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Proposed Rule2023-14338

Greenhouse Gas Reporting Rule: Revisions and Confidentiality Determinations for Petroleum and Natural Gas Systems

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Published

August 1, 2023

Issuing agencies

Environmental Protection Agency

Abstract

The Environmental Protection Agency (EPA) is proposing to amend requirements that apply to the petroleum and natural gas systems source category of the Greenhouse Gas Reporting Rule to ensure that reporting is based on empirical data, accurately reflects total methane emissions and waste emissions from applicable facilities, and allows owners and operators of applicable facilities to submit empirical emissions data that appropriately demonstrate the extent to which a charge is owed. The EPA is also proposing changes to requirements that apply to the general provisions, general stationary fuel combustion, and petroleum and natural gas systems source categories of the Greenhouse Gas Reporting Rule to improve calculation, monitoring, and reporting of greenhouse gas data for petroleum and natural gas systems facilities. This action also proposes to establish and amend confidentiality determinations for the reporting of certain data elements to be added or substantially revised in these proposed amendments.

Full Text

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[Federal Register Volume 88, Number 146 (Tuesday, August 1, 2023)]
[Proposed Rules]
[Pages 50282-50441]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2023-14338]

[[Page 50281]]

Vol. 88

Tuesday,

No. 146

August 1, 2023

Part II

Environmental Protection Agency

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40 CFR Part 98

Greenhouse Gas Reporting Rule: Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems; Proposed Rule

Federal Register / Vol. 88, No. 146 / Tuesday, August 1, 2023 /
Proposed Rules

[[Page 50282]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2023-0234; FRL-10246-01-OAR]
RIN 2060-AV83

Greenhouse Gas Reporting Rule: Revisions and Confidentiality
Determinations for Petroleum and Natural Gas Systems

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: The Environmental Protection Agency (EPA) is proposing to
amend requirements that apply to the petroleum and natural gas systems
source category of the Greenhouse Gas Reporting Rule to ensure that
reporting is based on empirical data, accurately reflects total methane
emissions and waste emissions from applicable facilities, and allows
owners and operators of applicable facilities to submit empirical
emissions data that appropriately demonstrate the extent to which a
charge is owed. The EPA is also proposing changes to requirements that
apply to the general provisions, general stationary fuel combustion,
and petroleum and natural gas systems source categories of the
Greenhouse Gas Reporting Rule to improve calculation, monitoring, and
reporting of greenhouse gas data for petroleum and natural gas systems
facilities. This action also proposes to establish and amend
confidentiality determinations for the reporting of certain data
elements to be added or substantially revised in these proposed
amendments.

DATES: Comments. Comments must be received on or before October 2,
2023. Under the Paperwork Reduction Act (PRA), comments on the
information collection provisions are best assured of consideration if
the Office of Management and Budget (OMB) receives a copy of your
comments on or before August 31, 2023.
Public hearing. The EPA does not plan to conduct a public hearing
unless requested. If anyone contacts us requesting a public hearing on
or before August 7, 2023, we will hold a virtual public hearing. See
SUPPLEMENTARY INFORMATION for information on requesting and registering
for a public hearing.

ADDRESSES: Comments. You may submit comments, identified by Docket Id.
No. EPA-HQ-OAR-2023-0234, by any of the following methods:
Federal eRulemaking Portal. <a href="http://www.regulations.gov">www.regulations.gov</a> (our preferred
method). Follow the online instructions for submitting comments.
Mail: U.S. Environmental Protection Agency, EPA Docket Center, Air
and Radiation Docket, Mail Code 28221T, 1200 Pennsylvania Avenue NW,
Washington, DC 20460.
Hand Delivery or Courier (by scheduled appointment only): EPA
Docket Center, WJC West Building, Room 3334, 1301 Constitution Avenue
NW, Washington, DC 20004. The Docket Center's hours of operations 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 proposed rulemaking. Comments received may be posted
without change to <a href="http://www.regulations.gov/">www.regulations.gov/</a>, 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.
The virtual hearing, if requested, will be held using an online
meeting platform, and the EPA will provide information on its website
(<a href="http://www.epa.gov/ghgreporting">www.epa.gov/ghgreporting</a>) regarding how to register and access the
hearing. Refer to the SUPPLEMENTARY INFORMATION section for additional
information.

