equipment or
operations with a shortened lifespan. The EPA is interested in
obtaining information on whether this situation exists in state oil and
natural gas rules that we may not have identified in our search. In
addition, the EPA is soliciting comment on situations where state rules
for industries other than the oil and natural gas industry include less
stringent requirements for sources that are soon to retire. If these
situations exist, the EPA is not only interested in the less stringent
requirements as they compare to the ``normal'' standards, but also how
the state evaluated the suitability of the less stringent requirements.
As currently written, the RULOF provision in subpart Ba does not
provide clear parameters for states on how and when to apply a standard
less stringent than the presumptive level of stringency given in an EG
to a particular source. As written, the references to reasonableness in
this provision are potentially subject to widely differing
interpretations and inconsistent application among states developing
plans, and by the EPA in reviewing them. Without a clear analytical
framework for applying RULOF, the current provision may be used by
states to set less stringent standards that could effectively undermine
the overall presumptive level of stringency envisioned by the EPA's
BSER determination and render it meaningless.\258\ Such a result is
contrary to the overarching purpose of CAA section 111(d), which is
generally to require meaningful emission reductions from designated
facilities based on the BSER.
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\258\ CAA section 111(d) does not require states to consider
RULOF, but rather requires that the EPA's regulations ``permit''
states to do so. In other words, the EPA must provide states with
the ability to account for RULOF, but states may instead choose to
establish a standard of performance that is the same as the
presumptive level of stringency set forth in the EGs. The
optionality, rather than mandate, for states to account for RULOF
supports the notion that this provision is not intended to undermine
the presumptive level of stringency in an EG for the source category
broadly. Additionally, the EPA notes that it is not aware of any CAA
section 111(d) EGs under which an EPA-approved state plan has
previously considered RULOF to apply a standard of performance that
deviates from the presumptive level of stringency. Clarifying
parameters may better enable states to effectively use this
provision in developing their state plans.
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Additionally, while states have discretion to consider RULOF under
CAA section 111(d), it is the EPA's responsibility to determine whether
a state plan is ``satisfactory,'' \259\ which includes evaluating
whether RULOF was appropriately considered. The relevant dictionary
meaning of ``satisfactory'' is ``fulfilling all demands or
requirements.'' The American College Dictionary 1078 (C.L. Barnhart,
ed. 1970). Thus, the most reasonable interpretation of a ``satisfactory
plan'' is a CAA section 111(d) plan that meets the applicable
conditions or requirements, including those under the implementing
regulations that the EPA is directed to promulgate pursuant to CAA
section 111(d), including the provisions governing the application of
RULOF.\260\
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\259\ CAA section 111(d)(2)(A) authorizes the EPA to promulgate
a Federal plan for any state that ``fails to submit a satisfactory
plan'' establishing standards of performance under CAA section
111(d)(1). Accordingly, the EPA interprets ``satisfactory'' as the
standard by which the EPA reviews state plan submissions.
\260\ Although there is no case law specifically on the standard
of review of a CAA section 111(d)(1) state plan or the EPA's duty to
approve satisfactory plans, the EPA's action on a CAA section
111(d)(1) state plan is structurally identical to the EPA's action
on a state implementation plan (SIP). Under section 110(k)(3), EPA
must approve a SIP that meets all requirements of the Act. See Train
v. NRDC, 421 U.S. 60 (1975) (discussing the 1970 version of the
Act); Virginia v. EPA, 108 F.3d 1397, 1408-10 (D.C. Cir. 1995)
(discussing the 1970, 1977, and 1990 versions).
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The EPA's determination of whether each plan is ``satisfactory'',
including the application of RULOF, must be generally consistent from
one plan to another. If the states do not have clear parameters for how
to consider RULOF when applying a standard of performance to a
designated facility, then they face the risk of submitting plans that
the EPA may not be able to consistently approve as satisfactory. For
example, under the current broadly structured provision, two states
could consider RULOF for two identically situated designated facilities
and apply completely different standards of performance on the basis of
the same factors. In this example, it may be difficult for the EPA to
substantiate finding both plans satisfactory in a consistent manner,
and the states and sources risk uncertainty as to whether each of the
differing standards of performance would be approvable. Accordingly,
providing a clear analytical framework for EG OOOOc for the invocation
of RULOF will provide regulatory certainty for states and the regulated
community as they seek to craft satisfactory plans that the EPA can
ultimately approve.
For these reasons, the EPA is proposing the RULOF provision under
subpart OOOOc, consistent with the statutory construct and goals of CAA
section 111(d), in order to provide states and sources with clarity
regarding the requirements that apply to the development and
approvability of state plans that consider RULOF when applying a
standard of performance to a particular designated facility. Below, we
describe the guiding principles for the EPA's proposed revisions.
CAA section 111(a)(1) requires that the EPA determine the BSER is
``adequately demonstrated'' for the regulated source category. In
determining whether a given system of emission reduction qualifies as
BSER, CAA section 111(a)(1) requires that the EPA take into account
``the cost of achieving such reduction and any non-air quality health
and environmental impact and energy requirements.'' The EPA's proposed
RULOF provision does so by tethering the states' RULOF demonstration to
the statutory factors the EPA considered in the BSER determination.
This is appropriate under the statute because the EPA will have
demonstrated that the BSER identified in EG OOOOc is ``adequately
demonstrated'' as achievable for sources broadly within the Crude Oil
and Natural Gas source category. Therefore, RULOF is appropriately
applied to permit states to address instances where the application of
the BSER factors to a particular designated facility is fundamentally
different than the determinations made to support the BSER and
presumptive level of stringency in the EG. For example, the D.C.
Circuit has stated that to be ``adequately demonstrated,'' the system
must be ``reasonably reliable, reasonably efficient, and . . .
reasonably expected to serve the interests of pollution control without
becoming exorbitantly costly in an economic or environmental way.''
Essex Chem. Corp. v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973).
The court has further stated that the EPA may not adopt a standard in
evaluating cost that would be ``exorbitant,'' \261\ ``greater than the
industry could bear and survive,'' \262\ ``excessive,'' \263\ or
``unreasonable.'' \264\ These formulations use reasonableness
[[Page 74819]]
in light of the statutory factors as the standard in evaluating cost,
so that a control technology may be considered the ``best system of
emission reduction . . . adequately demonstrated'' if its costs are
reasonable (i.e., not exorbitant, excessive, or greater than the
industry can bear), but cannot be considered the BSER if its costs are
unreasonable. Similarly, in making the BSER determination, the EPA must
evaluate whether a system of emission reduction is ``adequately
demonstrated'' for the source category based on the physical
possibility and technical feasibility of control. Under this construct,
it naturally follows that most designated facilities within the source
category should be able to implement the BSER at a reasonable cost to
achieve the presumptive level of stringency, and RULOF will be
applicable only for a subset of sources for which implementing the BSER
would impose unreasonable costs or not be feasible due to unusual
circumstances that are not applicable to the broader source category
that the EPA considered when determining the BSER.\265\
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\261\ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C.
Cir. 1999).
\262\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir.
1975).
\263\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
\264\ Ibid.
\265\ This construct is also supported by CAA section 111(d) use
of the term ``establishing'' in directing states to create and set
standards of performance. As previously described, ``standard of
performance'' is defined under CAA section 111(a)(1) as reflecting
the degree of emission limitation achievable through application of
the BSER, which sets the initial parameters for development of the
standards of performance by states. The statute does not provide
that states may account for RULOF in ``establishing'' standards of
performance in the first instance, but permits states to do so in
``applying'' such standards to a particular source.
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The RULOF provision we are proposing in this rule is consistent
with how the EPA has approached RULOF in the implementing regulations
previously. Subparts B and Ba both currently contain the same three
circumstances for when states may account for RULOF, and reasonableness
in light of the statutory criteria is an element of all three
circumstances. Under those subparts as currently written, states may
consider RULOF if they can demonstrate unreasonable cost of control,
physical impossibility of control, or other factors that make
application of a less stringent standard ``significantly more
reasonable.'' 40 CFR 60.24(f), 40 CFR 60.24a(e). The EPA's proposal for
EG OOOOc retains the first circumstance in whole and revises the second
one to add ``technical infeasibility'' of installing a control as a
situation where application of consideration of RULOF may be
appropriate. The proposal for EG OOOOc further clarifies the third
catch-all circumstance, which the first two circumstances also fall
under, by specifying that states may consider RULOF to apply a less
stringent standard if factors specific to a designated facility are
fundamentally different from the factors considered in the
determination of the BSER in EG OOOOc. The proposed third criteria
provides parameters for states and the EPA in developing and assessing
state plans, as this criterion was previously vague in the implementing
regulations and potentially open-ended as to the circumstances under
which states could consider RULOF.
The ``fundamentally different'' standard, which undergirds all
three circumstances, is also consistent with other variance provisions
that courts have upheld for environmental statutes. For example, in
Weyerhaeuser Co. v. Costle, 590 F.2d 1011 (D.C. Cir. 1978), the D.C.
Circuit considered a regulatory provision promulgated under the Clean
Water Act (CWA) that permitted owners to seek a variance from the EPA's
national effluent limitation guidelines under CWA sections 301(b)(1)(A)
and 304(b)(1). The EPA's regulation permitted a variance where an
individual operator demonstrates a ``fundamental difference'' between a
CWA section 304(b)(1)(B) factor at its facility and the EPA's
regulatory findings about the factor ``on a national basis.'' Id. at
1039. The court upheld this standard as ensuring a meaningful
opportunity for an operator to seek dispensation from a limitation that
would demand more of the individual facility than of the industry
generally, but also noted that such a provision is not a license for
avoidance of the Act's strict pollution control requirements. Id. at
1035.
For the reasons described in this section, the EPA is proposing
RULOF provisions for purposes of EG OOOOc by: (1) Including the
threshold requirements for consideration of RULOF; (2) adding
requirements for calculating a less stringent standard accounting for
RULOF; (3) adding requirements for consideration of communities most
affected by and vulnerable to the health and environmental impacts from
the designated facilities being addressed; and (4) adding requirements
for the types of information and evidence the states must provide to
support the invocation of RULOF in a state plan. The EPA solicits
comment on the proposed provisions described in the following
subsections, including the use of the BSER as a central tenet governing
the invocation of the RULOF provision.
The EPA also solicits comment about whether, instead of
establishing firm requirements for the application of RULOF, the EPA
should instead consider establishing a framework, consistent with the
proposed requirements in the following discussion, pursuant to which
state plans would be considered presumptively approvable. In this
scenario, states would have certainty regarding what type of
demonstration the EPA would find satisfactory as they develop their
plans, but states could also submit an alternative RULOF demonstration
for the EPA's consideration. In the latter case, states would bear the
burden of proving to the EPA that they have proposed a satisfactory
alterative analysis and standard, considering all factors relevant to
addressing emissions from the source or sources at issue. The EPA also
solicits comment on what different approaches might be appropriate for
a state in applying RULOF to a particular source and that the EPA
should consider in determining whether to finalize the provisions
discussed below, either as requirements or as presumptions.
c. Threshold Requirements for Considering Remaining Useful Life and
Other Factors
Under the existing RULOF provision in subpart Ba, 40 CFR 60.24a(e),
a state may only account for RULOF in applying a standard of
performance provided that it makes a demonstration based on one of
three criteria. These criteria are: (1) Unreasonable cost of control
resulting from plant age, location, or basic process design; (2)
physical impossibility of installing necessary control equipment; or
(3) other factors specific to the facility (or class of facilities)
that make application of a less stringent standard or final compliance
time significantly more reasonable. But the existing version of this
provision in subpart Ba provides no further guidance on what
constitutes reasonableness or unreasonableness for these
demonstrations. The EPA proposes this provision and clarifies it for
purposes of EG OOOOc to require that in order to account for RULOF in
applying a less stringent standard of performance to a designated
facility, a state must demonstrate that the designated facility cannot
reasonably apply the BSER to achieve the degree of emission limitation
determined by the EPA because it entails: (1) An unreasonable cost of
control resulting from plant age, location, or basic process design;
(2) physical impossibility or technical infeasibility of installing
necessary control equipment; or (3) other factors specific
[[Page 74820]]
to the facility (or class of facilities) that are fundamentally
different from the factors considered in the establishment of the
emission guidelines.\266\ The EPA proposes in EG OOOOc that the first
criterion remains the same as under the existing RULOF provision in 40
CFR 60.24a(e). For the second criterion, the EPA is proposing in EG
OOOOc to add a reference to technical infeasibility, as a similar yet
distinct factor from that of physical impossibility of control.
Finally, the EPA is proposing in EG OOOOc to revise the third criterion
to capture any circumstance at a specific designated facility that is
fundamentally different from the factors the EPA considered in
determining the BSER.
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\266\ States may also account for RULOF when applying standards
of performance to a class of designated facilities. For purposes of
administrative efficiency, a state may be able to calculate a
uniform standard of performance that accounts for RULOF using a
single set of demonstrations to meet the proposed requirements
described in this section if the group of sources has similar
characteristics.
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The EPA proposes in EG OOOOc to require that, in order to
demonstrate that a designated facility cannot reasonably meet the
presumptive level of stringency based on one of these three criteria,
the state must show that implementing the BSER is not reasonable for
the designated facility due to fundamental differences between the
factors the EPA considered in determining the BSER, such as cost and
technical feasibility of control, and circumstances at the designated
facility. Per the requirements of CAA section 111(a)(1), the EPA
determines the BSER by first identifying control methods that it
considers to be adequately demonstrated, and then determining which are
the best systems by evaluating (1) the cost of achieving such
reduction, (2) any non-air quality health and environmental impacts,
(3) energy requirements, (4) the amount of reductions, and (5)
advancement of technology. Accordingly, the state plan must show that
there are fundamental differences between a designated facility and the
EPA's BSER determination based on the EPA's consideration of any of
these factors.
For instance, if the state could demonstrate that the cost-per-ton
was significantly higher at a specific designated facility than
estimated by the EPA in the BSER analysis, and/or that a specific
designated facility does not have adequate space to reasonably
accommodate the installation, and/or that it is technically infeasible
to comply with the presumptive standard based on source-specific
technical barriers that are fundamentally different than those
considered in the EPA's BSER determination, that designated facility
may be evaluated for a less stringent standard because of the
consideration of RULOF.
However, states may not invoke RULOF based on minor, non-
fundamental differences. There could be instances where a designated
facility may not be able to comply with the level of stringency
required by EG OOOOc based on the precise metrics of the BSER
determination but is able to do so within a reasonable margin. For
example, the costs and cost effectiveness could be slightly higher than
estimated by the EPA for the BSER for the presumptive standard, but
that would not invoke RULOF. Similarly, there might also be instances
where the EPA determines the BSER for a designated facility as a
particular technology, but a particular designated facility does not
currently have the capability to implement that technology, or it would
be cost prohibitive to gain that capability. However, if that
designated facility has the ability instead to reasonably install a
different, non-BSER technology to achieve the presumptive level of
stringency, the designated facility would not be eligible for a less
stringent standard that accounts for RULOF.
Following are a few illustrative examples. The EPA is proposing to
determine the BSER for wet seal centrifugal compressors designated
facility an emission standard of 3 scfm volumetric flow rate. As
described in section IV.G of this preamble, the cost effectiveness of
complying with the 3 scfm emission standard is estimated to be
approximately $711 per ton of methane reduced for compressors in the
transmission and storage segment. Therefore, under the proposed RULOF
requirements for this EG, the state could evaluate the cost
effectiveness of implementing the BSER for a particular wet seal
centrifugal compressor in order to achieve the presumptive standard. As
noted above, the first criterion a state may use to justify RULOF in
applying a standard of performance is unreasonable cost of control
resulting from plant age, location, or basic process design. If a state
determined that for a centrifugal compressor affected facility in their
state, the cost effectiveness was $71,000 per ton of methane removed,
that would represent a valid demonstration of unreasonable cost of
control. However, a slightly higher cost effectiveness (e.g., $1,000
per ton, which is well within the range the EPA deems to be cost-
effective) may be representative of a minor difference that would not
represent a valid demonstration for unreasonable cost. This example is
only for illustrative purposes and should not be interpreted to
represent the difference that must exist to demonstrate unreasonable
cost of control (i.e., the cost effectiveness does not need to be two
orders of magnitude higher than the presumptive standard to be
considered unreasonable).
By way of further example, for the pneumatic controller designated
facility, the EPA determined that use of non-venting controllers is
BSER. At sites without electrical power, compliance solutions include
solar-powered controllers, a generator which powers electrical
controllers or an instrument air system, capturing the emissions and
routing them to a process, or installing self-contained controllers.
There could be physical constraints that impact the installation of
solar panels or a generator, and there may be technical infeasibility
issues related to ability to route to a process or to use self-
contained controllers. If a state determined that it would be
physically impossible and technically infeasible to install non-venting
controllers at a designated facility given the size and physical
constraints needed to install it, the lack of a process that can accept
the gas, or operational conditions that would not support the use of a
self-contained controller, this would represent a valid demonstration
of physical impossibility or technical infeasibility of installing
necessary control equipment.
As a third example of how RULOF may not be used is in the case of
the super-emitter response program. Upon notification of an emission
event over 100 kg/hr, the program requires an owner/operator to do a
root cause analysis to determine the source of the emissions event and
either take corrective action or explain why no corrective action was
warranted. Because it is not known what the source of the emissions
event is prior to the root cause analysis, RULOF cannot be applied in
any state plan to exempt an owner or operator from conducting this
analysis. Moreover, the EPA anticipates it would generally be
inappropriate for a designated facility with a less stringent standard
due to RULOF to be permitted to have unintentional and continuing
emissions events as high as 100 kg/hr such that the owner/operator
would not need to take corrective action under the super-emitter
response program.
The EPA solicits comment on the proposal to require states to
demonstrate, as a threshold matter when determining whether a state may
account for RULOF in order to set a less
[[Page 74821]]
stringent standard, that the designated facility cannot reasonably
apply the BSER to achieve the presumptive level of stringency
determined by the EPA. The EPA further solicits comment on whether
other considerations should inform the circumstances under which the
EPA should permit RULOF to be used to set a less stringent standard for
a particular designated facility. The EPA also discusses and solicits
comments later in section V.B.3.g. on the types of information used to
support a RULOF demonstration.
d. Calculation of a Standard Which Accounts for Remaining Useful Life
and Other Factors
If a state has made the proposed demonstration that accounting for
RULOF is appropriate for a particular designated facility, the state
may then apply a less stringent standard. The current RULOF provision
in subpart Ba is silent as to how a less stringent standard should be
calculated, raising the potential for inconsistent application of this
provision across states and the potential for the imposition of a
standard less stringent than what would be reasonably achievable by a
designated facility. In order to fill this gap and ensure the integrity
of EG OOOOc, the EPA is proposing several requirements that would apply
for the calculation of a standard of performance that accounts for
RULOF. The proposed requirements described in this section would
provide a framework for the state's analysis in evaluating and
identifying a less stringent standard, and in doing so would prevent
the application of a standard that is less stringent than what is
otherwise reasonably achievable by a particular designated facility.
The EPA is first proposing in EG OOOOc to require that the state
determine and include, as part of the plan submission, a source-
specific BSER for the designated facility. As described previously, the
statute requires the EPA to determine the BSER by considering control
methods that it considers to be adequately demonstrated, and then
determining which are the best systems by evaluating: (1) The cost of
achieving such reduction, (2) any non-air quality health and
environmental impacts, (3) energy requirements, (4) the amount of
reductions, and (5) advancement of technology. To be consistent with
this statutory construct, the EPA proposes that in determining a less
stringent BSER for a designated facility, a state must also consider
all these factors in applying RULOF for that source. Specifically, the
plan submission must identify all control technologies available for
the source and evaluate the BSER factors for each technology, using the
same metrics and evaluating them in the same manner as the EPA did in
developing the EG using the five criteria noted above.\267\
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\267\ To the extent that a state seeks to apply RULOF to a class
of facilities that the state can demonstrate are similarly situated
in all meaningful ways, the EPA proposes to permit the state to
conduct an aggregate analysis of these factors for the entire class.
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We are further proposing that the standard must be in the same form
(e.g., numerical rate-based emission standard) as required by the EG
OOOOc presumptive standard. The EPA notes there may be cases where a
state determines that a designated facility cannot reasonably implement
the BSER but can instead reasonably implement another control measure
to achieve the same level of stringency required by an EG. In such
cases, the standard of performance that reflects the designated
facility-specific BSER would be the same level of stringency as the
degree of emission limitation achievable through application of the
EPA's BSER.
The EPA solicits comment on these proposed requirements for the
calculation and form of the less stringent standard that accounts for
remaining useful life and other factors. The EPA believes that the five
identified BSER factors generally address all relevant information that
states would reasonably consider in evaluating the emission reductions
reasonably achievable for a designated facility. Moreover, the EPA
considers that that these factors provide states with the discretion to
weigh these factors in determining the BSER and establishing a
reasonable standard of performance for the source. However, the EPA
solicits comments on whether there are additional factors, not already
accounted for in the BSER analysis, that the EPA should permit states
to consider in determining the less stringent standard for an
individual source. The EPA also solicits comments on whether we should
consider these factors to be part of a presumptively approvable
framework for applying a less stringent standard of performance, rather
than requirements, and, if so, what different approaches states might
use to evaluate and identify less stringent standards that the EPA
should consider to be satisfactory in evaluating state plans that apply
RULOF.