FOR FURTHER INFORMATION CONTACT: Jennifer Bohman, Climate Change
Division, Office of Atmospheric Programs (MC-6207A), Environmental
Protection Agency, 1200 Pennsylvania Ave. NW, Washington, DC 20460;
telephone number: (202) 343-9548; email address: <a href="/cdn-cgi/l/email-protection#c5828d8297a0b5aab7b1acaba285a0b5a4eba2aab3">[email&#160;protected]</a>.
For technical information, please go to the Greenhouse Gas Reporting
Program (GHGRP) website, <a href="http://www.epa.gov/ghgreporting">www.epa.gov/ghgreporting</a>. To submit a
question, select Help Center, followed by ``Contact Us.''
World Wide Web (WWW). In addition to being available in the docket,
an electronic copy of this proposal will also be available through the
WWW. Following the Administrator's signature, a copy of this proposed
rule will be posted on the EPA's GHGRP website at <a href="http://www.epa.gov/ghgreporting">www.epa.gov/ghgreporting</a>.

SUPPLEMENTARY INFORMATION:
Written comments. Submit your comments, identified by Docket Id.
No. EPA-HQ-OAR-2023-0234, at <a href="http://www.regulations.gov">www.regulations.gov</a> (our preferred
method), or the other methods identified in the ADDRESSES section. Once
submitted, comments cannot be edited or removed from the docket. The
EPA may publish any comment received to its public docket. Do not
submit to the EPA's docket at <a href="http://www.regulations.gov">www.regulations.gov</a> any information you
consider to be confidential business information (CBI), proprietary
business information (PBI), or other information whose disclosure is
restricted by statute. 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). Commenters who would like the EPA
to further consider in this rulemaking any relevant comments that they
provided on the 2022 Proposed Rule regarding proposed revisions at
issue in this proposal must resubmit those comments to the EPA during
this proposal's comment period. Please visit <a href="http://www.epa.gov/dockets/commenting-epa-dockets">www.epa.gov/dockets/commenting-epa-dockets</a> for additional submission methods; the full EPA
public comment policy; information about CBI, PBI, or multimedia
submissions, and general guidance on making effective comments.
Participation in virtual public hearing. To request a virtual
public hearing, please contact the person listed in the following FOR
FURTHER INFORMATION CONTACT section by August 7, 2023. If requested,
the virtual hearing will be held on August 21, 2023. The EPA will
provide further information about the hearing on its website
(<a href="http://www.epa.gov/ghgreporting">www.epa.gov/ghgreporting</a>) if a hearing is requested.
If a public hearing is requested, the EPA will begin pre-
registering speakers for the hearing no later than one business day
after a request has been received. To register to speak at the virtual
hearing, please use the online registration form available at
<a href="http://www.epa.gov/ghgreporting">www.epa.gov/ghgreporting</a> or contact us by email at
<a href="/cdn-cgi/l/email-protection#80c7c8c7d2e5f0eff2f4e9eee7c0e5f0e1aee7eff6">[email&#160;protected]</a>. The last day to pre-register to speak at the
hearing will be August 16, 2023. On August 18, 2023, the EPA will post
a general agenda that will list pre-registered speakers in approximate
order at: <a href="http://www.epa.gov/ghgreporting">www.epa.gov/ghgreporting</a>.
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

[[Page 50283]]

electronically (via email) by emailing it to <a href="/cdn-cgi/l/email-protection#bff8f7f8eddacfd0cdcbd6d1d8ffdacfde91d8d0c9">[email&#160;protected]</a>. The
EPA also recommends 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.
Please note that any updates made to any aspect of the hearing will
be posted online at <a href="http://www.epa.gov/ghgreporting">www.epa.gov/ghgreporting</a>. While the EPA expects the
hearing to go forward as set forth above, please monitor our website or
contact us by email at <a href="/cdn-cgi/l/email-protection#783f303f2a1d08170a0c11161f381d0819561f170e">[email&#160;protected]</a> to determine if there are
any updates. The EPA does not intend to publish a document in the
Federal Register announcing updates.
If you require the services of an interpreter or special
accommodation such as audio description, please pre-register for the
hearing with the public hearing team and describe your needs by August
8, 2023. The EPA may not be able to arrange accommodations without
advanced notice.
Regulated entities. This is a proposed regulation. If finalized,
these proposed revisions would affect certain entities that must submit
annual greenhouse gas (GHG) reports under the GHGRP (40 CFR part 98).
These are proposed amendments to existing regulations. If finalized,
these amended regulations would also affect owners or operators of
petroleum and natural gas systems that directly emit GHGs. Regulated
categories and entities include, but are not limited to, those listed
in Table 1 of this preamble:

Table 1--Examples of Affected Entities by Category
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North American
Industry Examples of
Category Classification affected facilities
System (NAICS)
------------------------------------------------------------------------
Petroleum and Natural Gas Systems 486210 Pipeline
transportation of
natural gas.
221210 Natural gas
distribution
facilities.
211120 Crude petroleum
extraction.
211130 Natural gas
extraction.
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Table 1 of this preamble is not intended to be exhaustive, but
rather provides a guide for readers regarding facilities likely to be
affected by this proposed action. This table lists the types of
facilities that the EPA is now aware could potentially be affected by
this action. Other types of facilities than those listed in the table
could also be subject to reporting requirements. To determine whether
you would be affected by this proposed action, you should carefully
examine the applicability criteria found in 40 CFR part 98, subpart A
(General Provisions) and 40 CFR part 98, subpart W (Petroleum and
Natural Gas Systems). If you have questions regarding the applicability
of this action to a particular facility, consult the person listed in
the FOR FURTHER INFORMATION CONTACT section.
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
AGR acid gas removal unit
AMLD Advanced Mobile Leak Detection
API American Petroleum Institute
ASTM American Society for Testing and Materials
BOEM Bureau of Ocean Energy Management
BRE Bryan Research & Engineering
Btu/scf British thermal units per standard cubic foot
CAA Clean Air Act
CBI confidential business information
CEMS continuous emissions monitoring system
CenSARA Central States Air Resources Agency
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e carbon dioxide equivalent
CRR cost-to-revenue ratio
e-GGRT electronic Greenhouse Gas Reporting Tool
EG emission guidelines
EIA U.S. Energy Information Administration
EPA U.S. Environmental Protection Agency
ET Eastern time
FAQ frequently asked question
FLIGHT Facility Level Information on Greenhouse gases Tool
FR Federal Register
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GOR gas to oil ratio
gpm gallons per minute
GRI Gas Research Institute
GT gas turbines
HHV higher heating value
ICR Information Collection Request
ID identification
IRA Inflation Reduction Act of 2022
ISBN International Standard Book Number
IVT Inputs Verification Tool
kg/hr kilograms per hour
LDC local distribution company
LNG liquefied natural gas
m meters
MDEA methyl diethanolamine
MEA monoethanolamine
MMBtu/hr million British thermal units per hour
MMscf million standard cubic feet
mt metric tons
mtCO2e metric tons carbon dioxide equivalent
N2O nitrous oxide
NAICS North American Industry Classification System
NGLs natural gas liquids
NMAC New Mexico Administrative Code
NSPS new source performance standards
O&M operation and maintenance
OCS AQS Outer Continental Shelf Air Quality System
OEM original equipment manufacturer
OGI optical gas imaging
OMB Office of Management and Budget
PBI proprietary business information
ppm parts per million
ppmv parts per million by volume
PRA Paperwork Reduction Act
psig pounds per square inch gauge
REC reduced emission completion
RFA Regulatory Flexibility Act
RFI Request for Information
RICE reciprocating internal combustion engines
RY reporting year
scf standard cubic feet
scf/hr/device standard cubic feet per hour per device
THC total hydrocarbon
TSD technical support document
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
VOC volatile organic compound(s)
WWW World Wide Web

Contents

I. Background
A. How is this preamble organized?
B. Executive Summary
C. Background on This Proposed Rule
D. Legal Authority
E. Relationship to Other Clean Air Act Section 136 Actions

[[Page 50284]]