The EPA also notes that CAA section 111(d) requires that state
plans include measures that provide for the implementation and
enforcement of a standard of performance. This requirement therefore
applies to any standard of performance established by a state that
accounts for RULOF. Such measures include monitoring, reporting, and
recordkeeping requirements, as required by 40 CFR 60.25a, as well as
any additional measures specified under EG OOOOc. In particular, any
standard of performance that accounts for RULOF is also subject to the
requirement under subpart Ba that the state plan submission include a
demonstration that each standard is quantifiable, non-duplicative,
permanent, verifiable, and enforceable. 40 CFR 60.27a(g)(3)(vi).
e. Contingency Requirements
The EPA recognizes that a source's operations may change over time
in ways that cannot always be anticipated or foreseen by the EPA,
state, or designated facility. This is particularly true where a state
seeks to rely on a designated facility's operational conditions, such
as the source's remaining useful life or restricted capacity, as a
basis for setting a less stringent standard. If the designated facility
subsequently changes its operating conditions after the state applies a
less stringent standard of performance, there is potential for the
standard to not match what is reasonably achievable by a designated
facility, resulting in forgone emission reductions and undermining the
level of stringency set by EG OOOOc. For example, a state may seek to
invoke RULOF for a designated facility located at a well site (e.g.,
storage vessel) during a time when oil prices are low. The market
demand may prompt the owner or operator to shut the well site which may
not have been anticipated by the BSER. The well site may be shut in for
the duration of the compliance period required by an EG. Under this
scenario, the state may be able to demonstrate that it is not
reasonably cost effective for the designated facility to implement the
BSER in order to achieve the presumptive level of stringency, and the
state could set a less stringent standard of performance for this
storage vessel designated facility. However, because market conditions
are not a physical constraint on the designated facilities operations,
it is possible that oil prices can increase in the future therefore
causing the production demand to increase without any other legal
constraint.
The implementing regulations do not currently address this
potential scenario. To address this issue, the EPA is proposing for
purposes of EG OOOOc to add a contingency requirement to the RULOF
provision that would require a state to include in its state plan a
condition making a source's operating
[[Page 74822]]
condition, such as remaining useful life or restricted capacity,
enforceable whenever the state seeks to rely on that operating
condition as the basis for a less stringent standard. This requirement
would not extend to instances where a state applies a less stringent
standard on the basis of an unalterable condition that is not within
the designated source's control, such as technical infeasibility, space
limitations, water access, or subsurface reservoir and geological
conditions. Rather, this requirement addresses operating conditions
such as operation times, operational frequency, process temperature
and/or pressure, flow rate, fuel parameters, and other conditions that
are subject to the discretion and control of the designated facility.
As previously discussed, the state plan submission must also
include measures for the implementation and enforcement of a standard
that accounts for RULOF. For standards that are based on operating
conditions that a facility has discretion over and can control, the
operating condition and any other measure that provides for the
implementation and enforcement of the less stringent standard must be
included in the plan submission and as a component of the standard of
performance. For example, if a state applies a less stringent standard
for a storage vessel designated facility on the basis that the storage
vessel has less throughput than maximum capacity of the storage vessel
(e.g., due to the current well production, or a state permit limit),
the plan submission must include an enforceable requirement for the
source to operate at or below that capacity factor, and include
monitoring, reporting, and recordkeeping requirements that will allow
the state, the EPA, and the public to ensure that the source is in fact
operating at that lower capacity.
The EPA notes there may be circumstances under which a designated
facility's operating conditions change permanently so that there may be
a potential violation of the contingency requirements approved as
federally enforceable components of the state plan. For example, a
storage vessel designated facility that was previously running at lower
throughput now plans to run at a higher throughput full time, which
conflicts with the federally enforceable state plan requirement that
the facility operate at the lower throughput. To address this concern,
a state may submit a plan revision to reflect the change in operating
conditions. Such a plan revision must include a new standard of
performance that accounts for the change in operating conditions. The
plan revision would need to include a standard of performance that
reflects the level of stringency required by EG OOOOc and meet all
applicable requirements, or if a less stringent standard is still
warranted for other reasons, the plan revision would need to meet all
of the applicable requirements for considering RULOF.
The EPA requests comment on the proposed contingency requirements
to address the concern that a designated facility's operations may
change over time in ways that do not match the original rationale for a
less stringent standard.
f. Requirements Specific to Remaining Useful Life
Remaining useful life is the one ``factor'' that CAA section 111(d)
explicitly requires that the EPA permit states to consider in applying
a standard of performance. The current RULOF provision generally allows
for a state to account for remaining useful life to set a less
stringent standard. However, the provision does not provide guidance or
parameters on when and how a state may do so. Consistent with the
principles described previously in this section, the EPA is proposing
certain requirements for when a state seeks to apply a less stringent
standard on grounds that a designated facility will retire in the near
future.
The EPA is proposing to require that in order to account for
remaining useful life in setting a less stringent standard for a
particular designated facility, the state plan must identify the
source's retirement date and substantiate why this retirement date
qualifies for the imposition of a less stringent standard. The state
plan must include a demonstration of why the source's remaining useful
life based on its retirement date reasonably warrants a less stringent
standard and does not undermine the control objectives of the EG and
CAA section 111(d) itself.
This demonstration may take into account considerations in relation
to the remaining useful life such as the time needed to purchase and
install equipment required to comply, the time needed to develop a
compliance plan and secure the services of specialized contractors to
perform services required for compliance, the expected window of time
needed to obtain approvals of outside agencies, the time needed to
conduct any required community outreach or public hearings, as well as
other potential factors.
However, the EPA is proposing that one consideration must be
addressed in every case to substantiate that the remaining useful life
qualifies the imposition of a less stringent standard. That is, the
state must demonstrate that the cost of control is unreasonable in
relation to the retirement date.
When the EPA determines a BSER, it considers cost and, in many
instances, the EPA specifically considers annualized costs associated
with payment of the total capital investment of the technology
associated with the BSER. In the estimation of this annualized cost,
the EPA assumes an interest rate and a capital recovery period,
sometimes referred to as the payback period. For example, in the
estimation of the annual costs for the installation of an instrument
air system to power pneumatic controllers with compressed air a medium-
sized transmission and storage site, the EPA estimates that the total
capital investment (equipment and installation) of the system would be
$76,481. For the BSER analysis, the EPA assumed an interest rate of
seven percent and a capital recovery period of 15 years. This means
that the annual cost of recovering the initial capital investment
including interest, was $8,397 per year for 15 years. The total annual
cost includes this capital recovery cost plus the additional operation
and maintenance cost of the equipment (additional beyond what would be
required for a natural gas-driven controller system). For this example,
the additional operation and maintenance cost was estimated to be
$2,816 per year, resulting in a total annual cost of $11,213 and a cost
effectiveness of $1,250 per ton of methane removed, which is a value
within the range considered reasonable by the EPA.
Therefore, for this example, the cost effectiveness is reasonable
considering a capital recovery period, or payback period, of 15 years.
If the remaining useful life was less than 15 years, the result could
be a cost effectiveness that is outside of the range considered
reasonable by the EPA. For example, consider a remaining useful life of
six years. The resulting capital recovery cost would be $26,742 per
year and total annual cost would be $29,196. This would yield a cost
effectiveness of $1,834 per ton of methane removed, which would still
be in the range considered reasonable by the EPA. Therefore, the state
would not be able to claim that the costs were unreasonable for a
remaining useful life of six years. However, if the remaining useful
life were only two years, the capital recovery cost would be $70,502
per year and the total annual cost would be $72,956. The cost
effectiveness of this would be almost $4,600 per ton of methane
removed, which is outside of
[[Page 74823]]
the range considered reasonable by the EPA. In this situation, this
could potentially be used as part of a demonstration that may qualify
the remaining useful life for the imposition of a less stringent
standard.
Note that this specific example is only for illustrative purposes.
Specifically, for pneumatic controller designated facilities, there are
compliance options (e.g., electric controllers) that are considerably
less expensive than the installation of an instrument air system. A
state would have to demonstrate unreasonable cost of control for each
of the identified compliance options, not just one.
The EPA proposes that the only cost factor that should be
considered in a remaining useful life determination of cost
unreasonableness is whether there is a significant capital investment
required to design, purchase, and install equipment. A BSER based on
compliance measures that do not require such upfront capital
expenditures would have been demonstrated to have reasonable costs in
the EPA's analysis for the presumptive standards. This would largely be
the case if the affected facility operates for two years or 50 years.
Therefore, the EPA does not believe that all types of designated
facilities should be eligible for a determination of unreasonable costs
associated with remaining useful life. Accordingly, the proposed rule
would only allow that cost unreasonableness be considered in a state's
demonstration that a source's remaining useful life based on its
retirement date reasonably warrants a less stringent standard for the
following types of designated facilities: oil wells with associated
gas, storage vessels, pneumatic controllers, and pneumatic pumps. A
cost unreasonableness determination would not be allowed for any other
designated facility types. Note that this would not necessarily
prohibit a state from making a demonstration for these other types of
designated facilities, as some of the other factors mentioned above
(e.g., time needed to develop a compliance plan and secure the services
of specialized contractors to perform services required for compliance)
could be relevant for such facilities. However, a state could not rely
on unreasonable cost in determining that remaining useful life
justifies a less stringent standard.
The EPA recognizes that, even with the criteria outlined above, the
result could be that different states could make demonstrations that
result in different remaining useful life periods for the same types of
designated facilities. In order to avoid this potential inequity, the
EPA is requesting comment on whether EG OOOOc should include a single
``outermost retirement date'' that would define the maximum length of
time that would qualify for a designated facility to operate at a less
stringent standard based on remaining useful life.
As previously discussed, the EPA is proposing to require that when
an operational condition is used as the basis for applying a less
stringent standard, the state plan must include that condition as a
federally enforceable requirement. Accordingly, if a state applies a
less stringent standard by accounting for remaining useful life, the
EPA is proposing to require that the state plan must include the
retirement date for the designated facility as an enforceable
commitment and include measures that provide for the implementation and
enforcement of such commitment. For example, the state could adopt a
regulation or enter into an agreed order requiring the designated
facility to shut down by a certain date, and that regulation or agreed
order should then be incorporated into the state plan. The state could
also choose to incorporate the shutdown date into a permit, such as a
preconstruction permit, and incorporate that permit into the state
plan.
The EPA is further proposing to require that the state plan impose
a standard that applies to a designated facility until its retirement.
This standard must reflect a reasonably achievable source specific BSER
and be calculated as described in section IV of this preamble and
section XII of the November 2021 proposal and supported by the
demonstration described in 2021 TSD \268\ and the Supplemental TSD
\269\ for this action. The EPA recognizes that, in some instances, a
designated facility may intend to retire imminently after the
promulgation of an EG, and in such cases it may not be reasonable to
require any controls based on the source's exceptionally short
remaining useful life. In the case of an imminently retiring source,
the EPA is proposing that the state apply a standard no less stringent
than one that reflects the designated facility's business as usual.
This requirement equitably accommodates practical considerations
without impermissibly exacerbating the impacts of the pollutant
regulated under CAA section 111(d). The EPA generally expects that an
``imminent'' retirement is one that is about to happen in the near
term, e.g., within six months.
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\268\ Document ID No. EPA-HQ-OAR-2021-0317-0166.
\269\ Located at Docket ID No. EPA-HQ-OAR-2021-0317.
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The EPA solicits comment on the proposed requirements specific to
the consideration of remaining useful life as described in this
section.
g. The EPA's Standard of Review of State Plans Invoking RULOF
Under CAA section 111(d)(2), the EPA has the obligation to
determine whether a state plan submission is ``satisfactory.'' This
obligation extends to all aspects of a state plan, including the
application of a less stringent standard of performance that accounts
for RULOF. The proposed RULOF provision in EG OOOOc are intended to
provide parameters not only for the development of CAA section 111(d)
state plans, but for the EPA to evaluate the approvability of such
plans. The EPA is proposing the following requirements to further
bolster the RULOF provision and to facilitate the EPA's review of a
state plan to determine whether the plan implementing the RULOF
provision is ``satisfactory.'' As an initial matter, the EPA proposes
to explicitly require that the state must carry the burden of making
the demonstrations required under the RULOF provision. States carry the
primary responsibility to develop plans that meet the requirements of
CAA section 111(d) and therefore have the obligation to justify any
accounting for RULOF that they invoke in support of standards less
stringent than those provided by EG OOOOc. While the EPA has discretion
to supplement a state's demonstration, the EPA may also find that a
state plan's failure to include a sufficient RULOF demonstration is a
basis for concluding the plan is not ``satisfactory'' and therefore
disapprove the plan.
The EPA is further proposing that for the required demonstrations,
the state must use information that is applicable to and appropriate
for the specific designated facility, and the state must show how
information is applicable and appropriate. As RULOF is a source-
specific determination, it is appropriate to require that the
information used to justify a less stringent standard for a particular
designated facility be applicable to and appropriate for that source.
The EPA anticipates that in most circumstances, site-specific
information will be the most applicable and appropriate to use for
these demonstrations and proposes to require site-specific information
where available. In some instances, site-specific information may not
be available, and a state may instead be able to use general
information about the Crude Oil and Natural Gas source
[[Page 74824]]
category to evaluate a particular designated facility. In such cases,
the state plan submission must provide both the general information and
a clear assessment of how the information is applicable to and
appropriate for the designated facility. The use of general information
must also be consistent with and supportive of the overall assessment
and conclusions regarding consideration of RULOF for the specific
designated facility.
Finally, the EPA proposes to require that the information used for
a state's demonstrations under the new RULOF provisions must come from
reliable and adequately documented sources, which presumptively include
the following: EPA sources and publications, permits, environmental
consultants, control technology vendors, and inspection reports.
Requiring the use of such sources will help ensure that an accounting
of RULOF is premised on legitimate, verifiable, and transparent
information. The EPA solicits comment on the proposed list of
information sources and whether other sources should be considered as
reliable and adequately documented sources of information for purposes
of the RULOF demonstration, including but not limited to reliable and
adequately documented sources of cost information. \270\
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\270\ The EPA acknowledges there may be reliable and adequately
documented sources of information other than those described in this
section. The EPA encourages states to consult with their Regional
Offices if there are questions about whether a particular source of
information would meet the applicable requirements.
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These requirements will aid both the EPA in evaluating whether
RULOF has been appropriately accounted for, and the public in
commenting on the EPA's proposed action on a state plan that includes a
less stringent standard on the basis of RULOF. The EPA solicits comment
on the proposed requirements described in this section regarding the
EPA's standard of review for state plans that invoke consideration of
RULOF.
h. Consideration of Impacted Communities
CAA section 111(d) does not specify what are the ``other factors''
that the EPA's regulations should permit a state to consider in
applying a standard of performance. The EPA interprets this as
providing discretion for the EPA to identify the appropriate factors
and conditions under which the circumstance may be reasonably invoked
in establishing a standard less stringent than the EG. Additionally,
CAA section 111(d)(2)'s requirement that the EPA determine whether a
state plan is ``satisfactory'' applies to such plan's consideration of
RULOF in applying a standard of performance to a particular facility.
Accordingly, the EPA must determine whether a plan's consideration of
RULOF is consistent with section 111(d)'s overall health and welfare
objectives. While the consideration of RULOF can be warranted to apply
a less stringent standard of performance to a particular facility, such
standards have the potential to result in disparate health and
environmental impacts to communities most affected by and vulnerable to
impacts from the designated facilities being addressed by the state
plan. Those communities could be put in the position of bearing the
brunt of the greater health and environmental impacts resulting from
that source implementing less stringent emission controls than would
otherwise have been required pursuant to the EG. The EPA finds that a
lack of consideration to such potential outcomes would be antithetical
to the public health and welfare goals of CAA section 111(d) and the
CAA generally.
In order to address the potential exacerbation of health and
environmental impacts to vulnerable communities as a result of applying
a less stringent standard, the EPA is proposing in EG OOOOc to require
states to consider such impacts when applying the RULOF provision to
establish those standards. The EPA is proposing to require that, to the
extent a designated facility would qualify for a less stringent
standard through consideration of RULOF, the state, in calculating such
standard, must consider the potential health and environmental impacts
on communities most affected by and vulnerable to the impacts from the
designated facility considered in a state plan for RULOF provisions.
These communities will be identified by the state as pertinent
stakeholders under the proposed meaningful engagement requirements
described in section V.B.6 of this preamble.\271\
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\271\ Pursuant to the proposed meaningful engagement
requirements that states must complete prior to the submittal of
their state plans, states must identify pertinent stakeholders and
meaningfully engage with such pertinent stakeholders, including
communities most affected by and vulnerable to the impacts of the
plan.
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The EPA proposes to require that state plan submissions seeking to
invoke RULOF for a source must identify where and how a less stringent
standard impacts these communities. In evaluating a RULOF option for a
facility, states should describe the health and environmental impacts
anticipated from the application of RULOF for such communities, along
with any feedback the state received during meaningful engagement
regarding its draft state plan submission, including on any standards
of performance that consider RULOF. Additionally, to the extent there
is a range of options for reasonably controlling a source based on
RULOF, the EPA is proposing that in determining the appropriate
standard of performance, states should consider the health and
environmental benefits to the communities most affected by and
vulnerable to the impacts from the designated facility considered in a
state plan for RULOF provisions, and also provide in the state plan
submission a summary of the results that depicts the impacts to those
communities. This requirement to consider the health and environmental
impacts in any standard of performance taking into account RULOF is
consistent with the definition of ``standard of performance'' in CAA
section 111(a)(1). This definition requires the EPA to take into
account health and environmental impacts in determining the BSER. As
described in this section, if a designated facility qualifies for a
less stringent standard based on RULOF, the EPA is proposing the state
plan must identify a source-specific BSER based on the same factors and
metrics the EPA considered in determining the BSER in the EG.
Therefore, state plans must consider health and environmental impacts
in determining a source-specific BSER informing a RULOF standard, just
as the EPA is statutorily required to take into account these factors
in making its BSER determination. See section IV.D.1.b.III for an
example of the environmental impacts assessed for the EPA's proposed
BSER determination for pneumatic controllers.
As an example, the state plan submission could include a
comparative analysis assessing potential controls on a designated
facility and the corresponding potential benefits to the identified
communities in controlling the designated facility. If the comparative
analysis shows that a designated facility could be controlled at a
certain cost threshold higher than required under the EPA's proposed
revisions to the RULOF provision, and such control benefits the
communities that would otherwise be adversely impacted by a less
stringent standard, the state in accounting for RULOF could choose to
use that cost threshold to apply a standard of performance.\272\
[[Page 74825]]
Given that states have the discretion rather than mandate to consider
RULOF in applying a standard of performance under CAA section 111(d),
it is reasonable for states to consider the potential impacts to
communities most affected by and vulnerable to the impacts from a
particular designated facility in calculating the level of stringency
for such standard.
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\272\ As previously described, CAA section 111(d) gives states
the discretion to consider RULOF for a particular source and are not
required to do so. States thus have the authority to choose to
impose a more stringent standard, including the presumptive
standard, than would be permissible under RULOF for other reasons,
e.g. based on consideration of communities other than identified
impacted communities.
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Additionally, under CAA section 111(d)(2)(B), the EPA has the
authority to prescribe a Federal plan promulgating a standard of
performance for designated facilities located in a state that fails to
submit a satisfactory plan. Consistent with the statute's mandate for
the EPA's regulations under CAA section 111(d) to permit states to
account for RULOF, this provision further directs that the EPA
``shall'' take into account RULOF in promulgating standards of
performance for the source category under the Federal plan. Therefore,
because the statute uses the same ``other factors'' phrasing in both
CAA sections 111(d)(1) governing state plans and 111(d)(2) governing
Federal plans, the EPA proposes in EG OOOOc to require that impacts to
communities most affected by and vulnerable to the impacts from
designated facilities be considered in both the state and Federal plan
contexts when accounting for RULOF.
The EPA solicits comment on the proposed requirements described in
this section for consideration of vulnerable communities in the context
of RULOF.
i. Authority To Apply More Stringent Standards as Part of the State
Plan
In the November 2021 proposal, the EPA proposed that states are
authorized to include in their state plans, and the EPA is authorized
to approve, requirements that are more stringent than the EG under the
authority of CAA section 116, as interpreted by the Court in Union
Electric v. EPA, 27 U.S. 246, (1976). 86 FR 63251. The EPA is now
proposing that under CAA section 111(d), consistent with the authority
conferred by CAA section 116, states may consider RULOF to include more
stringent standards of performance in their state plans.
The current RULOF provision in subpart Ba under 40 CFR 60.24a(e)
governs instances where states seek to apply a less stringent standard
of performance to a particular designated facility. In promulgating
this provision, the EPA received comments contending that if states may
consider factors that justify less stringent standards, they must also
be permitted to consider factors that would justify greater stringency
than required by an EG, such as more expeditious compliance obligations
or the retirement of a source. EPA's Responses to Public Comments on
the EPA's Proposed Revisions to Emission Guideline Implementing
Regulations at 56 (Docket ID No. EPA-HQ-OAR-2017-0355-26740) (July 8,
2019). In response to these comments, the EPA explained that it
interpreted the statutory RULOF provision as intended to authorize only
standards of performance that are less stringent than the presumptive
level of stringency required by a particular EG. Id. at 57. The EPA has
reevaluated its prior interpretation and is now proposing for purposes
of EG OOOOc to interpret that the statute authorizes the EPA to permit
states to consider other factors that justify application of a more
stringent standard to a particular source than required by an EG. See
FCC v. Fox Television Stations, Inc., 556 U.S. 502 (2009). The EPA's
rationale for its revised interpretation and proposal is as follows.
As described previously, while standards of performance must
generally reflect the presumptive level of stringency identified in the
EG, CAA section 111(d) also requires the EPA to permit states to ``take
into consideration, among other factors, the remaining useful life'' in
applying a standard of performance to a particular designated facility.