II. Overview and Rationale for Proposed Amendments to 40 CFR Part
98, subpart W
A. Revisions To Address Potential Gaps in Reporting of Emissions
Data for Specific Sectors
B. Revisions To Add New Emissions Calculation Methodologies or
Improve Existing Emissions Calculation Methodologies
C. Revisions To Reporting Requirements to Improve Verification
and Transparency of the Data Collected
D. Technical Amendments, Clarifications, and Corrections
III. Proposed Amendments to Part 98
A. General and Applicability Amendments
B. Other Large Release Events
C. New and Additional Emission Sources
D. Reporting for the Onshore Petroleum and Natural Gas
Production and Onshore Petroleum and Natural Gas Gathering and
Boosting Industry Segments
E. Natural Gas Pneumatic Device Venting and Natural Gas Driven
Pneumatic Pump Venting
F. Acid Gas Removal Unit Vents
G. Dehydrator Vents
H. Liquids Unloading
I. Gas Well Completions and Workovers With Hydraulic Fracturing
J. Blowdown Vent Stacks
K. Atmospheric Storage Tanks
L. Flared Transmission Storage Tank Vent Emissions
M. Associated Gas Venting and Flaring
N. Flare Stack Emissions
O. Compressors
P. Equipment Leak Surveys
Q. Equipment Leaks by Population Count
R. Offshore Production
S. Combustion Equipment
T. Leak Detection and Measurement Methods
U. Industry Segment-Specific Throughput Quantity Reporting
V. Other Proposed Minor Revisions or Clarifications
IV. Schedule for the Proposed Amendments
V. Proposed Confidentiality Determinations for Certain Data
Reporting Elements
A. Overview and Background
B. Proposed Confidentiality Determinations
C. Proposed Reporting Determinations for Inputs to Emissions
Equations
D. Request for Comments on Proposed Category Assignments,
Confidentiality Determinations, or Reporting Determinations
VI. Impacts of the Proposed Amendments
VII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Determination Under CAA Section 307(d)

I. Background

A. How is this preamble organized?

The first section of this preamble contains background information
regarding the proposed amendments. This section also discusses the
EPA's legal authority under the Clean Air Act (CAA) to promulgate
(including subsequent amendments to) the Greenhouse Gas Reporting Rule,
codified at 40 CFR part 98 (hereafter referred to as ``part 98''),
generally and 40 CFR part 98, subpart W (hereafter referred to as
``subpart W'') in particular. This section also discusses the EPA's
legal authority to make confidentiality determinations for new or
revised data elements required by these amendments or for existing data
elements for which a confidentiality determination has not previously
been proposed. Section II of this preamble describes the types of
amendments included in this proposed rulemaking and includes the
rationale for each type of proposed change. Section III of this
preamble contains detailed information on the proposed revisions to 40
CFR part 98, subpart A (General Provisions), subpart C (General
Stationary Fuel Combustion Sources) and subpart W. Section IV of this
preamble discusses when the proposed revisions to part 98 would apply
to reporters. Section V of this preamble discusses the proposed
confidentiality determinations for new or substantially revised data
reporting elements (i.e., requiring additional or different data to be
reported), as well as for certain existing data elements for which a
determination has not been previously established. Section VI of this
preamble discusses the impacts of the proposed amendments. Section VII
of this preamble describes the statutory and Executive order
requirements applicable to this action.

B. Executive Summary

In August 2022, Congress passed, and President Biden signed, the
Inflation Reduction Act of 2022 (IRA) into law. Section 60113 of the
IRA amended the CAA by adding section 136, ``Methane Emissions and
Waste Reduction Incentive Program for Petroleum and Natural Gas
Systems.'' CAA section 136(c), ``Waste Emissions Charge,'' directs the
Administrator to impose and collect a charge on methane
(CH<INF>4</INF>) emissions that exceed statutorily specified waste
emissions thresholds from an owner or operator of an applicable
facility that reports more than 25,000 metric tons carbon dioxide
equivalent (mtCO<INF>2</INF>e) pursuant to the Greenhouse Gas Reporting
Rule's requirements for the petroleum and natural gas systems source
category (codified as subpart W in EPA's Greenhouse Gas Reporting Rule
regulations). Further, CAA section 136(h) requires that the EPA shall,
within two years after the date of enactment of section 60113 of the
IRA, revise the requirements of subpart W to ensure the reporting under
subpart W (and corresponding waste emissions charges under CAA section
136) is based on empirical data, accurately reflects the total
CH<INF>4</INF> emissions (and waste emissions) from the applicable
facilities, and allow owners and operators of applicable facilities to
submit empirical emissions data, in a manner to be prescribed by the
Administrator, to demonstrate the extent to which a charge is owed
under CAA section 136.
In this action, the EPA is proposing revisions to subpart W
consistent with the authority and directives set forth in CAA section
136(h) as well as the EPA's authority under CAA section 114. The EPA is
proposing revisions to include reporting of additional emissions or
emissions sources to address potential gaps in the total CH<INF>4</INF>
emissions reported by facilities to subpart W. These revisions include
proposing to add a new emissions source, referred to as ``other large
release events,'' to capture large emission events that are not
accurately accounted for using existing methods in subpart W. Other new
sources proposed to be added or included in revised existing sources
include nitrogen removal units, produced water tanks, mud degassing,
crankcase venting and combustion slip. The EPA is also proposing
several revisions to add new or revise existing calculation
methodologies to improve the accuracy of reported emissions,
incorporate additional empirical data and to allow owners and operators
of applicable facilities to submit empirical emissions data that could
appropriately demonstrate the extent to which a charge is owed in
future implementation of CAA section 136, as directed by CAA section
136(h). For example, the EPA is proposing new calculation methodologies
for equipment leaks and natural gas