Aside from the explicit reference to remaining useful life, the statute
is silent as to what the ``other factors'' are that states may consider
in applying a standard of performance. It also silent as to whether the
``standard of performance'' to be ``appl[ied]'' to a ``particular
source'' must be a weaker or stronger standard--the only inference that
can be drawn from the statutory language is that RULOF may be used to
apply a different standard. Therefore, the EPA may reasonably interpret
this ambiguity both as to what the ``other factors'' are that states
may use to apply a standard of performance to a particular source, and
how such consideration may affect the stringency of such standard.
Accordingly, the EPA reasonably interprets this phrase as authorizing
states to consider other factors in exercising their discretion to
apply a more stringent standard to particular a source. This is a
reasonable interpretation of the statute because if Congress intended
the RULOF provision to be used only to allow states to apply less
stringent standards, it would have clearly specified that its intent or
enumerated ``other factors'' that are appropriate for relaxing the
stringency of a standard. The statute's explicit reference to remaining
useful life shows that if there were factors that Congress specifically
wanted the EPA to allow or disallow states to consider, it knew how to
expressly make its intent clear in the RULOF provision.
In addition to finding that the statute does not preclude the EPA's
reasonable interpretation of the statutory RULOF provision as described
above, the EPA has reevaluated the bases for its prior interpretation
that states may only consider RULOF to apply a less stringent standard
and determined those bases were flawed. In making its prior
interpretation, the EPA noted that the new regulatory RULOF provision
under subpart Ba at 40 CFR 60.24a(e) was substantively similar to the
variance provision under subpart B, which authorizes the use of other
factors that ``make application of a less stringent standard or final
compliance time significantly more reasonable.'' 40 CFR 60.24(f)(3).
The EPA reasoned that because the variance provision under subpart B is
similar to and predated Congress's addition of the statutory RULOF
provision to CAA section 111(d) as part of the 1977 CAA Amendments,
``Congress effectively ratified the EPA's implementing regulations'
clear construct that remaining useful life and other factors are only
relevant in the context of setting less stringent standards.'' EPA's
Responses to Public Comments on the EPA's Proposed Revisions to
Emission Guideline Implementing Regulations at 57 (Docket ID# No. EPA-
HQ-OAR-2017-0355-26740) (July 8, 2019). The EPA has closely reexamined
the variance provision under subpart B and the RULOF provision under
CAA section 111(d) and does not find that these provisions support the
proposition that Congress clearly ratified the aspect of the variance
provision in subpart B allowing states to apply only less stringent
standards under certain circumstances. There are notable differences
between the subpart B variance provision and the CAA section 111(d)
RULOF provision that indicate Congress did not intend to incorporate
and ratify all aspects of the EPA's regulatory approach when amending
CAA section 111(d) in 1977. Particularly, for pollutants found to cause
or contribute to endangerment of public health, subpart B allows states
to apply a less stringent standard under
[[Page 74826]]
certain circumstances unless the EPA provides otherwise in a specific
EG for a particular designated facility or class of facilities. 40 CFR
60.24(c), (f). Subpart B places no similar exception for states in
authorizing them to seek a variance for a standard addressing a
pollutant for which the EPA has made a welfare-based, but not public
health-based, endangerment finding under 111(b)(1)(A). 40 CFR 60.24(d).
By contrast, the statutory RULOF provision does not make a similar
distinction between public health and welfare-based pollutants, which
the EPA itself acknowledged in promulgating the regulatory RULOF
provision in subpart Ba. 84 FR 32570 (July 8, 2019). Therefore, the EPA
cannot clearly ascertain whether the statutory RULOF provision ratified
the variance provision under subpart B, given that certain key elements
of the latter are not present in the former. There is nothing in CAA
section 111(d) or the legislative history that suggests Congress
enacted the statutory RULOF provision by ratifying certain elements of
the regulatory variance provision in subpart B but not others.
Additionally, in taking its prior position that states may only
consider RULOF to apply a less stringent standard, the EPA asserted
that the legislative history of the 1977 CAA Amendments supported its
interpretation. The EPA highlighted the following statement in the
House conference report adopting the amendment to add the statutory
RULOF provision: ``The section also makes clear that standards adopted
for existing sources under section 111(d) of the Act are to be based on
available means of emission control (not necessarily technological) and
must, unless the state decides to be more stringent, take into account
the remaining useful life of the existing sources.'' H.R. Conf. Rep.
No. 94-1742, (Sep. 30, 1976), 1977 CAA Legis. Hist. at 88. Based on
this statement, the EPA found that the caveat that states have the
choice to not invoke the RULOF provision and instead ``be more
stringent'' suggests that considering RULOF is only intended to allow a
state to make a standard less stringent. The EPA now finds that its
prior reliance on this legislative history was flawed. The cited
statement only speaks to remaining useful life, which is a factor that
inherently suggests a less stringent standard, but it is completely
silent as to the ``other factors'' the statute references. Thus, there
is no indication that Congress intended to limit the ``other factors''
that states may apply in developing their plans only to permit less
stringent, and not also more stringent standards. Rather, the cited
statement explicitly acknowledges that states may choose to ``be more
stringent'', which supports the EPA's interpretation of the statute to
permit states to consider other factors to set standards more stringent
than the degree of emission limitation achievable through application
of the BSER.
Interpreting the statutory RULOF provision as authorizing states to
apply a more stringent standard of performance to a particular source
is also consistent with the purpose and structure of CAA section
111(d). CAA section 111(d) clearly contemplates cooperative federalism,
where states bear the obligation to establish standards of performance.
Nothing under CAA section 111(d) suggests that the EPA has the
authority to preclude states from determining that it is appropriate to
regulate certain sources within their jurisdiction more strictly than
otherwise required by federal requirements. To do so would be arbitrary
and capricious in light of the overarching purpose of CAA section
111(d), which is to require emission reductions from existing sources
for certain pollutants that endanger public health or welfare. It is
inconsistent with the purpose of CAA section 111(d) and the role it
confers upon states for the EPA to constrain them from further reducing
emissions that harm their citizens, and the EPA does not see a
reasonable basis for doing so.
Other factors states may wish to account for in applying a more
stringent standard than required under an EG include, but are not
limited to, early retirements, effects on local communities, and
availability of control technologies that allow a source to achieve
greater emission reductions. However, the EPA cannot anticipate each
and every factor under which a state may seek to apply a more stringent
standard. Therefore, the EPA will evaluate on a case-by-case basis the
inclusion of a more stringent standard in a state plan addressing EG
OOOOc. The EPA is also proposing to require that states seeking to
apply a more stringent standard of performance based on other factors
must adequately demonstrate that the different standard is in fact more
stringent than the presumptive level of stringency. Such standard of
performance must meet all applicable statutory and regulatory
requirements, including that it is adequately demonstrated,\273\ and
the state plan must include measures that provide for the
implementation and enforcement of the standard as with any standard of
performance under CAA section 111(d).
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\273\ The EPA is not proposing to require the state to conduct a
source-specific BSER analysis for purposes of applying a more
stringent standard, as the EPA proposes to require for application
of a less stringent standard. So long as the standard will achieve
equivalent or better emission reductions than required by EG OOOOc,
the EPA believes it is appropriate to defer to the state's
discretion to, e.g., choose to impose more costly controls on an
individual source.
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For the reasons described in this section, the EPA proposes to
permit states to consider factors which justify applying a standard of
performance that is more stringent than required under an EG OOOOc.
Therefore, for purposes of EG OOOOc, per the authority of CAA
sections 111(d) and 116, the EPA proposes to permit states to include
more stringent standards of performance in their plans and that the EPA
must approve and render such standards as federally enforceable, so
long as the minimum requirements of the EG and subpart Ba are met.\274\
The EPA solicits comment on its proposal as described in this section.
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\274\ The EPA notes that its authority is constrained to
approving measures which comport with applicable statutory
requirements. For example, CAA section 111(d) only contemplates that
state plans would include requirements for designated facilities
regulated by a particular EG; therefore, the EPA concludes that CAA
section 116 does not provide it with the authority to approve and
render federally enforceable measures on entities other than those
on designated facilities.
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4. Providing Measures That Implement and Enforce Such Standards
As described in the November 2021 proposal, the EPA proposed to
require that state plans must also include compliance schedules for the
presumptive standards including where states choose to account for
RULOF, methods employed to implement and enforce the presumptive
standards such that the EPA can review and identify measures that
assure transparent and verifiable implementation, and states must
include appropriate monitoring, reporting, and recordkeeping
requirements to ensure that state plans adequately provide for the
implementation and enforcement of the presumptive standards.\275\ The
EPA is proposing to supplement the November 2021 proposal by clarifying
that states maintain the same monitoring, reporting, and recordkeeping
requirements, or equivalent requirements as described in EG OOOOc for
presumptive standards that states adopt in their plans. The EPA further
clarifies that where a state plan adopts standards of performance that
[[Page 74827]]
differ from the presumptive standards, the plan may accordingly include
different monitoring, reporting, and recordkeeping requirements than
those in the presumptive standards, but such requirements must be
appropriate for the implementation and enforcement of the standards and
must be determined to be equivalent as described in Section V.B.2. For
components of a state plan that differ from any presumptively
approvable aspects of the final EG, the EPA will review the
approvability of such components through notice and comment rulemaking.
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\275\ 86 FR 63252 (November 15, 2021).
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5. Emissions Inventories
In the November 2021 proposal the EPA discussed that the
implementing regulations at 40 CFR 60.25a contain generally applicable
requirements for emission inventories, source surveillance, and
reports. 86 FR 63253 (November 16, 2021). 40 CFR 60.25a(a) requires
that state plans shall include an inventory of all designated
facilities, including emission data for the designated pollutants. This
provision further requires that such data shall be summarized in the
plan, and emission rates of designated pollutants from designated
facilities shall be correlated with applicable standards of
performance. However, due to the very large number of existing oil and
natural gas sources,\276\ and the frequent change of configuration and/
or ownership, the EPA recognized that it may not be practical to
require states to compile this information in the same way that is
typically expected for other industries under other EG. Therefore, the
EPA solicited comment on whether to supersede the requirements of 40
CFR 60.25a(a) for purposes of this EG.\277\
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\276\ In the U.S. the EPA has identified over 15,000 oil and gas
owners and operators, around 1 million producing onshore oil and gas
wells, about 5,000 gathering and boosting facilities, over 650
natural gas processing facilities, and about 1,400 transmission
compression facilities.
\277\ The EPA may supersede any requirement in its implementing
regulations for CAA section 111(d) if done so explicitly in the EG.
See 40 CFR 60.20a(a)(1).
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State commenters generally support superseding the implementing
regulations and agree that states should be able to document impacted
sources differently than other CAA section 111(d) plans.\278\ While
some state commenters have state inventories, others confirmed the
EPA's understanding that some states do not have comprehensive tracking
systems for a designated facility inventory and associated
emissions.\279\ Some commenters discussed that the development of such
an inventory would be resource intensive with little benefit.\280\ The
State of Colorado referenced their 2020 leak inspection reporting
program which suggests there are over 15,000 well production facilities
in the state and the State of West Virginia estimates over 54,000
natural gas and over 10,000 crude oil producing wells in the
state.\281\ Both states recognize that each well production facility
would represent a much greater number of individual designated
facilities. The State of West Virginia further described the complexity
of inventory development given not only the vast number of sources, but
also the frequent change of configurations and ownership within the
industry. These points were echoed by the State of Texas which also
provided an estimate of the number of production wells in the state,
however, they noted that unless a state-wide equipment inventory is
conducted the number of designated facilities is unclear.\282\ Multiple
state commenters support the EPA allowing states to leverage existing
inventories and emissions data, even if that data might not be fully
aligned with the designated facilities in the EG.\283\
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\278\ The EPA received several comments on this topic. A
sampling of these comments is cited in footnotes in this section.
See Document ID Nos. EPA-HQ-OAR-2021-0317-0769, EPA-HQ-OAR-2021-
0317-0775.
\279\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0832-A2, EPA-HQ-
OAR-2021-0317-0722.
\280\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0200.
\281\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0775, EPA-HQ-
OAR-2021-0317-0424.
\282\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0419.
\283\ See Document ID Nos. EPA-HQ-OAR-2021-0317-1267.
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For purposes of this EG, the EPA does not believe that the
inventory and detailed emissions data required under 40 CFR 60.25a(a)
is necessary for states to develop standards of performance, and that
standards of performance could be developed with a different type of
emissions inventory data. For example, the emissions inventory data
could be derived from the GHGRP, which collects GHG emissions and
activity data annually from applicable facilities conducting petroleum
and natural gas systems activities. Facilities use uniform methods
prescribed by the EPA to calculate emissions for applicable source
types, and the EPA conducts a multi-step verification process to ensure
reported data are accurate, complete, and consistent. Reported data are
made available to the public through several portals accessible via the
EPA's website. The emissions and activity data reported to the GHGRP
can be leveraged to develop standards of performance. While the EPA
recognizes that the GHGRP includes a reporting threshold and that GHGRP
facility definitions and emission factors might not be fully aligned
with the designated facilities in the EG, the GHGRP data represent the
same general type of inventory information as the inventory and
detailed emissions data required under 40 CFR 60.25a(a). In addition,
the EPA does not think it reasonable to burden states to derive
information from GHGRP, which the EPA already has, only to resubmit it
to the Agency. The EPA notes that emissions inventory data used to
develop standards of performance could also be derived from other
available existing inventory information available to the state.
Therefore, in order to avoid the potential burden that could be imposed
by applying 40 CFR 60.25a(a) as written to this EG, and potential
burden and duplicative information collection imposed by requiring
states to use other inventories such as GHGRP, the EPA proposes to
supersede the requirements of 40 CFR 60.25a(a) for purposes of this EG,
so that state plans are not required to include an inventory and
emissions data as described under this provision.
6. Meaningful Engagement
In the November 2021 proposal, the EPA proposed and solicited
comment on requiring states to perform early outreach and meaningful
engagement with overburdened and underserved communities during the
development process of their state plan pursuant to EG OOOOc.\284\ The
fundamental purpose of CAA section 111 is to reduce emissions from
certain stationary sources that cause, or significantly contribute to,
air pollution which may reasonably be anticipated to endanger public
health or welfare. Therefore, a key consideration in the state's
development of a state plan, in any significant plan revision,\285\ and
in the EPA's development of a Federal plan pursuant to an EG
promulgated under CAA section 111(d) is the potential impact of the
proposed plan requirements on public health and welfare. A robust and
meaningful public participation process during plan development is
critical to ensuring that the full range of these impacts are
understood and considered. The EPA received numerous comments from
states supporting the proposed
[[Page 74828]]
requirements for meaningful engagement, providing suggestions based on
their own experience and initiatives, while requesting that the EPA
provide specificity around meaningful engagement and examples of
satisfactory engagement. The EPA also hosted two discussions with
representatives of state and local air agencies to hear more about
their perspectives on meaningful engagement. The Agency held a similar
meeting with communities, tribes, and small businesses to hear their
views on meaningful engagement.
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\284\ See 86 FR 63254 (November 15, 2021).
\285\ Significant state plan revision includes, but is not
limited to, any revision to standards of performance or to measures
that provide for the implementation or enforcement of such
standards.
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Many stakeholders support robust public engagement, especially with
communities most affected by and vulnerable to the impacts of the state
plan, and some highlight how this type of public engagement aligns with
their commitment to EJ.\286\ State commenters also encouraged the EPA
to allow for flexibility to craft plans to the unique economic and
demographic features of each state.\287\ Some states and industry
commenters question the EPA's authority to require states to conduct
meaningful engagement and seek guidance on alternative procedures for
meaningful engagement.\288\ Other state commenters indicate that states
already take EJ initiatives into consideration and some say additional
efforts would be redundant and share concern about adequate resources
to conduct meaningful engagement.\289\ State commenters generally
advocate for the EPA to provide examples of the types of engagement
that will be approvable and seek additional guidance. Industry
commenters expressed commitment to support constructive interactions
between industry, regulators, and surrounding communities and
populations that may be disproportionately impacted.\290\ Some industry
and state commenters express concern that the meaningful engagement
requirement could cause disapproval of a state plan if the EPA fails to
provide a definition for meaningful engagement with clear parameters
and examples of adequate engagement.\291\
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\286\ The EPA received several comments on this topic. A
sampling of these comments are cited in footnotes in this section.
See Document ID Nos. EPA-HQ-OAR-2021-0317-0581, EPA-HQ-OAR-2021-
0317-0808-A1, EPA-HQ-OAR-2021-0317-0921, EPA-HQ-OAR-2021-0317-0938,
EPA-HQ-OAR-2021-0317-0814, EPA-HQ-OAR-2021-0317-0832-A2, EPA-HQ-OAR-
2021-0317-0727, EPA-HQ-OAR-2021-0317-0775, and EPA-HQ-OAR-2021-0317-
1267.
\287\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0832-A2 and EPA-
HQ-OAR-2021-0317-0581.
\288\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0727, EPA-HQ-
OAR-2021-0317-0921, EPA-HQ-OAR-2021-0317-0938, EPA-HQ-OAR-2021-0317-
0921, EPA-HQ-OAR-2021-0317-0763, EPA-HQ-OAR-2021-0317-0722.
\289\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0775 and EPA-HQ-
OAR-2021-0317-0727.
\290\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808-A1, EPA-HQ-
OAR-2021-0317-0445, EPA-HQ-OAR-2021-0317-0819, and EPA-HQ-OAR-2021-
0317-0456.
\291\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0921 and EPA-HQ-
OAR-2021-0317-0938.
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State commenters offer an array of helpful suggestions based on
their own experience and initiatives. New Mexico, for example, agreed
with the EPA that requiring states to share information and solicit
input from stakeholders at critical junctures during plan development
will ensure communities have abundant opportunities to participate in
the plan development process.\292\ New Mexico further agreed with the
EPA's proposal to give the reasonable notice requirement additional and
separate meaning from ``public hearing'' to ensure the public has
reasonable notice of relevant information, as well as the opportunity
to participate in the state plan development.
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\292\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0832-A2.
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New Mexico discusses that in addition to using traditional
communication technologies, even with potential barriers involving
accessibility of technologies (e.g., video conferencing, social media,
and smart phone applications), these new technologies should also be
utilized during the meaningful engagement process and they specifically
ask the EPA to permit both new and traditional communication
technologies to qualify as a means to conduct meaningful public
engagement. New Mexico also suggests that states, local governments,
community organizations, and other stakeholders may find it helpful to
create organized groups that can help address interstate air quality
issues. For example, they participate in the Four Corners Air Quality
Group, which could serve as a model for such coordination. New Mexico,
along with the Navajo Nation, Colorado, Arizona, and Utah meet
regularly to address common air quality issues in the region. The Four
Corners Air Quality Group also includes a variety of different
stakeholders including community members and organizations and industry
leaders. The goals and functions of any cross-border groups can, and
should, be crafted to the unique needs of the area(s) in which they
serve.
States and Cities provided other examples of strategies for states
to consider.\293\ They first suggest targeting special notice, by mail,
of public participation opportunities to residents and schools within a
certain radius from regulated oil and natural gas facilities. Their
second suggestion includes hosting a series of public meetings or
workshops to provide background on the purpose of the state plans, the
process for developing the plans, and the public comment and hearing
process. Third, they suggest assuring that those public meetings,
workshops, and hearings are held at times that are convenient for
members of the affected community, that translation services are
available at such events, and that there are options for participating
via phone or videoconference. Fourth, they recommend ensuring that any
public meeting, workshop, hearing, or other format for gathering input
are safe spaces and that participation does not endanger community
members because of immigration or employment status. Fifth, they
suggest providing information on a public website and in hardcopy at an
accessible location within the community, such as a public library or
school. Lastly, they agree that the state plan submission would need to
describe and report on the engagement conducted which would be
evaluated as part of the state plan completeness determination.
Commenters also seek additional guidance on how states could go about
making public meetings or workshops safe spaces for undocumented
members of overburdened or underserved communities. Similarly,
commenters ask if the EPA could specify that information about the
rulemaking to be shared at a public meeting or workshop must be
translated in communities with linguistic barriers by the EPA's duties
under Title VI the Civil Rights Act.
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\293\ See Document ID Nos. EPA-HQ-OAR-2021-0317-1267.
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The EPA previously proposed in EG OOOOc to include certain
meaningful engagement in addition to the requirements for notice and
public hearing. The notice and public hearing requirements in 40 CFR
60.23a(c)-(f) require the states to conduct one or more public hearings
prior to the adoption of any plan. The states are to provide
notification to the public by prominent advertisement to the public of
the date, time, and place of the public hearing, 30 days prior to the
date of such hearing, and the advertisement requirement may be
satisfied through the internet. Id. at (d).
The EPA recognizes that a fundamental purpose of the Act's notice
and public hearing requirements is for all affected members of the
public, and not just a particular subset, to participate in pollution
control planning processes that impact their health and
[[Page 74829]]
welfare.\294\ Accordingly, in order for there to be a meaningful
opportunity for the public to participate in hearings on CAA section
111(d) state plans, the notice of such hearings must be reasonably
adequate in its ability to reach affected members of the public. Many
states provide for notification of public engagement through the
internet, however there cannot be a presumption that such notification
is adequate in reaching all those who are impacted by a CAA section
111(d) state plan and would benefit the most from participating in a
public hearing. For example, data shows that as many as 30 million
Americans do not have access to broadband infrastructure that delivers
even minimally sufficient speeds, and that 25 percent of adults ages 65
and older report never going online.\295\ Examples of prominent
advertisement for a public hearing, in addition to through the
internet, may include notice through newspapers, libraries, schools,
hospitals, travel centers, community centers, places of worship, gas
stations, convenience stores, casinos, smoke shops, Tribal Assistance
for Needy Families offices, Indian Health Services, clinics, and/or
other community health and social services as appropriate for the
emission guideline addressed.
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\294\ Consistent with this principle of providing reasonable
notice under the CAA, under programs other than CAA section 111(d),
the EPA similarly requires states to provide specific notice to an
area affected by a particular proposed action. See e.g., 40 CFR
51.161(b)(1) requiring specific notice for an area affected by a
state or local agency's analysis of the effect on air quality in the
context of the New Source Review program; 40 CFR 51.102(d)(2), (4),
and (5) requiring specific notice for an area affected by a CAA
section 110 SIP submission.
\295\ FACT SHEET: Biden-Harris Administration Mobilizes
Resources to Connect Tribal Nations to Reliable, High-Speed internet
(Dec. 22, 2021). https://www.whitehouse.gov/briefing-room/statements-releases/2021/12/22/fact-sheet-biden-harris-administration-mobilizes-resources-to-connect-tribal-nations-to-reliable-high-speed-internet/; 7% of Americans don't use the
internet. Who are they? Pew Research Center (Apr. 2, 2021), https://www.pewresearch.org/fact-tank/2021/04/02/7-of-americans-dont-use-the-internet-who-are-they/.
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Given the public health and welfare objectives of CAA section
111(d) in regulating specific existing sources, the EPA believes it is
reasonable to require meaningful engagement as part of the state plan
development public participation process in order to further these
objectives. Additionally, CAA section 301(a)(1) provides that the EPA
is authorized to prescribe such regulations ``as are necessary to carry
out [its] functions under [the CAA].'' The proposed meaningful
engagement requirements would effectuate the EPA's function under CAA
section 111(d) in prescribing a process under which states submit plans
to implement the statutory directives of this section. Therefore, the
EPA is proposing additional meaningful engagement requirements to
ensure that pertinent stakeholders have reasonable notice of relevant
information and the opportunity to participate in the state plan
development throughout the process. The EPA intends to propose similar
meaningful engagement provisions to this provision under the
implementing regulations in a separate upcoming rulemaking that would
apply generally to new EG promulgated under CAA section 111(d). While
inviting comments on the application of these proposed revisions in the
context of the oil and gas sector in this rulemaking, the EPA also
encourages the public to provide comments on these proposed revisions
more generally in that upcoming rulemaking process to amend the
implementing regulations. The EPA intends to finalize that rulemaking
before finalizing this oil and gas rulemaking.
Consistent with its intended addition to the implementing
regulations, in this supplemental proposal, the EPA is proposing
regulatory text for EG OOOOc in 40 CFR 60.5365c regarding the proposed
meaningful engagement requirements that states must complete prior to
the submittal of their state plans. In particular, the EPA is proposing
to define meaningful engagement as ``. . . timely engagement with
pertinent stakeholder representation in the plan development or plan
revision process. Such engagement must not be disproportionate nor
favor certain stakeholders. It must include the development of public
participation strategies to overcome linguistic, cultural,
institutional, geographic, and other barriers to participation to
assure pertinent stakeholder representation, recognizing that diverse
constituencies may be present within any particular stakeholder
community. It must include early outreach, sharing information, and
soliciting input on the State plan.'' The EPA is also proposing to
define that pertinent stakeholders ``. . .include, but are not limited
to, industry, small businesses, and communities most affected by and/or
vulnerable to the impacts of the plan or plan revision.'' Increased
vulnerability of communities may be attributable, among other reasons,
to both an accumulation of negative and lack of positive environmental,
health, economic, or social conditions within these populations or
communities. Examples of such communities have historically included,
but are not limited to, communities of color (often referred to as
``minority'' communities), low-income communities, tribal and
indigenous populations, and communities in the United States that
potentially experience disproportionate health or environmental harms
and risks as a result of greater vulnerability to environmental
hazards. Tribal communities or communities in neighboring states may
also be impacted by a state plan and, if so, should be identified as
pertinent stakeholders. In addition, to the extent a designated
facility would qualify for a less stringent standard through
consideration of RULOF as described in section V.B.3.h of this
preamble, the state, must identify and engage with the communities most
affected by and vulnerable to the health and environmental impacts from
the designated facility considered in a state plan for RULOF
provisions. The EPA expects that the inclusion of the definitions of
meaningful engagement and pertinent stakeholders in EG OOOOc will
provide the states specificity around the meaningful engagement
requirements while allowing for flexibility in the implementation of
such requirements.
In the November 2021 proposal, the EPA proposed to include a
requirement for a demonstration of meaningful engagement as part of the
completeness evaluation of a state plan submittal. The EPA is proposing
regulatory text associated to the proposed meaningful engagement
demonstration states are to include in their plans as part of the
completeness criteria. The EPA is proposing that a state would be
required to provide, in their plan submittal, a list of the pertinent
stakeholders and a summary of engagement conducted and of the
stakeholder input provided. The EPA would evaluate the states'
demonstrations regarding meaningful engagement as part of its
completeness evaluation of a state plan submittal. If a state plan
submission does not include the required elements for public
participation, including requirements for meaningful engagement, this
may be grounds for the EPA to find the submission incomplete or to
disapprove the plan. The EPA is soliciting comment on the proposed
definitions of meaningful engagement and pertinent stakeholders as well
as the inclusion of meaningful engagement requirements in completeness
criteria for state plan submission. The EPA also solicits comments on
examples or models of meaningful engagement by states, including best
practices and challenges.
During the state plan process, the EPA expects states to identify
the pertinent stakeholders. As part of efforts to ensure
[[Page 74830]]
meaningful engagement, states will share information and solicit input
on plan development and on any accompanying assessments. This
engagement will help ensure that plans achieve the appropriate level of
emission reductions, that communities most affected by and vulnerable
to the health and environmental impacts from the designated facilities
partake in the benefits of the state plan, and that these communities
are protected from being adversely impacted by the plan. In addition,
the EPA recognizes that emissions from designated facilities could
cross state and/or Tribal borders, and therefore may affect communities
in neighboring states or Tribal lands. The EPA expects that the
discussion in section VI of the November 2021 proposal (86 FR 63139)
will assist the states in the identification of pertinent stakeholders.
The EPA is soliciting comment on how meaningful engagement should apply
to pertinent stakeholders inside and outside of the borders of the
state that is developing a state plan, for example, if a state should
coordinate with the neighboring state and/or tribes for engagement or
directly contact the affected communities.
The EPA further proposes to allow a state to request the approval
of different state procedures for public participation. The EPA
proposes to require that such alternate state procedures do not
supersede the meaningful engagement requirements, so that a state would
still be required to comply with the meaningful engagement requirements
even if they apply for a different procedure than the other public
notice and hearing requirements. The EPA is however also proposing that
states may apply for, and the EPA may approve, alternate meaningful
engagement procedures if, in the judgement of the Administrator, the
procedures, although different from the requirements of this subpart,
in fact provide for adequate notice to and meaningful engagement of the
public. The EPA is soliciting comment on the distinction between
request for approval of alternate state procedures to meet public
notice and hearing requirements from those to meet meaningful
engagement, and comment on the consideration of request for approval of
alternate meaningful engagement procedures.
The EPA conducted meaningful engagement prior to the November 2021
proposal. The EPA believes this example will provide states with ideas
for how they can structure their own meaningful engagement activities.
States are not limited by the EPA's example, but rather the EPA's
example should be viewed as a minimum of what type of engagement is
considered sufficient to meet the meaningful engagement requirement for
purpose of state plan submittal.
Prior to the November 2021 proposal, the EPA identified stakeholder
groups likely to be interested in the proposal and engaged with them in
several ways including through meetings, training webinars, and public
listening sessions to share information with stakeholders about this
action, on how stakeholders may comment on the proposed rule, and to
hear their input about the industry and its impacts as we were
developing this proposal.\296\ Specifically, on May 27, 2021, the EPA
held a webinar-based training designed for communities affected by this
rule.\297\ This training provided an overview of the Crude Oil and
Natural Gas Industry and how it is regulated and offered information on
how to participate in the rulemaking process. The EPA also held virtual
public listening sessions June 15 through June 17, 2021, and heard
various community and health related themes from speakers who
participated. 298 299
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\296\ For more information about the EPA's pre-proposal outreach
activities, please see EPA Docket ID No. EPA-HQ-OAR-2021-0295 and
EPA-HQ-OAR-2021-0317. For a description of the themes that
commenters raised please see the 2021 November proposal at 86 FR
63143.
\297\ https://www.epa.gov/sites/default/files/2021-05/documents/us_epa_training_webinar_on_oil_and_natural_gas_for_communities.5.27.2021.pdf.
\298\ June 15, 2021 session: https://youtu.be/T8XwDbf-B8g; June
16, 2021. session: https://www.youtube.com/watch?v=l23bKPF-5oc; June
17, 2021 session: https://www.youtube.com/watch?v=R2AZrmfuAXQ.
\299\ Full transcripts for the listening sessions are posted at
EPA Docket ID No. EPA-HQ-OAR-2021-0295.
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In addition to the trainings and listening sessions, the EPA
engaged with community leaders potentially impacted by this proposed
action by hosting a meeting with EJ community leaders on May 14, 2021.
The EPA provided the public with factual information to help them
understand the issues addressed by the November 2021 proposal. We
obtained input from the public, including communities, about their
concerns about air pollution from the oil and gas industry, including
receiving stakeholder perspectives on alternatives. The EPA considered
and weighed information from communities as the agency developed the
November 2021 proposal.
In addition to the engagement conducted prior to the November 2021
proposal, the EPA provided the public, including those communities
disproportionately impacted by the burdens of pollution, opportunities
to engage in the EPA's public comment period for this proposal,
including by hosting trainings on the proposed rule and a public
hearing. EPA hosted three half-day trainings November 16 through 18,
2021, to provide background information, an overview of the proposed
rule, stakeholder panel discussions, and information on how to
effectively engage in the regulatory process. The trainings were open
to the public, with a focus on communities with EJ concerns, Tribes and
small business stakeholders. The public hearing occurred on November 30
to December 2, 2021, and the EPA requested speakers discuss:
What impacts they are experiencing (i.e., health, noise,
smells, economic),
How the community would like the EPA to address their
concerns,
How the EPA is addressing those concerns in the
rulemaking, and
Any other topics, issues, concerns, etc. that the public
may have regarding this proposal.
The EPA expects that the description of the meaningful engagement
with pertinent stakeholders included in the preamble and in the docket
of this rulemaking will serve as a guide of the meaningful engagement
demonstration states are to include in their plans as part of the
completeness criteria.
C. Components of State Plan Submission
While the EPA is not proposing any changes from the November 2021
proposal to this section, the EPA is proposing to add a provision for
electronic submission of state plans. The provision at 40 CFR
60.23a(a)(1) currently requires state plan submissions to be made in
accordance with the provision in 40 CFR 60.4. Pursuant to 40 CFR
60.4(a), all requests, reports, applications, submittals, and other
communications to the Administrator pursuant to 40 CFR part 60 shall be
submitted in duplicate to the appropriate Regional Office of the EPA.
The provision in 40 CFR 60.4(a) then proceeds to include a list of the
corresponding addresses for each Regional Office. In this supplemental
proposal, the EPA is proposing to require electronic submission of
state plans instead of paper copies as according to 40 CFR 60.4. In
particular, the EPA is proposing to include a sentence in 40 CFR
60.5362c(a) that reads as follows: ``The submission of such plan shall
be made in electronic format according with 40 CFR 60.5362c(d) of this
subpart.'' In 40 CFR 60.5362c(d), the EPA is proposing the requirements
associated with the electronic submittal of plans.
[[Page 74831]]
As previously described, CAA section 111(d) requires the EPA to
promulgate a ``procedure'' similar to that of CAA section 110 under
which states submit plans. The statute does not prescribe a specific
platform for plan submissions, and the EPA reasonably interprets the
procedure it must promulgate under the statute as allowing it to
require electronic submission. Requiring electronic submission is
reasonable for the following reasons. Providing for electronic
submittal of CAA section 111(d) state plans in EG OOOOc in place of
paper submittals aligns with current trends in electronic data
management and will result in less burden on the states. It is the
EPA's experience that the electronic submittal of information increases
the ease and efficiency of data submittal and data accessibility. The
EPA's experience with the electronic submittal process for SIPs under
CAA section 110 has been successful as all the states are now using the
State Planning Electronic Collaboration System (SPeCS). SPeCS is a
user-friendly, web-based system that enables state air agencies to
officially submit SIPs and associated information electronically for
review and approval to meet their CAA obligations related to attaining
and maintaining the NAAQS. SPeCS is the EPA's preferred method for
receiving such SIPs submissions. The EPA has worked extensively with
state air agency representatives and partnered with E-Enterprise for
the Environment and the Environmental Council of the States to develop
this integrated electronic submission, review, and tracking system for
SIPs. SPeCS can be accessed by the states through the CDX. The CDX is
the Agency's electronic reporting site and performs functions for
receiving acceptable data in various formats. The CDX registration site
supports the requirements and procedures set forth under the EPA's
Cross-Media Electronic Reporting Regulation, 40 CFR part 3.
The EPA is proposing to include the requirements associated with
the electronic submittal of a state plan in EG OOOOc. As proposed, EG
OOOOc will require state plan submission to the EPA be via the use of
SPeCS or through an analogous electronic reporting tool provided by the
EPA for the submission of any plan required by this subpart. The EPA is
also proposing to include language to specify that states are not to
transmit CBI through SPeCS. Even though state plans submitted to the
EPA for review and approval pursuant to CAA section 111(d) through
SPeCS are not to contain CBI, this language will also address the
submittal of CBI in the event there is a need for such information to
be submitted to the EPA. The requirements for electronic submission of
CAA section 111(d) state plans in EG OOOOc will ensure that these
Federal records are created, retained, and maintained in electronic
format. Electronic submittal will also improve the Agency's efficiency
and effectiveness in the receipt and review of state plans. The
electronic submittal of state plans may also provide continuity in the
event of a disaster like the one our nation experienced with COVID-19.
The EPA requests comment on whether the EPA should provide for
electronic submittals of plans as an option instead of as a
requirement. The EPA requests comment on whether a requirement for
electronic submissions of CAA section 111(d) state plans should be via
SPeCS or whether another electronic mechanism should be considered as
appropriate for CAA section 111(d) state plan submittals.
D. Timing of State Plan Submissions and Compliance Times
Background and Court Decision Re: Vacated Timelines. Under CAA
section 111(d), it is first the EPA's responsibility to establish a
BSER and a presumptive level of stringency via a promulgated EG. It is
then each state's obligation to submit a plan to the EPA that
establishes standards of performance for each designated facility. The
EPA acknowledged in the November 2021 proposal that the D.C. Circuit
vacated certain timing provisions within 40 CFR part 60, subpart Ba.
Am. Lung Assoc. v. EPA, 985 F.3d at 991 (D.C. Cir. 2021) (ALA). See 86
FR 63255 (November 15, 2021). These vacated timing requirements
include: the timeline for state plan submissions, the timeline for the
EPA to act on a state plan, the timeline for the EPA to promulgate a
Federal plan, and the timeline that dictates when state plans must
include increments of progress. As a result of the court's vacatur, no
regulations currently govern the timing of these actions for EGs
promulgated after July 8, 2019.\300\ The Agency plans to undertake a
separate rulemaking to address these vacated provisions in subpart Ba
for purposes of the implementing regulations, including a generally
applicable deadline for state plan submissions. However, the EPA
solicited comment in the November 2021 proposal on any facts and
circumstances that are unique to the oil and natural gas industry that
the EPA should consider when proposing a timeline for plan submission
applicable to a final EG for this source category. The EPA is now
proposing to require that each state adopt and submit to the
Administrator, within 18 months after publication of the final EG
OOOOc, a plan for the control of GHGs in the form of limitations on
methane to which EG OOOOc applies. As described further in this
section, an 18-month deadline for state plans addressing EG OOOOc both
appropriately accommodates the process required by states to develop
plans to effectuate the EG OOOOc, and is consistent with the objective
of CAA section 111(d) to ensure that designated facilities control
emissions of GHGs that the EPA has determined may be reasonably
anticipated to endanger public health or welfare.
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\300\ The court did not vacate the applicability provision for
subpart Ba under 40 CFR 60.20a(a).
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The EPA notes that the portions of the implementing regulations
under subpart Ba that were not affected by the court's vacatur, the
November 2021 proposal, and this supplemental proposal collectively lay
out all of the required components of, and requirements for, state
plans for purposes of EG OOOOc. Therefore, states will have the
necessary information at that time to develop state plans to meet the
requirements of any final EG OOOOc. Any separate rulemaking to address
the vacated provisions in subpart Ba will not add to or change these
required components. The EPA intends to propose deadlines for its
action on state plan submissions and for promulgation of a Federal plan
in its separate rulemaking. These deadlines are intended to apply
generally to these actions implementing EGs under CAA section 111(d),
including to the EPA's action on state plan submissions and
promulgation of a Federal plan under the final EG OOOOc. It is not
necessary for the EPA to propose deadlines on its own action on state
plans submitted in response to a final EG OOOOc, or promulgation of a
Federal plan where a state fails to submit an approvable plan, as part
of this supplemental proposal because these deadlines are not relevant
to states in the development of their plans, and go to the EPA's
actions subsequent to the states' development of their plans. However,
the EPA intends to propose and finalize these deadlines not later than
finalization of an EG OOOOc, so that states and stakeholders will have
knowledge of them as development on state plans begins. Additionally,
as described further in this section, the EPA is proposing the final
compliance schedule for designated facilities to run from the deadline
for state plan submissions. Accordingly, the compliance deadline for
any final EG
[[Page 74832]]
OOOOc will also be knowable and provide certainty of obligations to
regulated entities and other stakeholders in advance of state plan
development. The D.C. Circuit's vacatur of the extended timelines in
subpart Ba was based both on the EPA's failure to substantiate the
necessity for the additional time at each step of the administrative
process, and the EPA's failure to address how those extended
implementation timelines would impact public health and welfare.
Accordingly, for EG OOOOc, the EPA has evaluated these factors and is
proposing the 18-month state plan deadline based on the minimum
administrative time reasonably necessary for each step in the
implementation process thus, minimizing impacts on public health and
welfare. This approach addresses both aspects of the ALA decision
because states will take no longer than necessary to develop and adopt
plans that impose requirements consistent with the overall objectives
of CAA section 111(d).
The EPA acknowledges this proposed 18-month deadline is not
identical to the generally applicable three year-deadline for SIPs
under CAA section 110, which the agency adopted in the vacated subpart
Ba rule. However, the EPA's proposed deadline is consistent with the
requirement of CAA section 111(d) that the EPA to promulgate a
procedure ``similar'' to that of CAA section 110, rather than an
identical procedure. This is also consistent with the ALA decision,
which requires the EPA to ``engage meaningfully with the different
scale'' of CAA section 111(d) and 110 plans. Am. Lung Ass'n v. EPA, 985
F.3d 914, 993 (D.C. Cir. 2021). Accordingly, the EPA evaluated each
step of the OOOOc implementation process to independently determine the
appropriate duration of time to accomplish the given step as part of
the overall process, and the proposed timeline represents what the EPA
is proposing to determine will be necessary for a state plan upon
publication of any final EG OOOOc.
As described previously, no timing requirements for state plan
submissions are currently in effect for EGs published after July 8,
2019. The original implementing regulations promulgated under subpart B
in 1975, which are applicable to EGs published before July 8, 2019,
provide that states have nine months to submit a state plan after
publication of a final EG. 40 CFR 60.23(a)(1). In 2019, the EPA
promulgated subpart Ba and provided three years for states to submit
plans, consistent with the timelines provided for submission of SIPs
pursuant to CAA section 110(a)(1). This 3-year timeframe was vacated in
the ALA decision, and thus currently there is no applicable deadline
for state plan submissions required under EGs subject to subpart Ba. In
evaluating the appropriate timeline for plan submittal to propose for
EG OOOOc, the EPA reviewed steps that states need to carry out to
develop, adopt, and submit a state plan to the EPA, and its history in
implementing EGs under the timing provisions of subpart B. The EPA
further evaluated statutory deadlines, contents, and processes for
relatively comparable state plans under CAA sections 129 and 182. The
EPA also considered the characteristics of the Crude Oil and Natural
Gas source category to assist justification for the timelines and
address how the timeline will impact health and welfare.
In developing a CAA section 111(d) state plan, a state must
consider multiple components in meeting applicable requirements. In
addition to any requirements that an EG specifies for state plans,
subpart Ba specifies certain fundamental elements that must be included
in a state plan submission (see 40 CFR 60.24a, 60.25a, 60.26a) and
certain processes that a state plan must undergo in adopting and
submitting a plan (see 40 CFR 60.23a). In addition to these EPA
requirements for state plans, there are also state-specific processes
applicable to the development and adoption of a state plan. In
particular, the component that the EPA expects to take the most time
and have the most variability from state to state is the administrative
process (e.g., through legislative processes, regulation, or permits)
that establishes standards of performance. Considering this
variability, 18 months should adequately accommodate the differences in
state processes necessary for the development of a state plan that
meets applicable requirements. The EPA evaluated data from previously
implemented EGs, and the statutory deadlines and data from analogous
programs (i.e., CAA section 129), as described below, to help inform
this proposed 18-month timeline.