[[Page 50285]]

pneumatic devices to allow for the use of direct measurement. The EPA
is also proposing several revisions to existing reporting requirements
to collect data that would improve verification of reported data,
ensure accurate reporting of emissions, and improve the transparency of
reported data. For example, the EPA is proposing to disaggregate
reporting requirements within the Onshore Petroleum and Natural Gas
Production and Onshore Petroleum and Natural Gas Gathering and Boosting
industry segments, with most emissions and activity data for Onshore
Petroleum and Natural Gas Production and Onshore Petroleum and Natural
Gas Gathering and Boosting being disaggregated to at least the well-pad
and site-level, respectively. The EPA is also proposing other technical
amendments, corrections, and clarifications that would improve
understanding of the rule. These revisions primarily include revisions
of requirements to better reflect the EPA's intent or editorial
changes. The proposed revisions under this rulemaking are described in
further detail in sections II and III of this preamble. The EPA will be
undertaking one or more separate actions in the future to implement the
remainder of CAA section 136.

C. Background on This Proposed Rule

This proposed action builds on previous Greenhouse Gas reporting
rulemakings. The Greenhouse Gas Reporting Rule was published in the
Federal Register (FR) on October 30, 2009 (74 FR 56260) (hereafter
referred to as the 2009 Final Rule). The 2009 Final Rule became
effective on December 29, 2009, and requires reporting of GHGs from
various facilities and suppliers, consistent with the 2008 Consolidated
Appropriations Act.\1\ Although reporting requirements for petroleum
and natural gas systems were originally proposed to be part of part 98
(75 FR 16448, April 10, 2009), the final October 2009 rulemaking did
not include the petroleum and natural gas systems source category as
one of the 29 source categories for which reporting requirements were
finalized. The EPA re-proposed subpart W in 2010 (75 FR 18608; April
12, 2010), and a subsequent final rulemaking was published on November
30, 2010, with the requirements for the petroleum and natural gas
systems source category at 40 CFR part 98, subpart W (75 FR 74458)
(hereafter referred to as the ``2010 Final Rule''). Following
promulgation, the EPA finalized several technical and clarifying
amendments to subpart W (76 FR 22825, April 25, 2011; 76 FR 53057,
August 25, 2011; 76 FR 59533, September 27, 2011; 76 FR 73866, November
29, 2011; 76 FR 80554, December 23, 2011; 77 FR 48072, August 13, 2012;
77 FR 51477, August 24, 2012; 78 FR 25392, May 1, 2013; 78 FR 71904,
November 29, 2013; 79 FR 63750, October 24, 2014; 79 FR 70352, November
25, 2014; 80 FR 64262, October 22, 2015; and 81 FR 86490, November 30,
2016). These amendments generally added or revised requirements in
subpart W, including revisions that were intended to improve quality,
clarity, and consistency across the calculation, monitoring, and data
reporting requirements, and to finalize confidentiality and reporting
determinations for data elements reported under the subpart.
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\1\ Consolidated Appropriations Act, 2008, Public Law 110-161,
121 Stat. 1844, 2128.
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More recently, the EPA proposed amendments to subpart W on June 21,
2022 (87 FR 36920) (hereafter referred to as the ``2022 Proposed
Rule''), including technical amendments to improve the quality and
consistency of the data collected under the rule and resolve data gaps,
amendments to streamline and improve implementation, and revisions to
provide additional flexibility in the calculation methods and
monitoring requirements for some emission sources. The 2022 Proposed
Rule was developed prior to the enactment of the IRA and its direction
in CAA section 136(h) to revise subpart W. Consequently, in developing
this current proposed action, the EPA considered the proposed
amendments to subpart W from the 2022 Proposed Rule as well as the
concerns and information submitted by commenters in response to that