Subpart B provides nine months for states to submit plans after
publication of a final EG. The EPA's review of state's timeliness for
submitting CAA section 111(d) plans under the 9-month timeline
indicates that most states either did not submit plans or submitted
plans that were substantially late. We note that the plans submitted
under subpart B were not subject to the additional requirements the EPA
is proposing for meaningful engagement and consideration of RULOF,
respectively described in section V.B. Based on the lack of timeliness
of prior state plan submissions under subpart B and the additional
requirements of this proposal, EG OOOOc, nine months is not a suitable
amount of time for most states to adequately develop a plan for an EG.
To help inform what is an appropriate proposal for the state plan
submission deadline, the EPA also reviewed CAA section 129's statutory
deadline and requirements for state plans, and the timeliness and
responsiveness of states under CAA section 129 EGs. CAA section 129
references CAA section 111(d) in many instances, creating considerable
overlap in the functionality of the programs. Notably, existing solid
waste incineration units are subject to the requirements of both CAA
sections 129 and 111(d). CAA section 129(b)(1). The processes for CAA
sections 111(d) and 129 are very similar in that states are required to
submit plans to implement and enforce the EPA's EGs. However, there are
some key distinctions between the two programs, most notably that CAA
section 129(b)(2) specifies that state plans be submitted no later than
1 year from the promulgation of a corresponding EG, whereas the statute
does not specify a particular timeline for state plan submissions under
CAA section 111(d) and is instead governed by the EPA's implementing
regulations (i.e., subparts B and Ba). Moreover, CAA section 129 plans
are required by statute to be at least as protective as the EPA's EGs.
However, CAA section 111(d) permits states to take into account
remaining useful life and other factors, which suggests that the
development of a CAA section 111(d) plan could involve more complicated
analyses than a CAA section 129 plan (see section V.B. for more
information on RULOF provisions). The contrast between the CAA section
129 plans and CAA section 111(d) plans suggests that in determining the
timeframe for CAA section 111(d) plan submissions the EPA should
provide for a longer timeframe than the 1 year timeframe the statute
provides under CAA section 129.
The EPA found that a considerable number of states have not made
required state plan submissions in response to a CAA section 129 EG. In
instances where states submitted CAA section 129 plans, a significant
number of states submitted plans between 14 to 17 months after the
promulgated EG. This suggests that states will typically need more than
1 year to develop a state plan to implement an EG, particularly for a
program that permits more source-
[[Page 74833]]
specific analysis than under CAA section 129 as CAA section 111(d)
does.
In the 2019 promulgation of subpart Ba, the EPA mirrored CAA
section 110 by giving states 3 years to submit plans. As previously
described, the court partly faulted the EPA for adopting the CAA
section 110 timelines without accounting for the differences in scale
and scope between CAA section 110 and 111(d) plans. The EPA has now
more closely evaluated the statutory deadlines and requirements in the
CAA section 110 implementation context to determine what might be
feasible for an OOOOc EG state plan submission timeline. The EPA
specifically focused on statutory SIP submission deadline and
requirements in the context of attainment plans for the ozone NAAQS.
Subpart 2 of Title I of the CAA contains a number of deadlines for
ozone attainment plans that are 2 years or longer. For example, areas
initially designated Marginal have two years from designation to submit
a SIP that contains a permitting program and emissions inventory. CAA
section 182(a). Areas initially designated Moderate have two years to
submit a plan implementing reasonable available control technologies
under CAA section 182(b)(2)), and three years to submit their
attainment plan and other requirements under CAA section 182(b)(1).
These ozone attainment plans are arguably more complicated for states
to develop when compared to plans under CAA section 111(d) for EG
OOOOc. For example, ozone attainment plans require states to determine
how to control a variety of sources, based on extensive modeling and
analyses, in order to bring a nonattainment area into attainment of the
NAAQS by a specified attainment date. Under CAA section 111(d) and EG
OOOOc, it is clear which designated facilities must be subject to a
state plan, and the standards of performance for these sources must
generally reflect the level of stringency determined by the EG unless a
state chooses to account for RULOF. Additionally, ozone attainment
plans must contain inventories of actual emissions from certain
sources, whereas the EPA is proposing to supersede the subpart Ba
inventory requirement for purposes of this EG. The difference in
complexity between the CAA ozone attainment plan requirements and the
plan requirements for EG OOOOc suggests that a timeline of 18 months is
more appropriate for developing state plans submissions in response to
this EG.
Furthermore, the EPA considered the characteristics of the Crude
Oil and Natural Gas source category. The EPA believes that EG OOOOc has
the potential to require states to perform considerable engineering
and/or economic analyses for their plan. For example, the EPA
anticipates considerable engineering analyses for when states chose to
leverage their existing state programs and determine that their
existing state program meets the criteria to conduct a source-by-source
stringency comparison. The engineering analysis can become more complex
should a state chooses to utilize a different design, equipment, work
practice, and/or operational standard than the EG because a qualitative
assessment will have a number of metrics that require evaluation. The
EPA also anticipates states will need to conduct considerable
engineering and economic analysis should a state invoke RULOF. As
discussed in section V.C., when invoking RULOF, the plan submission
must identify all control technologies available for the source and
evaluate the BSER factors for each technology, using the same metrics
and evaluating them in the same manner as the EPA did in developing the
EG. For example, if the EPA considered capital cost as part of the BSER
analysis, the state will also need to consider the same.
The EPA has long recognized the unique nature of the Crude Oil and
Natural Gas source category because, in comparison to other EG, it is
geographically spread out covering multiple industry segments.
Specifically, the EPA defines the Crude Oil and Natural Gas source
category to mean: (1) Crude oil production, which includes the well and
extends to the point of custody transfer to the crude oil transmission
pipeline or any other forms of transportation; and (2) natural gas
production, processing, transmission, and storage, which include the
well and extend to, but do not include, the local distribution company
custody transfer station.\301\ The Crude Oil and Natural Gas source
category impacts a great number of states, tribes, and U.S. territories
in some capacity. U.S. Energy Information Administration (EIA)
production data shows thirty-four states that have crude oil and or
natural gas production.\302\ Except for Vermont and Hawaii, the states
not producing crude oil and or natural gas have compressor stations in
the transmission and storage segment. The EPA understands that EG OOOOc
for the Crude Oil and Natural Gas source category will apply to an
extraordinary number of designated facilities and for many designated
facilities the standards are complex compared to other EG. For example,
in the U.S., the EPA has identified over 15,000 oil and gas owners and
operators, around 1 million producing onshore oil and gas wells, about
5,000 gathering and boosting facilities, over 650 natural gas
processing facilities, and about 1,400 transmission compression
facilities. States will need to develop and draft plans covering these
designated facilities that include the required components, such as
standards of performance and implementation measures for such
standards, and adopt the plans through their required administrative
processes before submitting them to the EPA. EG OOOOc covers numerous
designated facilities with corresponding presumptive standards. By
comparison, the EPA's EG for Municipal Solid Waste Landfills included
one designated facility type, affecting approximately 1,000 landfills.
81 FR 59313 (August 29, 2016). Of these 1,000 landfills, approximately
731 will be affected by the collection and control standard laid out in
the rule, approximately 93 more landfills than the 1996 Municipal Solid
Waste Landfills EG. 61 FR 9919 (March 12, 1996).
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\301\ For purposes of the November 2021 proposal and this
supplemental proposed rulemaking, for crude oil, the EPA's focus is
on operations from the well to the point of custody transfer at a
petroleum refinery, while for natural gas, the focus is on all
operations from the well to the local distribution company custody
transfer station commonly referred to as the ``city-gate''.
\302\ See https://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbblpd_a.htm and https://www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_FGW_mmcf_a.htm.
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The EPA also recognizes the need to address potential health and
welfare impacts of methane emissions from this source category. The EPA
discusses extensively in section III of the November 2021 proposal
\303\ titled, ``Air Emissions from the Crude Oil and Natural Gas Sector
and Public Health and Welfare,'' and in section VI of the November 2021
proposal titled, ``Environmental Justice Considerations, Implications,
and Stakeholder Outreach,'' the urgent need to mitigate climate-
destabilizing pollution and protecting human health by reducing GHG
emissions from the Oil and Natural Gas Industry,\304\ specifically, the
Crude Oil and Natural Gas source category.\305\
[[Page 74834]]
The Oil and Natural Gas Industry is the United States' largest
industrial emitter of methane, a highly potent GHG. Human activity-
related emissions of methane are responsible for about one third of the
warming due to well-mixed GHGs and constitute the second most important
warming agent arising from human activity after carbon dioxide (a well-
mixed gas is one with an atmospheric lifetime longer than a year or
two, which allows the gas to be mixed around the world, meaning that
the location of emission of the gas has little importance in terms of
its impacts). According to the Intergovernmental Panel on Climate
Change (IPCC), strong, rapid, and sustained methane reductions are
critical to reducing near-term disruption of the climate system and are
a vital complement to reductions in other GHGs that are needed to limit
the long-term extent of climate change and its destructive impacts. The
need to balance the complexity of EG OOOOc and the need to mitigate
climate change and protecting human health further suggest that a
timeline of 18 months is more appropriate for development of state
plans submissions.
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\303\ See 86 FR 63110 (November 15, 2021).
\304\ The EPA characterizes the Oil and Natural Gas Industry
operations as being generally composed of four segments: (1)
Extraction and production of crude oil and natural gas (``oil and
natural gas production''), (2) natural gas processing, (3) natural
gas transmission and storage, and (4) natural gas distribution.
\305\ The EPA defines the Crude Oil and Natural Gas source
category to mean: (1) Crude oil production, which includes the well
and extends to the point of custody transfer to the crude oil
transmission pipeline or any other forms of transportation; and (2)
natural gas production, processing, transmission, and storage, which
include the well and extend to, but do not include, the local
distribution company custody transfer station. For purposes of this
proposed rulemaking, for crude oil, the EPA's focus is on operations
from the well to the point of custody transfer at a petroleum
refinery, while for natural gas, the focus is on all operations from
the well to the local distribution company custody transfer station
commonly referred to as the ``city-gate''.
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Thus, based on the EPA's evaluation of states' responsiveness to
previous CAA section 111(d) EGs, the contrast between the development
of CAA section 111(d) plans and CAA section 129 plans, the complexity
of the source category and designated facilities, and the need to
quickly take action to address critical climate and health and welfare
impacts, the EPA is proposing to require that state plans under EG
OOOOc be due 18 months after publication of the final EG. This proposed
timeframe is substantially shorter than the 3-year deadline vacated by
the D.C. Circuit; however, it should give states adequate time to adopt
and submit approvable plans without extending the timing such that
significant adverse impacts to health and welfare are likely to occur
from the foregone emission reductions during the state planning
process. Allowing states sufficient time to develop feasible
implementation plans for their designated facilities that adequately
address public health and environmental objectives will ultimately help
ensure timelier implementation of EG OOOOc, and therefore achievement
in actual emission reductions, than would an unattainable deadline that
may result in the failure of states to submit plans and require the
development and implementation of a Federal plan.
The EPA recognizes that the court, in ALA, faulted the Agency for
failing to consider the potential impacts to public health and welfare
associated with extending planning deadlines. The EPA does not
interpret the court's direction to require a quantitative measure of
impact, but rather consideration of the importance of the public health
and welfare goals when determining appropriate deadlines for
implementation of regulations under CAA section 111(d). Because 18
months is the minimum period of time in which the EPA finds that most
states can expeditiously create and submit a plan that meets applicable
requirements for EG OOOOc, it follows that the EPA has appropriately
considered the potential impacts to public health and welfare
associated with this extension of time by providing no more time than
the states reasonably need to ensure a plan is comprehensive and
timely. The EPA is soliciting comment on the proposed 18-month state
plan submission deadline upon publication of the final EG OOOOc, and
the analysis supporting the EPA's proposed determination regarding the
amount of time reasonably necessary for plan development and
submission. The EPA is also soliciting comment on whether the EPA
should consider any other factors in setting this deadline.
As discussed in section V.B of this preamble, the EPA is proposing
to include a requirement for states to undertake outreach and
meaningful engagement with pertinent stakeholders as part of the state
plan development process. The EPA solicits comment on how much, if any,
time this additional engagement will take in the state plan development
process.
In section V.B of this preamble, the EPA is also proposing
revisions to the RULOF provision. These proposed revisions would
clarify the procedures for considering RULOF by establishing a robust
analytical framework that would require a state to provide a sufficient
justification when applying a standard of performance that is less
stringent than the EPA's presumptive level of stringency, thereby
allowing the EPA to readily determine if the state's plan is
satisfactory and therefore approvable. The proposed state plan
submission timeline of 18 months should adequately provide time for
states to conduct the analyses required by this provision; however, the
EPA is soliciting comment on whether states will need additional time
in the plan development to account for instances where RULOF is
considered. The EPA is specifically requesting comment on how much
additional time might be required for this consideration and how that
additional time fits within the entire process of state plan
development.
The proposed state plan submission timeline should be generally
achievable by states. The EPA notes it is obligated to promulgate a
Federal plan for states that have not submitted a plan by the
submission deadline. Once the obligation to promulgate a Federal plan
is triggered, it can only be tolled by the EPA's approval of a state
plan. If a Federal plan is promulgated, a state may still submit a plan
to replace the Federal plan. A Federal plan under CAA section 111(d) is
a means to ensure timely implementation of EGs, and a state may choose
to accept a Federal plan for their sources rather than submit a state
plan. While the EPA encourages states to timely submit plans, there are
no mandatory sanctions associated with submitting a late plan or
accepting the implementation of a Federal plan.
Timeline for State Plan Compliance Schedule. Under 40 CFR
60.22a(b)(5), the EPA in an EG is required to provide, among other
things, ``the time within which compliance with standards of
performance can be achieved''. Each state plan must then include
compliance schedules that, subject to certain exception, require
compliance as expeditiously as practicable but no later than the
compliance times included in the relevant EG. Id. at 60.24a(a) and (c).
States are free to include compliance times in their plans that are
earlier than those included in the final EG. Id. at 40 CFR
60.24a(f)(2). If a state chooses to include a compliance schedule in
its plan that extends for a certain period beyond the date required for
submittal of the plan, then ``the plan must include legally enforceable
increments of progress to achieve compliance for each designated
facility.'' 341 Id. at 40 CFR 60.24a(d). To the extent a state accounts
for remaining useful life and other factors in applying a less
stringent standard of performance than required by the EPA in the final
EG, the state must also include a compliance deadline that it can
demonstrate appropriately correlates with that standard.
The November 2021 proposal proposed requiring that state plans
impose a compliance timeline on
[[Page 74835]]
designated facilities to require final compliance with the standards of
performance as expeditiously as practicable, but no later than 2 years
following the state plan submittal deadline. 86 FR 63256 (November 15,
2021). Commenters on the proposal indicated that more than 2 years
after the submittal of a state plan was needed to come into compliance
for existing sources. Given the number of designated facilities that
would need to come into compliance, commenters explained that requiring
existing sources to upgrade at the same time would place a substantial
burden on the supply chain (all orders at the same time) and vendors
(all install at the same time). Commenters stated that, if compliance
timelines are too short, there will be significant economic disruptions
for both the companies operating these facilities as well as the
manufacturers who support them. Commenters also stated that there would
be a need to train a tremendous number of staff on the regulatory
requirements and actions needed to comply. A few of the commenters
representing states also noted that 2 years from state plan submittal
would not allow sufficient time for states to issue the air quality
permits in advance of the compliance date for the sources to have
regulatory requirements with which to demonstrate compliance.
Environmental commenters supported the EPA's proposed requirement that
state plans include a compliance timeline within no more than 2 years
of plan submission and urged the Agency to consider whether a more
abbreviated compliance timeline is warranted.\306\
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\306\ See Document ID No. EPA-HQ-OAR-2021-0317-0844.
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In evaluating whether to revise the November 2021 proposed two-year
final compliance deadline, the EPA considered several factors that
could impact the ability of a designated facility to come into
compliance with the proposed presumptive standards. These factors are
presented in Table 38.
TABLE 38--Factors Considered When Determining Compliance Timeline
------------------------------------------------------------------------
Factor Description
------------------------------------------------------------------------
Design/Purchase Equipment.............. Equipment must be purchased and
installed to comply. This
could be control equipment or
specific equipment to meet an
equipment standard (e.g.,
solar powered pneumatic
controller). This would also
typically involve design
considerations.
Availability of Equipment (Supply Chain This factor is related to the
Issues). potential shortage of
available equipment. Note that
this could have an impact on
small businesses as the
assumption is that larger
businesses would be supplied
first.
Cost of Equipment (Individual The cost of equipment for an
Designated Facility). individual designated
facility. This cost may
disproportionally impact small
businesses.
Performance Testing.................... The requirement for a
performance testing requires
securing the services of a
testing contractor, scheduling
and planning the test, and
notifying/coordinating with
the state agency. In addition
to control device performance
testing, this would also
include monitoring (e.g.,
fugitive component
monitoring).
Complexity of Requirements............. More complex requirements may
need more time for owners and
operators to understand the
requirements and develop
procedures upfront to ensure
initial and continuing
compliance.
Availability of Specialized Services This is related to the
(Monitoring). potential shortage of
available specialized services
(e.g., OGI contractors). Note
that this could have an impact
on small businesses as the
assumption is that contractors
could prioritize larger
businesses.
Number of Designated Facilities........ The sheer number of designated
facilities may have an impact
on the ability to comply
within a specified timeline,
which assumes that it will
potentially be more
problematic for companies
owning many designated
facilities to comply in a
shorter time frame.
Existing Sources Covered by State If the designated facility is
Regulation. covered by state regulations
that cover existing sources to
a degree equivalent to the EG,
the number of designated
facilities needing to comply
with be less.
Emissions Reduced/Total Designated The overall methane emissions
Facility. reduction that will result
from control of existing
sources under the EG. EPA
could prioritize designated
facilities to achieve emission
reductions sooner.
------------------------------------------------------------------------
Some of the factors presented in Table 38 would impact the ability
of an owner or operator of a designated facility to comply within two
years more than others. For example, factors that are beyond an owner
or operator's control, such as the availability of specialized services
and availability of equipment, can be compounded by the fact that there
are a large number of designated facilities where owners or operators
are dependent on the availability of equipment and services. Other
factors, such as the cost of equipment necessary for a designated
facility to come into compliance, will impact some owners and operators
more than others. Small businesses have often reported that large
businesses generally have an advantage over small businesses in such
cases. Presumptive standards that include a higher reliance on factors
that would impact the ability of a designated facility to come into
compliance, such as those proposed for pneumatic controllers, were
considered to require more time (i.e., greater than the November 2021
proposed 2-year time frame). For example, to meet the proposed
presumptive standards for pneumatic controllers, it is expected that
more time may be needed due to the anticipated high demand for
specialized equipment to meet the proposed EG standards and the
increased reliance on ``design/purchase equipment'', ``availability of
equipment'', ``cost of equipment,'' and ``number of designated
facilities.'' Other
[[Page 74836]]
designated facility presumptive standards that are less dependent on
the need for specialized equipment or services (e.g., fugitive
emissions work practice standards) might require less time to come into
compliance than pneumatic controllers but would still require
considerable upfront planning based on the number of designated
facilities.
After consideration of comments received on the November 2021
proposal and consideration of the factors that could impact the ability
of a designated facility to come into compliance with the proposed
presumptive standards, the EPA is proposing to require that state plans
impose a compliance timeline on designated facilities to require final
compliance with the standards of performance as expeditiously as
practicable, but no later than 36 months following the state plan
submittal deadline. The EPA considered requiring differing compliance
timelines for the differing designated facilities depending on the
requirements of the proposed presumptive standards and the factors
presented in Table 38 but chose to include a uniform compliance
timeframe for all of the designated facilities. The EPA believes that
establishing a uniform compliance timeline of no later than 36 months
following the state plan submittal deadline simplifies compliance and
eases the burden on large and small business owners and operators that
need to develop and implement plans to meet their compliance
obligations for a large number of designated facilities. The required
state plan compliance elements for owners and operators to come into
compliance include the need to: (1) Become familiar with state plan
requirements for the nine different types of designated facilities, (2)
assess all existing sites and operations owned by the company to
determine the universe of designated facilities that are subject to
requirements, (3) prepare an increment of progress final control
compliance plan for meeting standards of performance for all of the
hundreds, potentially thousands, of designated facilities owned by the
company, (4) implement a compliance plan for each designated facility,
(5) ensure standards of performance for designated facility are met by
required compliance dates, and (6) plan and implement initial
compliance performance testing, monitoring, recordkeeping, and
reporting. Each of the nine types of designated facilities include
various compliance element needs (e.g., engineering assessments,
requirements to purchase equipment, contract services for modifying
existing equipment to include add-on control equipment, contract
services to perform monitoring and/or performance testing, contract
services to perform maintenance and repair services to ensure
compliance).
The level of planning and implementation of a plan to come into
compliance will differ by each type of designated facility. Further,
site-specific conditions may require different compliance paths even
for the same type of designated facility. Another factor to consider is
the ability of an owner or operator to meet the initial capital and
labor expenditures needed to develop and implement a compliance plan
will vary based on the numbers of each of the designated facilities and
available capital and in-house expertise/labor. Small businesses often
need more time to absorb the associated capital and labor expenditure
needs to develop and implement compliance plans. By allowing a uniform
compliance deadline of 36 months from the time of submittal of the
state plan to come into compliance, owners and operators are able to
take into consideration all of the differing designated facilities,
sites and expenditures that will be needed to comply when they develop
their compliance plans. This will also reduce any potential confusion
that could occur with varied compliance deadlines for designated
facilities that are covered under the proposed EG.
As previously described, EPA is proposing to require that states
submit their state plan within 18 months of publication of the EGs.
Accordingly, linking a 36-month compliance deadline to the state plan
submittal deadline for purposes of this EG would give sources ample
time to plan for compliance with an approved state plan. The EPA also
notes that publication of a final EG will also give sources meaningful
information as to their potential compliance obligations, such as the
presumptive standards, in advance of the state plan submittal deadline.
Though EPA has not yet proposed a timeline for its action on state
plans in response to the ALA vacatur, and intends to do so in an
upcoming rulemaking, such timeline cannot be so lengthy as to
contravene the court's direction to consider potential health and
welfare impacts of an extended deadline. The EPA believes that a
compliance deadline 36 months from the state plan submittal deadline is
an appropriate amount of time for designated facilities to ensure
compliance based on the EPA's general understanding of the industry and
the proposed presumptive standards and accounts for retrofit
considerations and potential supply chain issues that owners and
operators may encounter. The EPA considered whether to link the
compliance deadline to its approval of a state plan, however, requiring
compliance with state plans based on the state plan submittal deadline
rather than the state plan approval date standardizes when designated
facilities must come into compliance across states.
Subpart Ba requires that standards of performance are implemented
in a timely manner through provisions that require legally enforceable
increments of progress if the compliance schedule extends beyond 24
months after the state plan submission deadline.\307\ However, the 24-
month timeline for triggering increments of progress was vacated by the
D.C. Circuit in the ALA decision. Petitioners did not challenge, and
the court did not vacate, the substantive requirement for increments of
progress. The EPA intends to address the vacated timeline for
increments of progress for purposes of the implementing regulations in
an upcoming rulemaking. For EG OOOOc, because the EPA is proposing a
final compliance deadline of 36 months after publication of the EG, the
EPA is proposing to require that state plans must include legally
enforceable increments of progress in order to better assure compliance
by each designated facility or category of facilities. While the EPA is
proposing 36 months after the state plan submission deadline for final
compliance based on the considerations described above, increments of
progress will help assure that designated facilities are on track to
actually achieve compliance by undertaking certain concrete interim
steps. Taking into consideration the large numbers of designated
facilities that regulated entities would need to evaluate and plan for
to come into compliance, we are proposing that state plans require
owners and operators of designated facilities address two of the five
incremental of progress steps identified in the definition of
increments of progress subpart Ba: (1) A final control plan and (2)
final compliance. The EPA is proposing that the final control plan
include a compliance plan for each designated facility, but a company
would be allowed to submit one plan that covers all of the company's
designated facilities in the state in lieu of submitting a plan for
each designated facility. The final control plan would be
[[Page 74837]]
required to include an identification of their designated facilities
and how they are planning to comply with the EGs for each of their
designated facilities (e.g., air pollution control devices/measures to
be used to comply with the emission limits, standards and other
requirements). The final control plan would also be required to include
all instances where a designated facility is complying with an
alternative standard (e.g., routing centrifugal compressor wet seal
emissions to a control device to achieve a 95 percent reduction in
methane instead of complying with the 3 scfm volumetric flow rate
standard) or when the owner or operator is planning to claim technical
infeasibility to allow compliance with an alternative standard (e.g., a
pneumatic pump that demonstrates it is technically infeasible to use a
pump that is not driven by natural gas and that is technically
infeasible to route to control). We are proposing that the final
control plan be required to be submitted within two years after the
deadline for the state plan submittals. This timeline allows sufficient
time for regulated entities to develop their compliance plan for each
of their designated facilities to meet their compliance obligations.
The EPA solicits comment on the timing and requirements of this final
control plan proposal.
---------------------------------------------------------------------------
\307\ 40 CFR 60.24a(a) and 60.24a(d).
---------------------------------------------------------------------------
In addition to the final control plan, we evaluated whether to
require a report that demonstrates final compliance as an increment of
progress report. We are proposing that state plans include a
requirement for owners and operators of designated facilities to submit
a notification of final compliance report for each designated facility
on or before 60 days after the compliance date of the state plan. Under
this proposal, a company would be allowed to submit one notification
that covers all of the company's designated facilities in a state in
lieu of submitting a notification for each designated facility. As an
alternative, we evaluated not including a specific requirement for a
notification of final compliance report. Without a requirement for a
notification of final compliance report, confirmation that designated
facilities are complying with a state plan would not occur until the
first annual report. The EPA determined that requiring a notification
of final compliance report that was submitted before the first annual
report was more closely aligned with the intent of a final compliance
increment of progress step. The EPA solicits comment on this proposed
notification of final compliance report.
VI. Use of Optical Gas Imaging in Leak Detection (Appendix K)
A. Overview of the November 2021 Proposal
In the November 2021 proposal, the EPA proposed a protocol for the
use of OGI in the determination of leaks as Appendix K. The protocol
was proposed for use in the oil and gas sector but was proposed to have
broader applicability to surveys of process equipment using OGI cameras
throughout the entire oil and gas upstream and downstream sectors from
production through refining to distribution where a subpart in those
sectors references its use.
The proposed appendix K was based on extensive literature review on
the technology development, as well as observations on current
applications of OGI technology, multiple empirical laboratory studies
and OGI technology evaluations commissioned by the EPA, and a virtual
stakeholder workshop hosted by the EPA to gather input on development
of a protocol for the use of OGI. The proposed appendix K outlined the
procedures that camera operators would be required to follow to
identify leaks or fugitive emissions using a field portable infrared
camera. Additionally, the proposed appendix K contained specifications
relating to the required performance of OGI cameras, required operator
training and verification, determination of an operating window for
performing surveys, and requirements for a monitoring plan and
recordkeeping.
B. Significant Changes Since Proposal
1. Scope
The EPA proposed that appendix K would have broad applicability
across the oil and gas upstream and downstream sectors, but that it
must be referenced by an applicable subpart before it would apply. This
would potentially include well sites, compressor stations, boosting
stations, petroleum refineries, gas processing plants, and gasoline
distribution facilities. Chemical plants and other facilities outside
of the oil and gas upstream and downstream sectors were specifically
excluded in the applicability section.
Commenters stated that appendix K applicability should not be
restricted to the oil and gas upstream and downstream sectors.\308\
While the EPA originally excluded the chemical sector because there are
issues with seeing some of the compounds that could be released as
emissions in some of the chemical sector sources, there are some
chemical sector sources where most of the emissions are made up of
compounds that can be imagined by an OGI camera. As such, the EPA is
proposing to revise the scope and applicability for appendix K to
remove the sector applicability and to base the applicability on being
able to image most of the compounds in the gaseous emissions from the
process equipment. The EPA is retaining the requirement that appendix K
does not on its own apply to anyone but must be referenced by a subpart
before it would apply.
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\308\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0604, EPA-HQ-
OAR-2021-0317-0748, EPA-HQ-OAR-2021-0317-0808, and EPA-HQ-OAR-2021-
0317-0831.
---------------------------------------------------------------------------
2. Operator Training
The EPA proposed a multi-layered training requirement for OGI
camera operators because operator training is critical in developing
the ability to see leaks with an OGI camera. The proposed training
consisted of both an initial and annual classroom training on the
fundamental concepts of OGI, basic operation of the camera, best
practices for finding leaks, and the site's monitoring plan. appendix K
also contained initial field training consisting of 100 site surveys
with a senior OGI camera operator, where initially the trainee observes
the senior OGI camera operator and then eventually is observed by the
senior OGI camera operator, and a final site survey test with zero
missed persistent leaks. Additionally, the EPA proposed quarterly
performance audits for OGI camera operators either by comparative
monitoring or a review of video footage by a senior OGI camera
operator, where the auditee must have zero missed persistent leaks and
a technique that aligns with the site's monitoring plan. Auditees not
meeting these criteria must be retrained. The EPA also proposed that
operators would be required to repeat initial training after 12 months
of inactivity.
The EPA received numerous comments on all aspects of the proposed
training requirements. Commenters stated that online training should be
allowed for classroom training, and they recommended that periodic
classroom training should be extended to every 2 or 3 years.\309\
Commenters also provided a broad range of recommendations on what the
initial field training should
[[Page 74838]]
look like.\310\ The recommendations for initial training hours ranged
from around 5 to 80 hours. Additionally, some commenters said the
determination of suitability for independent monitoring should be based
on observations and comparative monitoring, not on a set number of
hours of training.\311\ Some commenters suggested reducing the final
survey test to 1 hour.\312\ Commenters also suggested that requiring
zero missed leaks during the final survey test was too stringent.\313\
Some commenters thought the OGI camera operator audits were
unnecessary, while others thought they were too frequent or too long.
There was a range of recommendations on what the audit frequency should
be, including annual or a stepped up and down frequency based on
performance.\314\ Additionally, commenters stated that requiring zero
missed leaks during the audit was too stringent and that instead of a
failed audit triggering automatic retraining, there should be an
opportunity to counsel the auditee and let them try again.\315\
Commenters thought returning operators should only be required to take
refresher level training, pass a performance audit, or pass the final
survey test.\316\ Commenters also thought there should be some
grandfathering of current OGI camera operators.\317\ Finally,
commenters stated that there should be different performance audit and
retraining requirements for small businesses and the Alaska North
Slope.\318\
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\309\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0561, EPA-HQ-
OAR-2021-0317-0793, EPA-HQ-OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-
0814, EPA-HQ-OAR-2021-0317-0831, EPA-HQ-OAR-2021-0317-0954, and EPA-
HQ-OAR-2021-0317-1373.
\310\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0463, EPA-HQ-
OAR-2021-0317-0561, EPA-HQ-OAR-2021-0317-0608, EPA-HQ-OAR-2021-0317-
0718, EPA-HQ-OAR-2021-0317-0749, EPA-HQ-OAR-2021-0317-0793, EPA-HQ-
OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-0816, EPA-HQ-OAR-2021-0317-
0831, and EPA-HQ-OAR-2021-0317-0934.
\311\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0608 and EPA-HQ-
OAR-2021-0317-0718.
\312\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808 and EPA-HQ-
OAR-2021-0317-0831.
\313\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0599, EPA-HQ-
OAR-2021-0317-0750, EPA-HQ-OAR-2021-0317-0782, EPA-HQ-OAR-2021-0317-
0793, EPA-HQ-OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-0817, and EPA-
HQ-OAR-2021-0317-0831.
\314\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0463, EPA-HQ-
OAR-2021-0317-0561, EPA-HQ-OAR-2021-0317-0599, EPA-HQ-OAR-2021-0317-
0608, EPA-HQ-OAR-2021-0317-0718, EPA-HQ-OAR-2021-0317-0749, EPA-HQ-
OAR-2021-0317-0782, EPA-HQ-OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-
0831, and EPA-HQ-OAR-2021-0317-0916.
\315\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0561, EPA-HQ-
OAR-2021-0317-0599, EEPA-HQ-OAR-2021-0317-0749, EPA-HQ-OAR-2021-
0317-0808, and EPA-HQ-OAR-2021-0317-0831.
\316\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0463, EPA-HQ-
OAR-2021-0317-0608, EPA-HQ-OAR-2021-0317-0718, EPA-HQ-OAR-2021-0317-
0808, EPA-HQ-OAR-2021-0317-0816, and EPA-HQ-OAR-2021-0317-0831.
\317\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808 and EPA-HQ-
OAR-2021-0317-0831.
\318\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0814, EPA-HQ-
OAR-2021-0317-0916, and EPA-HQ-OAR-2021-0317-1373.
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Based on these comments, the EPA is proposing specific revisions or
clarifications related to the operator training requirements. In this
action, the EPA is clarifying our intent to allow classroom training to
be online or in-person and revising the classroom refresher training
frequency to biennial (i.e., every 2 years). For the initial field
training, the EPA is proposing 30 survey hours with a senior OGI camera
operator and changing the final field test from one site to two survey
hours. The EPA is also proposing to allow up to 10 percent missed leaks
on the final survey test if there are more than 10 leaks found by the
senior OGI camera operator during the final field test and is providing
clarification on what happens if a trainee doesn't pass the final field
test. In this instance, the senior OGI camera operator would discuss
the failure with the trainee and provide instruction on improving
performance, then allow the trainee to repeat the test. While the EPA
is retaining quarterly operator audits, we are proposing to reduce the
audit from four hours to two hours and allow up to 10 percent missed
leaks if there are more than 10 leaks found by the senior OGI camera
operator during the audit. While an auditee would still need to retrain
following a failed audit, the EPA is proposing to reduce the amount of
retraining from 25 site surveys to 16 survey hours and adding a
requirement that the senior OGI camera operator counsel the auditee on
the reasons for the failure and how to improve surveying techniques.
However, if an auditee fails two consecutive audits, the auditee will
have to complete the initial training again. The EPA is also proposing
to reduce the amount of training required for OGI operators who have
been inoperative for an extended period from the initial training
requirements to the retraining requirements.
Finally, the EPA is proposing to allow previous OGI experience to
substitute for some of the initial training requirements within
appendix K in order to recognize the experience of current OGI camera
operators. Specifically, OGI camera operators with previous classroom
training (either at a physical location or online) that covers the
majority of the elements required by the initial classroom training
required in appendix K prior to the finalization of appendix K will not
need to complete the initial classroom training, but if the date of
training is more than 2 years before the date that the appendix is
finalized, the OGI camera operator will need to complete the biennial
classroom training in lieu of the initial classroom training. Also, OGI
camera operators who have 40 hours of experience over the 12 calendar
months prior to the date that appendix K is finalized may substitute
the retraining requirements, including the final monitoring survey
test, for the initial field training requirements.
3. Senior OGI Camera Operator
The EPA proposed that a senior OGI camera operator is a camera
operator who has conducted a minimum of 500 site surveys over their
career, including at least 20 site surveys in the past year, and who
has taken or developed the initial classroom training. Commenters were
concerned that there may be a lack of available senior OGI camera
operators, especially in the period right after finalization of
appendix K.\319\ Commenters also stated that the definition is too
restrictive, and some were concerned there is no certification
program.\320\ Some commenters also recommended that senior OGI
operators should be removed from the auditing process since they are
auditing and training others.\321\
---------------------------------------------------------------------------
\319\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0599, EPA-HQ-
OAR-2021-0317-0750, EPA-HQ-OAR-2021-0317-0782, and EPA-HQ-OAR-2021-
0317-0831.
\320\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0599, EPA-HQ-
OAR-2021-0317-0561, EPA-HQ-OAR-2021-0317-0608, EPA-HQ-OAR-2021-0317-
0718, EPA-HQ-OAR-2021-0317-0750, EPA-HQ-OAR-2021-0317-0802, and EPA-
HQ-OAR-2021-0317-0808.
\321\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0749, and EPA-
HQ-OAR-2021-0317-0808.
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The EPA is proposing to change the definition of senior OGI camera
operator to someone with 1400 survey hours over their career, including
40 hours in the past year. The 1400 survey hours is consistent with the
level that experienced operators had during the studies on operator
experience performed at the Methane Emissions Technology Evaluation
Center (METEC) test site.\322\ The study clearly showed a delineation
of the detection capabilities of high experienced operators, with the
high experienced operators detecting about 67 percent more leaks than
other operators. The experience of the group of operators considered to
be high experienced operators began at around 700 sites surveyed. The
background
[[Page 74839]]
document for the METEC study estimated experience at about four sites
per day, which equates to about two hours per site. Therefore, based on
the data used in the study, 700 sites should equate to about 1400 hours
on average. Additionally, the EPA is clarifying that the hours spent by
the senior OGI camera operator performing comparative monitoring,
either as part of initial training, retraining, or auditing other OGI
camera operators, can be included when determining the senior OGI
camera operator's experience both over their career and the past 12
months.
---------------------------------------------------------------------------
\322\ See Document ID No. EPA-HQ-OAR-2021-0317-0076.
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4. Dwell Time
The EPA proposed that during a survey, OGI camera operators should
view equipment from multiple angles. For each angle, the dwell time,
the active time the operator is looking for potential leaks when the
scene is in focus and steady, would need to be a minimum of 5 seconds
per component in the field of view. Some commenters stated that there
is no need to specify a dwell time, while other commenters said that
the dwell time should be shorter.\323\ Still other commenters stated
that the dwell time requirement should be based on the scene and not on
a per component basis.\324\
---------------------------------------------------------------------------
\323\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0570, EPA-HQ-
OAR-2021-0317-0599, EPA-HQ-OAR-2021-0317-0463, EPA-HQ-OAR-2021-0317-
0608, EPA-HQ-OAR-2021-0317-0718, EPA-HQ-OAR-2021-0317-0782, EPA-HQ-
OAR-2021-0317-0816, EPA-HQ-OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-
0831, EPA-HQ-OAR-2021-0317-0916, and EPA-HQ-OAR-2021-0317-0954.
\324\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0561, EPA-HQ-
OAR-2021-0317-0816, and EPA-HQ-OAR-2021-0317-0954.
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The EPA is proposing to change the dwell time per angle to two
seconds per component in the field of view. This aligns closely with
the estimated time to complete a monitoring survey in the analysis
performed for onshore natural gas processing plants for the proposed
NSPS OOOOb.\325\ The EPA based that analysis on data provided by OGI
camera operators. The EPA believes that two seconds per component would
provide enough time to determine whether a leak is present, and it is
expected that a trained OGI camera operator would be aware of
situations that necessitate dwelling longer than the minimum required
time.
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\325\ See Chapter 10 of the November 2021 TSD at Document ID No.
EPA-HQ-OAR-2021-0317-0166.
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5. Other Changes
The EPA proposed that OGI camera operators must take 5-minute rest
breaks after 20 minutes of continuous surveying. This proposed
requirement is the same as the requirement for opacity observations in
EPA Method 9 of 40 CFR part 60 appendix A-4. Commenters were divided
over this requirement. Some commenters agreed with the principal of
rest breaks while requesting additional flexibility or longer surveying
times between breaks. Others felt it was unnecessary to mandate rest
breaks.\326\ Rest breaks are an appropriate requirement for OGI camera
operators because physical, mental, and eye fatigue are concerns with
continuous field operation of OGI cameras. The EPA is proposing to
update the requirement for rest breaks to once every 30 minutes, as one
commenter \327\ noted that this makes tracking breaks easier. The EPA
does not believe that changing the continuous survey period from 20
minutes to 30 minutes will have a detrimental effect on an operator's
ability to see leaks, and as such, is proposing to update the
requirement to ease the burden on operators performing surveys. The EPA
is not proposing a change in the length of the rest break. No comments
were received on the specific length of the rest break. The EPA also
notes that operators may perform tasks related to the survey, such as
documentation, during rest breaks; the rest break is solely a break
from actively imaging components.
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\326\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0561, EPA-HQ-
OAR-2021-0317-0599, EPA-HQ-OAR-2021-0317-0608, EPA-HQ-OAR-2021-0317-
0718, EPA-HQ-OAR-2021-0317-0749, EPA-HQ-OAR-2021-0317-0750, EPA-HQ-
OAR-2021-0317-0782, EPA-HQ-OAR-2021-0317-0793, EPA-HQ-OAR-2021-0317-
0808, EPA-HQ-OAR-2021-0317-0814, EPA-HQ-OAR-2021-0317-0816, EPA-HQ-
OAR-2021-0317-0954, and EPA-HQ-OAR-2021-0317-1373.
\327\ See Document ID No. EPA-HQ-OAR-2021-0317-0561.
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The EPA proposed that OGI cameras must be capable of imaging
methane emissions of 17 grams per hour(g/hr) and butane emissions of
18.5 g/hr at a viewing distance of 2 meters and a delta-T of 5 [deg]C
in an environment of calm wind conditions. Commenters stated that gases
other than butane should be used for certification of cameras.\328\
Additionally, some commenters stated that the emission rates in the
camera certification should be the same as in NSPS OOOOa.\329\ While
the EPA does not agree that the camera certification should be the same
as what is in NSPS OOOOa because we have learned more about the
detection capabilities of OGI cameras since that time, we are proposing
to change the butane requirement to a choice between propane or butane
and noting that referencing subparts may provide specifications for
other gases. The EPA is also clarifying that the initial certification
testing, as well as the operating window development testing, can be
performed by the owner or operator, the camera manufacturer, or a third
party.
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\328\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0599 and EPA-HQ-
OAR-2021-0317-0808.
\329\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0782 and EPA-HQ-
OAR-2021-0317-0808.
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The EPA proposed that the response factors used when determining
whether an OGI camera would be able to image the components in gaseous
emissions would need to come from peer reviewed publications.
Commenters requested that the EPA develop guidance on how to develop
response factors and stated that the response factors should be able to
be developed by manufacturers without the requirement for peer reviewed
publication.\330\ The EPA agrees with these comments, and as such, is
proposing to remove the requirement for peer reviewed publications.
Guidance for developing response factors is being provided as annex 1
to appendix K.
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\330\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0808 and EPA-HQ-
OAR-2021-0317-0831.
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The EPA proposed that when a leak is found with OGI, the OGI camera
operator must take a video clip of the leak. As requested by
commenters, this requirement is being updated to allow a photograph of
leaks as an option in lieu of video clips.\331\ Additionally, as
requested by a commenter, the EPA is proposing to allow the option for
full videos of the surveys to be retained in lieu of video clips of
leaks.\332\
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\331\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0463, EPA-HQ-
OAR-2021-0317-0599, EPA-HQ-OAR-2021-0317-0808, EPA-HQ-OAR-2021-0317-
0814 and EPA-HQ-OAR-2021-0317-1373.
\332\ See Document ID No. EPA-HQ-OAR-2021-0317-0816.
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The EPA is proposing to add a definition of monitoring survey,
which means imaging equipment with an OGI camera at one site on one
day. Changing site location or changing the day of imaging would
constitute a new monitoring survey. This definition is needed to help
clarify some of the requirements related to recordkeeping for
monitoring surveys.
Finally, the EPA is also making a number of other clarifications
and minor edits based on comments received during the November 2021
proposal.
C. Summary of Proposed Requirements
In this action, the EPA is proposing a protocol for the use of OGI
as appendix K. As part of the development of appendix K, the EPA
conducted an extensive literature review on the technology development
as well as
[[Page 74840]]
observations on current application of OGI technology. Approximately
150 references identify the technology, applications, and limitations
of OGI. The EPA also commissioned multiple laboratory studies and OGI
technology evaluations. Additionally, on November 9 and 10, 2020, the
EPA held a virtual stakeholder workshop to gather input on development
of a protocol for the use of OGI. The information obtained from these
efforts was used to develop the TSD for appendix K, which provides
technical analyses, experimental results, and other supplemental
information used to evaluate and develop standardized procedures for
the use of OGI technology in monitoring for fugitive emissions of VOCs,
HAP, and methane from industrial environments.\333\
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\333\ See Document ID No. EPA-HQ-OAR-2021-0317-0079.
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The EPA notes that while this protocol is being proposed for use at
onshore natural gas processing plants in this action at the proposed 40
CFR 60.5400b and 40 CFR 60.5400c, the applicability of the protocol is
broader. The protocol is applicable to facilities when specified in a
referencing subpart to help determine the presence and location of
leaks; it is not currently applicable for use in direct emission rate
measurements from sources. The protocol may be applied, when
referenced, to surveys of process equipment using OGI cameras where the
majority of compounds (>75 percent by weight) in the emissions streams
have a response factor of at least 0.25 when compared to the response
factor of propane. The OGI camera must also be capable of detecting (or
producing a detectable image of) methane emissions of 17 g/hr and
either butane emissions of 5.0 g/hr or propane emissions of 18 g/hr at
a viewing distance of 2 meters and a delta-T of 5 [deg]C in an
environment of calm wind conditions around 1 meter per second or less.
Verification that the OGI camera meets these criteria may be performed
by the owner or operator, the camera manufacturer, or a third party.
The supplies necessary for conducting the verification are described in
section 6.2 of the proposed appendix.
Field conditions, such as the viewing distance to the component to
be monitored, wind speed, ambient air temperature, and the background
temperature, have the potential to impact the ability of the OGI camera
operator to detect a leak. Because it is important that the OGI camera
has been tested under the full range of expected field conditions in
which the OGI camera will be used, an operating envelope must be
established for field use of the OGI camera. Imaging must not be
performed when the conditions are outside of the developed operating
envelope. Operating envelopes are specific to each model of OGI camera
and can be developed by the owner or operator, the camera manufacturer,
or a third party. To develop the operating envelope, methane gas is
released at a set mass rate and wind speed, viewing distance, and
delta-T (the temperature differential of the background and the
released gas) are all varied to determine the conditions under which a
leak can be imaged. For purposes of developing the operating envelope,
a leak is considered able to be imaged if three out of four observers
can see the leak. Once the operating envelope is developed using
methane, the testing is repeated with either butane or propane gas. The
operating envelope for the OGI camera is the more restrictive operating
envelope developed between the different test gases.
The operating envelope must be confirmed for all potential
configurations that could impact the detection limit of the OGI camera.
In response to the November 2021 proposal, several commenters suggested
that the operating envelope determination requirements should be
streamlined. For example, if a configuration is established and
confirmed, another configuration that is inherently more sensitive
should be allowed without additional testing. Commenters also requested
a more defined and acceptable list of configurations be provided based
on the technology's capabilities, not user preferences.\334\ The EPA
does not currently have enough data or empirical evidence to provide a
complete list of possible configurations for all the available
commercial OGI cameras (taking into account future possible
configurations) or a definitive ranking of which configurations are
more stringent than other. The EPA is requesting comment on this topic
and seeking any empirical data that could be used to create such a
defined ranking of configurations. Additionally, one commenter
suggested that instead of having different operating envelopes for
different situations and having to decide which envelope to use, the
OGI camera operator should conduct a daily camera demonstration each
day prior to imaging to determine the maximum distance at which the OGI
camera operator should image for that day.\335\ The EPA believes that
this type of determination would be more difficult and costly than
creating an operating envelope, as it would require OGI camera
operators to have necessary gas supplies on hand and take time to do
this determination daily, or potentially multiple times a day.
Nevertheless, the EPA is requesting comment on this suggestion, as well
as how such a demonstration could be used if conditions on the site
change throughout the day, at what point would the changed conditions
necessitate repeating the demonstration, and how changes in the
background in different areas of the site (such as to affect the delta-
T) would be factored into such a demonstration.
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\334\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0604 and EPA-HQ-
OAR-2021-0317-0954.
\335\ See Document ID No. EPA-HQ-OAR-2021-0317-0561.
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The EPA is proposing that each site would have a monitoring plan
that describes the procedures for conducting a monitoring survey. One
monitoring plan can be used for multiple sites, as long as the plan
contains the relevant information for each site. The monitoring plan
must contain procedures for a daily verification check, ensuring that
the monitoring survey is performed only when conditions in the field
are within the operating envelope, monitoring all the components
regulated by the referencing subpart within the unit or area, viewing
the components with the camera, operator rest breaks, documenting
surveys, and quality assurance.
Delta-T is a crucial variable in determining whether it is possible
to see a leak. Without an adequate delta-T, it will be difficult, or
even impossible to see a leak, no matter how big the leak is. The EPA
is proposing that the monitoring plan must describe how the operator
will ensure an adequate delta-T is present in order to view potential
gaseous emissions, e.g., using a delta-T check function built into the
features of the OGI camera or using a background temperature reading in
the OGI camera field of view. In response to the November 2021
proposal, a commenter stated guidance should be added for operators who
are using a background temperature reading in the OGI camera field of
view.\336\ The EPA is requesting comment on ways that an OGI camera
operator can ensure an adequate delta-T exists during monitoring
surveys for cameras that do not have a built-in delta-T check function.
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\336\ See Document ID No. EPA-HQ-OAR-2021-0317-0719.
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The EPA is proposing that a component must be imaged from at least
[[Page 74841]]
two different angles, and the OGI camera operator must dwell on each
angle for a minimum of 2 seconds per component in the field of view,
where dwell time is defined as the time the scene is steady and in
focus and the operator is actively viewing the scene. The operator may
reduce the dwell time for complex scenes based on the monitoring area
and number of components in the subsection as prescribed in Table 14-1
of the appendix; use of this table is only required when an operator
wants to reduce the dwell time from the minimum 2 second per component
dwell time. In response to the November 2021 proposal, commenters
suggested that dwell time should be based on the scene, not on a per
component basis. Additionally, commenters suggested further defining
the scene as ``simple'' or ``complex'' with a greater dwell time for
``complex'' scenes.\337\ The EPA is concerned with creating blanket
dwell times for scenes, as scenes can vary in complexity within these
categories, and an operator would need to look at scenes with more
components longer than a scene with fewer components. Additionally, the
EPA does not believe it is possible to describe every possible scene in
order to create bins for ``simple'' and ``complex'' scenes that would
be inclusive of all scenes an OGI camera operator might encounter in
the field. However, the EPA is soliciting comment on how dwell time
could be based on the scene while still accounting for the differences
in the complexity of scenes or ways to create bins for ``simple'' and
``complex'' scenes. The EPA is also soliciting comment on ways to
similarly achieve the goal of ensuring that OGI camera operators survey
a scene for an adequate amount of time to ensure there are no leaks
from any components in the field of view without specifying a dwell
time.
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\337\ See Document ID Nos. EPA-HQ-OAR-2021-0317-0561, EPA-HQ-
OAR-2021-0317-0604, EPA-HQ-OAR-2021-0317-0816, and EPA-HQ-OAR-2021-
0317-0954.
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Physical, mental, and eye fatigue are concerns with continuous
field operation of OGI cameras. The EPA is proposing that OGI camera
operators must take a rest break after surveying continuously for a
period of 30 minutes. In response to the November 2021 proposal,
commenters suggested that this was an unnecessary requirement. The EPA
is aware that continuously surveying for long periods can lead to
decreased detection of leaks. However, the EPA has heard anecdotally
that this may have more to do with the number of hours the OGI camera
operator has surveyed during the day, such that it is more appropriate
to limit the hours of surveying per day than it is to mandate rest
breaks at a set frequency. The EPA is seeking any empirical data on the
topic of the necessity of rest breaks when conducting OGI surveys or
the link between operator performance and length of survey period.
The EPA is proposing that the facility or company performing the
OGI surveys must have a training plan which ensures and monitors the
proficiency of the OGI camera operators. If the facility does not
perform its own OGI monitoring, the facility must ensure that the
training plan for the company performing the OGI surveys adheres to
this requirement. The proposed appendix K prescribes a multi-faceted
approach to training. Training includes classroom instruction (either
online or at a physical location) both initially and biennially on the
OGI camera and external devices, monitoring techniques, best practices,
process knowledge, and other regulatory requirements related to leak
detection that are relevant to the facility's OGI monitoring efforts.
Prior to conducting monitoring surveys, camera operators must
demonstrate proficiency with the OGI camera. The initial field training
includes a minimum of 30 survey hours with OGI where trainees first
observe the techniques and methods of a senior OGI camera operator and
then eventually perform monitoring surveys independently with a senior
OGI camera operator present to provide oversight. The trainee must then
pass a final monitoring survey test of at least two hours. If there are
10 or more leaks identified by the senior OGI operator, the trainee
must achieve less than 10 percent missed persistent leaks relative to
the senior OGI camera operator to be considered authorized for
independent survey execution. If there are less than 10 leaks
identified by the senior OGI operator, the trainee must achieve zero
missed persistent leaks relative to the senior OGI camera operator to
be considered authorized for independent survey execution. If the
trainee doesn't pass the monitoring survey test, the senior OGI camera
operator must discuss the reasons for the failure with the trainee and
provide instruction/correction on improving the trainee's performance,
following which the trainee may repeat the final test.
The EPA is proposing that performance audits for all OGI camera
operators must occur on a quarterly basis and can be conducted either
by comparative monitoring or video review by a senior OGI camera
operator. If the senior OGI camera operator finds that the survey
techniques during the video review do not match those described in the
monitoring plan, then the camera operator being audited will need to be
retrained. Additionally, if there are 10 or more leaks identified by
the senior OGI operator, the camera operator being audited must achieve
less than 10 percent missed persistent leaks relative to the senior OGI
camera operator. If there are less than 10 leaks identified by the
senior OGI operator, the camera operator being audited must achieve
zero missed persistent leaks relative to the senior OGI camera
operator. Retraining consists of a discussion of the reasons for the
failure with the OGI operator being audited and techniques to improve
performance; a minimum of 16 survey training hours; and a final
monitoring survey test. If an OGI operator requires retraining in two
consecutive quarterly audits, the OGI operator must repeat the initial
training requirements. In response to the November 2021 proposal,
commenters stated that there should be no performance audit
requirements for senior OGI camera operators because senior OGI camera
operators are responsible for training and auditing other OGI camera
operators. The EPA believes that it is important to verify the
performance of all OGI camera operators, even the most experienced
operators, on an ongoing basis. Nevertheless, the EPA is requesting
comment on whether there should be a reduced performance audit
frequency for certain OGI camera operators, and if so, who should
qualify for a reduced frequency, what the reduced frequency should be,
and the basis for the reduced frequency.
Previous experience with OGI camera operation can be substituted
for some of the initial training requirements. OGI camera operators
with previous classroom training (either at a physical location or
online) that covers the majority of the elements required by the
initial classroom training required in appendix K prior to the
finalization of appendix K do not need to complete the initial
classroom training, but if the date of certification is more than 2
years before the publication date of the final rule, the biennial
classroom training must be completed in lieu of the initial classroom
training. OGI camera operators who have 40 hours of experience over the
12 calendar months prior to the date of publication of the final rule
may substitute the retraining requirements, including the final
monitoring survey test, for the initial field training requirements.
Recordkeeping is an important compliance assurance measure. The
proposed appendix K requires records
[[Page 74842]]
to be retained in hard copy or electronic form. Records include the
site monitoring plan, operating envelope limitations, data supporting
the initial OGI camera performance verification and development of the
operating envelope, the training plan for OGI camera operators, OGI
camera operator training and auditing records, records necessary to
verify senior OGI camera operator status, monitoring survey records,
quality assurance verification videos for each operator, and
maintenance and calibration records. Some of the records required by
the proposed appendix K are not required to be kept onsite as long as
the owner or operator can easily access these records and can make the
records available for review if requested by the Administrator.
VII. Impacts of This Proposed Rule
A. What are the air impacts?
The EPA projected that, from 2023 to 2035, relative to the
baseline, the proposed NSPS OOOOb and EG OOOOc will reduce about 36
million short tons of methane emissions (810 million tons
CO2 Eq.), 9.7 million short tons of VOC emissions, and 390
thousand short tons of HAP emission from facilities that are
potentially affected by this proposal. The EPA projected regulatory
impacts beginning in 2023 as that year represents the first full year
of implementation of the proposed NSPS OOOOb. The EPA assumes that
emissions impacts of the proposed EG OOOOc will begin in 2026. The EPA
projected impacts through 2035 to illustrate the accumulating effects
of this rule over a longer period. The EPA did not estimate impacts
after 2035 for reasons including limited information, as explained in
the RIA, though the EPA is soliciting comment on whether information
exists to better characterize the likely effects beyond 2035.
As noted in section I of this preamble, the updated analysis not
only incorporates the new provisions put forth in the supplemental
proposal (in addition to the elements of the November 2021 proposal
that are unchanged), but also includes key updates to assumptions and
methodologies that impact both the baseline and policy scenarios.
Accordingly, these estimates of air impacts are not directly comparable
to corresponding estimates presented in the November 2021 proposal.
B. What are the energy impacts?
The energy impacts described in this section are those energy
requirements associated with the operation of emission control devices.
Potential impacts on the national energy economy from the rule are
discussed in the economic impacts section in VIII.D of this preamble.
There will likely be minimal change in emissions control energy
requirements resulting from this rule. Additionally, this proposed
action continues to encourage the use of emission controls that recover
hydrocarbon products that can be used on-site as fuel or reprocessed
within the production process for sale.
C. What are the compliance costs?
The equivalent annualized value, or EAV, of the regulatory
compliance cost associated with the proposed NSPS OOOOb and EG OOOOc
over the 2023 to 2035 period was estimated to be $1.4 billion per year
using a 3-percent discount rate and $1.4 billion using a 7-percent
discount rate. The corresponding estimates of the present value (PV) of
compliance costs were $14 billion (in 2019 dollars) using a 3-percent
discount rate and $12 billion using a 7-percent discount rate. These
estimates include the producer revenues associated with the projected
increase in the recovery of saleable natural gas, using the 2022 Annual
Energy Outlook (AEO) projection of natural gas prices to estimate the
value of the change in the recovered gas at the wellhead projected to
result from the proposed action. Estimates of the value of the
recovered product have been included in previous regulatory analyses as
offsetting compliance costs and are appropriate to include when
assessing the societal cost of a regulation. If the recovery of
saleable natural gas is not accounted for, the EAV of the regulatory
compliance costs of the proposed rule over the 2023 to 2035 period were
estimated to be $1.8 billion per year using a 3-percent discount rate
and $1.8 billion per year using a 7-percent discount rate. The PV of
these costs were estimated to be $19 billion using a 3-percent discount
rate and $15 billion using a 7-percent discount rate.
D. What are the economic and employment impacts?
The EPA conducted an economic impact and distributional analysis
for this proposal, as detailed in section 4 of the RIA for this
supplemental proposal. To provide a partial measure of the economic
consequences of the proposed NSPS OOOOb and EG OOOOc, the EPA developed
a pair of single-market, static partial-equilibrium analyses of
national crude oil and natural gas markets. We implemented the pair of
single-market analyses instead of a coupled market or general
equilibrium approach to provide broad insights into potential national-
level market impacts while providing maximum analytical transparency.
We estimated the price and quantity impacts of the proposed NSPS OOOOb
and EG OOOOc on crude oil and natural gas markets for a subset of years
within the time horizon analyzed in the RIA. The models are
parameterized using production and price data from the U.S. Energy
Information Administration and supply and demand elasticity estimates
from the economics literature.
The RIA projects that regulatory costs are at their highest in
2026, the first year the requirements of both the proposed NSPS OOOOb
and EG OOOOc are assumed to be in effect and will represent the year
with the largest market impacts based upon the partial equilibrium
modeling. We estimated that the proposed rule could result in a maximum
decrease in annual natural gas production of about 358 million Mcf in
2026 (or about 1.00 percent of natural gas production) with a maximum
price increase of $0.07 per Mcf (or about 2.35 percent). We estimated
the maximum annual reduction in crude oil production would be about 21
million barrels (or about 0.52 percent of crude oil production) with a
maximum price increase of about $0.10 per barrel (or less than 0.16
percent).
Before 2026, the modeled market impacts are much smaller than the
2026 impacts as only the incremental requirements under the proposed
NSPS OOOOb are assumed to be in effect. As regulatory costs are
projected to decline after 2026, the modelled market impacts for years
after 2026 are smaller than the peaks estimated for 2026. Please see
section 4.1 of the RIA for more detail on the formulation and
implementation of the model as well as a discussion of several
important caveats and limitations associated with the approach.
As discussed in the RIA for this proposal, employment impacts of
environmental regulations are generally composed of a mix of potential
declines and gains in different areas of the economy over time.
Regulatory employment impacts can vary across occupations, regions, and
industries; by labor and product demand and supply elasticities; and in
response to other labor market conditions. Isolating such impacts is a
challenge, as they are difficult to disentangle from employment impacts
caused by a wide variety of ongoing, concurrent economic changes.
The oil and natural gas industry directly employs approximately
140,000 people in oil and natural gas extraction, a figure which varies
with market prices
[[Page 74843]]
and technological change and employs a large number of workers in
related sectors that provide materials and services.\338\ As indicated
above, the proposed NSPS OOOOb and EG OOOOc are projected to cause
small changes in oil and natural gas production and prices. As a
result, demand for labor employed in oil and natural gas-related
activities and associated industries might experience adjustments as
there may be increases in compliance-related labor requirements as well
as changes in employment due to quantity effects in directly regulated
sectors and sectors that consume oil and natural gas products.
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\338\ Employment figure drawn from the Bureau of Labor
Statistics Current Employment Statistics for NAICS code 211.
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E. What are the benefits of the proposed standards?
To satisfy the requirement of E.O. 12866 and to inform the public,
the EPA estimated the climate and health benefits due to the emissions
reductions projected under the proposed NSPS OOOOb and EG OOOOc. The
EPA expects climate and health benefits due to the emissions reductions
projected under the proposed NSPS OOOOb and EG OOOOc. The EPA estimated
the climate benefits of CH4 emission reductions expected
from this proposed rule using the SC-CH4 estimates presented
in the ``Technical Support Document: Social Cost of Carbon, Methane,
and Nitrous Oxide Interim Estimates under E.O. 13990 (IWG 2021)''
published in February 2021 by the Interagency Working Group on the
Social Cost of Greenhouse Gases (IWG). The SC-CH4 is the
monetary value of the net harm to society associated with a marginal
increase in emissions in a given year, or the benefit of avoiding that
increase. In principle, SC-CH4 includes the value of all
climate change impacts, including (but not limited to) changes in net
agricultural productivity, human health effects, property damage from
increased flood risk and natural disasters, disruption of energy
systems, risk of conflict, environmental migration, and the value of
ecosystem services. The SC-CH4 therefore, reflects the
societal value of reducing emissions of the gas in question by one
metric ton and is the theoretically appropriate value to use in
conducting benefit-cost analyses of policies that affect CH4
emissions.
The interim estimates of the social cost of methane and other
greenhouse gases (collectively referred to as the social cost of
greenhouse gases (SC-GHG)) presented in the February 2021 Technical
Support Document (TSD) (IWG 2021) were developed over many years, using
a transparent process, peer-reviewed methodologies, the best science
available at the time of that process, and with input from the public.
As a member of the IWG involved in the development of the February 2021
TSD, the EPA agrees that the interim SC-GHG estimates continue to
represent at this time the most appropriate estimate of the SC-GHG
until revised estimates have been developed reflecting the latest,
peer-reviewed science. However, while the IWG's SC-GHG work under E.O.
13990 continues, the RIA accompanying this proposal the EPA presents a
sensitivity analysis of the monetized climate benefits using a set of
SC-CH4 estimates that incorporates recent research
addressing recommendations of the National Academies of Sciences,
Engineering, and Medicine (2017).
We invite the public to comment on both the sensitivity analysis of
the monetized climate benefits and the accompanying external review
draft technical report that the EPA has prepared that explains the
methodology underlying the newer set of SC-CH4 estimates.
This report is also included as supporting material for the RIA in the
docket.\339\ However, we emphasize that the monetized benefits analysis
is entirely distinct from the statutory BSER determinations proposed
herein and is presented solely for the purposes of complying with E.O.
12866. As discussed in more detail in the November 2021 proposal and
earlier in this notice, the EPA weighed the relevant statutory factors
to determine the appropriate proposed standards and did not rely on the
monetized benefits analysis for purposes of determining the standards.
E.O. 12866 separately requires the EPA to perform a benefit-cost
analysis, including monetizing costs and benefits where practicable,
and the EPA has conducted such an analysis. The monetized climate
benefits calculated using the SC-CH4 are included in the
benefit-cost analysis, and thus, as is generally the case with any
analytical methods, data, or results associated with RIAs, the EPA
welcomes the opportunity to continually improve its understanding
through public input on these estimates.
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\339\ For more information about the development of these
estimates, see www.epa.gov/environmental-economics/scghg.
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The EPA estimated the PV of the climate benefits over the 2023 to
2035 period to be $48 billion at a 3-percent discount rate. The EAV of
these benefits is estimated to be $4.5 billion per year at a 3-percent
discount rate. These values represent only a partial accounting of
climate impacts from methane emissions and do not account for health
effects of ozone exposure from the increase in methane emissions.
Under the proposed NSPS OOOOb and EG OOOOc, the EPA expects that
VOC emission reductions will improve air quality and are likely to
improve health and welfare associated with exposure to ozone,
PM2.5, and HAP. Calculating ozone impacts from VOC emissions
changes requires information about the spatial patterns in those
emissions changes. In addition, the ozone health effects from the
proposed rule will depend on the relative proximity of expected VOC and
ozone changes to population. In this analysis, we have not
characterized VOC emissions changes at a finer spatial resolution than
the national total. In light of these uncertainties, we present an
illustrative screening analysis in Appendix C of the RIA based on
modeled oil and natural gas VOC contributions to ozone concentrations
as they occurred in 2017 and do not include the results of this
analysis in the estimate of benefits and net benefits projected from
this proposal.
VIII. Statutory and Executive Order Reviews
Additional information about these statutes and EOs can be found at
https://www.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This proposed action is an economically significant regulatory
action that was submitted to the OMB for review. Any changes made in
response to OMB recommendations have been documented in the docket. The
EPA prepared an analysis of the potential costs and benefits associated
with this action. This analysis, ``Regulatory Impact Analysis of the
Supplemental Proposal for the Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review'', is
available in the docket and describes in detail the EPA's assumptions
and characterizes the various sources of uncertainties affecting the
estimates.
B. Paperwork Reduction Act (PRA)
The information collection activities in the proposed amendments
for 40 CFR part 60, subparts OOOOb and OOOOc,
[[Page 74844]]
have been submitted for approval to the OMB under the PRA. The ICR
document that the EPA prepared has been assigned OMB Control No. 2060-
0721 and EPA ICR number 2523.05. You can find a copy of the ICR in the
docket for this rule, and it is briefly summarized here. As noted in
section IV.N of this supplemental preamble, draft versions of the
proposed templates for the semiannual and annual reports for these
subparts are included in the docket for this action,\340\ and the EPA
specifically requests comment on the content, layout, and overall
design of the templates.
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\340\ See Part_60_Subpart_OOOOb_60.5420b(b)_Annual_Report.xlsm
and Part_60_Subpart_OOOOb_60.5422b(b)_Semiannual_Report.xlsx,
available in the docket for this action.
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40 CFR Part 60, Subpart OOOOb
This ICR reflects the EPA's proposed NSPS OOOOb for a wide range of
emissions sources in the Crude Oil and Natural Gas source category. The
information collected will be used by the EPA and delegated state and
local agencies to determine the compliance status of affected
facilities subject to the rule.
Respondents/affected entities: Oil and natural gas operators and
owners; approved third-party notifiers.
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: 1,849.
Frequency of response: Varies depending on affected facility.\341\
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\341\ The specific frequency for each information collection
activity within this request is shown in Tables 1a through 1d of the
Supporting Statement in the public docket.
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Total estimated burden: 883,625 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $58,535,262($2019) (per year), which includes
$12,182,846 in capital costs.
40 CFR Part 60, subpart OOOOc
This rule does not directly impose specific requirements on oil and
natural gas facilities located in states or areas of Indian country.
The rule also does not impose specific requirements on tribal
governments that have affected facilities located in their area of
Indian country. This rule does impose specific requirements on state
governments with affected oil and natural gas facilities. The
information collection requirements are based on the recordkeeping and
reporting burden associated with developing, implementing, and
enforcing a plan to limit GHG emissions from existing sources in the
oil and natural gas sector. These recordkeeping and reporting
requirements are specifically authorized by CAA section 114 (42 U.S.C.
7414). All information submitted to the EPA pursuant to the
recordkeeping and reporting requirements for which a claim of
confidentiality is made is safeguarded according to Agency policies set
forth in 40 CFR part 2, subpart B.
The annual burden for this collection of information for the states
(averaged over the first 3 years following promulgation) is estimated
to range from 55,467 to 69,333 hours at a total annual labor cost of
between $7 to $8.8 million. The annual burden for the Federal
government associated with the state collection of information
(averaged over the first 3 years following promulgation) is estimated
to be 22,520 hours at a total annual labor cost of $1,399,930. The
annual burden for industry (averaged over the first 3 years following
promulgation) is estimated to be 2.2 million hours at a total annual
labor cost of $166 million. We realize, however, that some facilities
may not incur these costs within the first 3 years and may incur them
during the fourth or fifth year instead. Therefore, this ICR presents a
conservatively high burden estimate for the initial 3 years following
promulgation of the proposed emission guidelines. Burden is defined at
5 CFR 1320.3(b).
Respondents/affected entities: States with one or more designated
facilities covered under subpart OOOOc.
Respondent's obligation to respond: Mandatory.
Estimated number of respondents: 50.
Frequency of response: Once.
Total estimated burden: 69,333 hours (per year). Burden is defined
at 5 CFR 1320.3(b).
Total estimated cost: $8,822,020 (per year), which includes $36,750
in capital costs.
An Agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9. Submit your
comments on the Agency's need for this information, the accuracy of the
provided burden estimates and any suggested methods for minimizing
respondent burden to the EPA using the docket identified at the
beginning of this rule. The EPA will respond to any ICR-related
comments in the final rule. Written comments and recommendations for
the proposed information collection should be sent within 30 days of
publication of this notice to www.reginfo.gov/public/do/PRAMain. Find
this particular information collection by selecting ``Currently under
30-day Review--Open for Public Comments'' or by using the search
function. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after receipt, OMB must receive comments no
later than January 5, 2023.
C. Regulatory Flexibility Act (RFA)
Pursuant to section 603 of the RFA, the EPA prepared an initial
regulatory flexibility analysis (IRFA) that examined the impact of the
proposed rule on small entities along with regulatory alternatives that
could minimize that impact. The complete IRFA is available for review
in the RIA (see Section 4.3) and the EPA is soliciting comment on the
presentation of its analysis of the impacts on small entities,
particularly if there is value in presenting more granular information
beyond a focus on entities above and below the SBA size
classifications.
As required by section 609(b) of the RFA, the EPA also convened a
Small Business Advocacy Review (SBAR) Panel to obtain advice and
recommendations from small entity representatives that potentially
would be subject to the rule's requirements. The SBAR Panel evaluated
the assembled materials and small-entity comments on issues related to
elements of an IRFA. A copy of the full SBAR Panel Report is available
in the rulemaking docket.
As required by section 604 of the RFA, the EPA will prepare a final
regulatory flexibility analysis (FRFA) for this action as part of the
final rule. The FRFA will address the issues raised by public comments
on the IRFA.
D. Unfunded Mandates Reform Act (UMRA)
The NSPS contains a federal mandate under UMRA, 2 U.S.C. 1531-1538,
that may result in expenditures of $100 million or more for state,
tribal, and local governments, in the aggregate, or the private sector
in any one year. Accordingly, the EPA has prepared under section 202 of
the UMRA a written statement of the benefit-cost analysis, which can be
found in Section VII of this preamble, and in Chapter 1 of the RIA.
Consistent with section 205, the EPA has identified and considered
a reasonable number of regulatory alternatives. These alternatives are
described in Section IV of this preamble.
The EG is proposed under CAA section 111(d) and does not impose any
direct compliance requirements on designated facilities, apart from the
[[Page 74845]]
requirement for states to develop state plans. As explained in section
XIV.G. of the November 2021 proposal \342\ and section V of this
supplemental proposal, the EG also does not impose specific
requirements on tribal governments that have designated facilities
located in their area of Indian country. The burden for states to
develop state plans following promulgation of the rule is estimated to
be below $100 million in any one year. Thus, the EG is not subject to
the requirements of section 203 or section 205 of the UMRA.
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\342\ See 86 FR 63256 (November 15, 2021).
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The NSPS and EG are also not subject to the requirements of section
203 of UMRA because, as described in 2 U.S.C. 1531-38, they contain no
regulatory requirements that might significantly or uniquely affect
small governments. Specifically, for the EG the state governments to
which rule requirements apply are not considered small governments. In
light of the interest among governmental entities, the EPA conducted
pre-proposal outreach with national organizations representing states
and tribal governmental entities while formulating the proposed rule as
discussed in section VII of the November 2021 proposal.\343\ The EPA
considered the stakeholders' experiences and lessons learned to help
inform how to better structure this proposal and consider ongoing
challenges that will require continued collaboration with stakeholders.
With this proposal, the EPA seeks further input from states and tribes.
For public input to be considered during the formal rulemaking, please
submit comments on this proposed action to the formal regulatory docket
at EPA Docket ID No. EPA-HQ-OAR-2021-0317 so that the EPA may consider
those comments during the development of the final rule.
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\343\ See 86 FR 63145 (November 15, 2021).
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E. Executive Order 13132: Federalism
Under Executive Order 13132, the EPA may not issue an action that
has federalism implications, that imposes substantial direct compliance
costs, and that is not required by statute, unless the Federal
Government provides the funds necessary to pay the direct compliance
costs incurred by state and local governments, or the EPA consults with
state and local officials early in the process of developing the
proposed action.
The proposed NSPS OOOOb and proposed EG OOOOc do not have
federalism implications. These actions will not have substantial direct
effects on the states as defined in the Executive Order, on the
relationship between the Federal Government and the States, or on the
distribution of power and responsibilities among the various levels of
government.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action has tribal implications. However, it will neither
impose substantial direct compliance costs on Federally recognized
Tribal governments, nor preempt Tribal law, and does not have
substantial direct effects on the relationship between the Federal
Government and Indian Tribes or on the distribution of power and
responsibilities between the Federal Government and Indian Tribes, as
specified in E.O. 13175. See 65 FR 67249 (November 9, 2000). As stated
in the November 2021 proposal, the EPA found that 112 unique tribal
lands are located within 50 miles of an affected oil and natural gas
source, and 32 tribes have one or more oil or natural gas sources on
their lands.\344\ The majority of the designated facilities impacted by
proposed NSPS and EG on Tribal lands are owned by private entities, and
tribes will not be directly impacted by the compliance costs associated
with this rulemaking. There would only be tribal implications
associated with this rulemaking in the case where a unit is owned by a
Tribal government or in the case of the NSPS, a Tribal government is
given delegated authority to enforce the rulemaking. Tribes are not
required to develop plans to implement the EG under CAA section 111(d)
for designated existing sources. The EPA notes that this supplemental
proposal does not directly impose specific requirements on designated
facilities, including those located in Indian country. Before
developing any standards for sources on Tribal land, the EPA would
consult with leaders from affected tribes.
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\344\ 86 FR 63143 (November 15, 2021).
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After the November 2021 proposal, the EPA held consultation with
the Mandan, Hidatsa, and Arikara Nation (January 24, 2022), the
Northern Arapaho Tribe (January 24, 2022), and the Eastern Shoshone
Tribe (January 25, 2022).\345\ Consistent with previous actions
affecting the Crude Oil and Natural Gas source category, the EPA
understands there is continued significant tribal interest because of
the growth of the oil and natural gas production in Indian country. In
accordance with the EPA Policy on Consultation and Coordination with
Indian Tribes, the EPA will continue to engage in consultation with
tribal officials during the development of this supplemental proposal.
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\345\ See memorandums located at Docket ID No. EPA-HQ-OAR-2021-
0317.
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G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
This action is subject to E.O. 13045 (62 FR 19885; April 23, 1997)
because it is an economically significant regulatory action as defined
by E.O. 12866, and the EPA believes that the environmental health or
safety risk addressed by this action has a disproportionate effect on
children. Accordingly, the Agency has evaluated the environmental
health and welfare effects of climate change on children. GHGs,
including methane, contribute to climate change and are emitted in
significant quantities by the oil and gas industry. The EPA believes
that the GHG emission reductions resulting from implementation of these
proposed standards and guidelines, if finalized will further improve
children's health. The assessment literature cited in the EPA's 2009
Endangerment Findings concluded that certain populations and life
stages, including children, the elderly, and the poor, are most
vulnerable to climate-related health effects (74 FR 66524). The
assessment literature since 2009 strengthens these conclusions by
providing more detailed findings regarding these groups'
vulnerabilities and the projected impacts they may experience (e.g.,
the 2016 Climate and Health Assessment).\346\ These assessments
describe how children's unique physiological and developmental factors
contribute to making them particularly vulnerable to climate change.
Impacts to children are expected from heat waves, air pollution,
infectious and waterborne illnesses, and mental health effects
resulting from extreme weather events. In addition, children are among
those especially susceptible to most allergic diseases, as well as
health effects associated with heat waves, storms, and floods.
Additional health concerns may arise in low-income households,
especially those with children, if climate change reduces food
availability and increases prices, leading to food insecurity within
households. More
[[Page 74846]]
detailed information on the impacts of climate change to human health
and welfare is provided in sections III and VI of the November 2021
proposal \347\ and section VII of this preamble.
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\346\ USGCRP, 2016: The Impacts of Climate Change on Human
Health in the United States: A Scientific Assessment. Crimmins, A.,
J. Balbus, J.L. Gamble, C.B. Beard, J.E. Bell, D. Dodgen, R.J.
Eisen, N. Fann, M.D. Hawkins, S.C. Herring, L. Jantarasami, D.M.
Mills, S. Saha, M.C. Sarofim, J. Trtanj, and L. Ziska, Eds. U.S.
Global Change Research Program, Washington, DC, 312 pp. http://dx.doi.org/10.7930/J0R49NQX.
\347\ See 86 FR 63124 and 86 FR 63139 (November 15, 2021).
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H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
This action, which is a significant regulatory action under
Executive Order 12866, has a significant adverse effect on the supply,
distribution or use of energy. The documentation for this decision is
contained in the Regulatory Impact Analysis for the Proposed Standards
of Performance for New, Reconstructed, and Modified Sources and
Emissions Guidelines for Existing Sources: Oil and Natural Gas Sector
Climate Review prepared for the November 2021 proposal and the
Regulatory Impact Analysis of the Supplemental Proposal for the
Standards of Performance for New, Reconstructed, and Modified Sources
and Emissions Guidelines for Existing Sources: Oil and Natural Gas
Sector Climate Review for this action \348\
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\348\ See Document ID No. EPA-HQ-OAR-2021-0317-0173.
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I. National Technology Transfer and Advancement Act (NTTAA)
This proposed action for NSPS OOOOb and EG OOOOc involves technical
standards. Therefore, the EPA conducted searches for the Standards of
Performance for New, Reconstructed, and Modified Sources and Emissions
Guidelines for Existing Sources: Oil and Natural Gas Sector Climate
Review through the Enhanced National Standards Systems Network (NSSN)
Database managed by the American National Standards Institute (ANSI).
Searches were conducted for EPA Methods 1, 1A, 2, 2A, 2C, 2D, 3A, 3B,
3C, 4, 6, 10, 15, 16, 16A, 18, 21, 22, and 25A of 40 CFR part 60,
appendix A. No applicable voluntary consensus standards were identified
for EPA Methods 1A, 2A, 2D, 21, and 22 and none were brought to its
attention in comments. All potential standards were reviewed to
determine the practicality of the voluntary consensus standards (VCS)
for this rule. Two VCS were identified as an acceptable alternative to
EPA test methods for the purpose of this proposed rule. First, ANSI/
ASME PTC 19-10-1981, Flue and Exhaust Gas Analyses (Part 10) (manual
portions only and not the instrumental portion) was identified to be
used in lieu of EPA Methods 3B, 6, 6A, 6B, 15A and 16A. This standard
includes manual and instrumental methods of analysis for carbon
dioxide, carbon monoxide, hydrogen sulfide, nitrogen oxides, oxygen,
and sulfur dioxide. Second, ASTM D6420-99 (2010), ``Test Method for
Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography/Mass Spectrometry'' is an acceptable alternative to EPA
Method 18 with the following caveats, only use when the target
compounds are all known and the target compounds are all listed in ASTM
D6420 as measurable. ASTM D6420 should never be specified as a total
VOC Method. (ASTM D6420-99 (2010) is not incorporated by reference in
40 CFR part 60.) The search identified 19 VCS that were potentially
applicable for this proposed rule in lieu of EPA reference methods.
However, these have been determined to not be practical due to lack of
equivalency, documentation, validation of data and other important
technical and policy considerations. For additional information, please
see the September 10, 2021, memo titled, ``Voluntary Consensus Standard
Results for New, Reconstructed, and Modified Sources and Emissions
Guidelines for Existing Sources: Oil and Natural Gas Sector Climate
Review.'' \349\ In this document, the EPA is proposing to include in a
final rule regulatory text for 40 CFR part 60, subpart OOOOb and OOOOc
that includes incorporation by reference. In accordance with
requirements of 1 CFR part 51, the EPA is proposing to incorporate the
following ten standards by reference.
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\349\ See Document ID No. EPA-HQ-OAR-2021-0317-0072.
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ASTM D86-96, Distillation of Petroleum Products (Approved
April 10, 1996) covers the distillation of natural gasolines, motor
gasolines, aviation gasolines, aviation turbine fuels, special boiling
point spirits, naphthas, white spirit, kerosenes, gas oils, distillate
fuel oils, and similar petroleum products, utilizing either manual or
automated equipment.
ASTM D1945-03 (Reapproved 2010), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography covers the determination
of the chemical composition of natural gases and similar gaseous
mixtures within a certain range of composition. This test method may be
abbreviated for the analysis of lean natural gases containing
negligible amounts of hexanes and higher hydrocarbons, or for the
determination of one or more components.
ASTM D3588-98 (Reapproved 2003), Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuel covers procedures for calculating heating value, relative
density, and compressibility factor at base conditions for natural gas
mixtures from compositional analysis. It applies to all common types of
utility gaseous fuels.
ASTM D4891-89 (Reapproved 2006), Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion covers the determination of the heating value of natural
gases and similar gaseous mixtures within a certain range of
composition.
ASTM D6522-00 (Reapproved December 2005), Standard Test
Method for Determination of Nitrogen Oxides, Carbon Monoxide, and
Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating
Engines, Combustion Turbines, Boilers, and Process Heaters Using
Portable Analyzers covers the determination of nitrogen oxides, carbon
monoxide, and oxygen concentrations in controlled and uncontrolled
emissions from natural gas-fired reciprocating engines, combustion
turbines, boilers, and process heaters.
ASTM E168-92, General Techniques of Infrared Quantitative
Analysis covers the techniques most often used in infrared quantitative
analysis. Practices associated with the collection and analysis of data
on a computer are included as well as practices that do not use a
computer.
ASTM E169-93, General Techniques of Ultraviolet
Quantitative Analysis (Approved May 15, 1993) provide general
information on the techniques most often used in ultraviolet and
visible quantitative analysis. The purpose is to render unnecessary the
repetition of these descriptions of techniques in individual methods
for quantitative analysis.
ASTM E260-96, General Gas Chromatography Procedures
(Approved April 10, 1996) is a general guide to the application of gas
chromatography with packed columns for the separation and analysis of
vaporizable or gaseous organic and inorganic mixtures and as a
reference for the writing and reporting of gas chromatography methods.
ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses
[Part 10, Instruments and Apparatus] (Issued August 31, 1981) covers
measuring the oxygen or carbon dioxide content of the exhaust gas.
EPA-600/R-12/531, EPA Traceability Protocol for Assay and
Certification of Gaseous Calibration
[[Page 74847]]
Standards (Issued May 2012) is mandatory for certifying the calibration
gases being used for the calibration and audit of ambient air quality
analyzers and continuous emission monitors that are required by
numerous parts of the CFR.
The EPA determined that the ASTM and ASME/ANSI standards,
notwithstanding the age of the standards, are reasonably available
because it they are available for purchase from the following
addresses: ASTM International (ASTM), 100 Barr Harbor Drive, Post
Office Box C700, West Conshohocken, PA 19428-2959; or ProQuest, 300
North Zeeb Road, Ann Arbor, MI 48106 and the American Society of
Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016-
5990. The EPA determined that the EPA standard is reasonably available
because it is publicly available through the EPA's website: https://nepis.epa.gov/Adobe/PDF/P100EKJR.pdf.
The EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially
applicable VCS and to explain why such standards should be used in this
regulation.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
This action does not have disproportionately high and adverse human
health or environmental effects on minority populations, low-income
populations, and/or indigenous peoples, as specified in Executive Order
12898 (59 FR 7629; February 16, 1994). The documentation for this
assessment is contained in section 4 of the Regulatory Impact Analysis
for the Proposed Standards of Performance for New, Reconstructed, and
Modified Sources and Emissions Guidelines for Existing Sources: Oil and
Natural Gas Sector Climate Review prepared for the November 2021
proposal and in section 4 of the Regulatory Impact Analysis of the
Supplemental Proposal for the Standards of Performance for New,
Reconstructed, and Modified Sources and Emissions Guidelines for
Existing Sources: Oil and Natural Gas Sector Climate Review prepared
for this action.\350\
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\350\ See Document ID No. EPA-HQ-OAR-2021-0317-0173.
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List of Subjects in 40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Incorporation by reference; Reporting and
recordkeeping requirements.
Michael S. Regan,
Administrator.
[FR Doc. 2022-24675 Filed 12-5-22; 8:45 am]
BILLING CODE 6560-50-P