proposal. In this proposal, the EPA is again proposing to revise the
subpart W provisions, and our proposed revisions include both (1)
updates to the proposed revisions to subpart W that were in the 2022
Proposed Rule as well as (2) additional proposed revisions to comply
with CAA section 136(h). The EPA accordingly does not intend to
finalize the revisions to subpart W that were proposed in the 2022
Proposed Rule in the final version of that rule. Commenters who would
like the EPA to further consider in this rulemaking any relevant
comments that they provided on the 2022 Proposed Rule regarding its
proposed revisions to subpart W must resubmit those comments to the EPA
during this proposal's comment period.
Additionally, the EPA opened a non-regulatory docket on November 4,
2022, and issued a Request for Information (RFI) seeking public input
to inform program design related to CAA section 136.\2\ As part of this
request, the EPA sought input on revisions that should be considered
related to subpart W. The comment period closed on January 18, 2023.
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\2\ Docket ID No. EPA-HQ-OAR-2022-0875.
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The EPA also recently issued a supplemental proposal to the 2022
Proposed Rule (88 FR 32852, May 22, 2023), which included proposed
updates to the General Provisions of the Greenhouse Gas Reporting Rule
to reflect revised global warming potentials, proposed reporting of GHG
data from additional sectors (i.e., non-subpart W sectors), and
proposed revisions to source categories other than subpart W that would
improve implementation of the Greenhouse Gas Reporting Rule. These
proposed revisions are being undertaken in a separate action.
Accordingly, the EPA considers comments related to that action to be
outside the scope of this proposed rule.

D. Legal Authority

The EPA is proposing these rule amendments under its existing CAA
authority provided in CAA section 114 and under its newly established
authority provided in CAA section 136, as applicable. As stated in the
preamble to the 2009 Final Rule, CAA section 114(a)(1) provides the EPA
broad authority to require the information proposed to be gathered by
this rule because such data would inform and are relevant to the EPA's
carrying out of a variety of CAA provisions. See the preambles to the
proposed Greenhouse Gas Reporting Rule (74 FR 16448, April 10, 2009)
and the 2009 Final Rule for further information. As noted in section
I.B of this preamble, the IRA added CAA section 136, ``Methane
Emissions and Waste Reduction Incentive Program for Petroleum and
Natural Gas Systems,'' which requires revisions to the requirements of
subpart W to ensure that reporting of CH<INF>4</INF>emissions under
subpart W (and corresponding waste emissions charges under CAA section
136) is based on empirical data, accurately reflects the total
CH<INF>4</INF> emissions (and waste emissions) from applicable
facilities, and allows owners and operators to submit empirical
emissions data, in a manner prescribed by the Administrator, to
demonstrate the extent to which a charge is owed under CAA section 136.
Under CAA section 136, an ``applicable facility'' is a facility within
nine of the ten industry segments subject to subpart W, as currently
defined in 40 CFR 98.230 (excluding natural gas distribution).

[[Page 50286]]

The Administrator has determined that this action is subject to the
provisions of section 307(d) of the CAA. Section 307(d) contains a set
of procedures relating to the issuance and review of certain CAA rules.
In addition, pursuant to sections 114, 301, and 307 of the CAA, the
EPA is publishing proposed confidentiality determinations for the new
or substantially revised data elements required by these proposed
amendments. Section 114(c) requires that the EPA make information
obtained under section 114 available to the public, except for
information (excluding emission data) that qualifies for confidential
treatment.

E. Relationship to Other Clean Air Act Section 136 Actions

The IRA adds authorities under CAA section 136 to reduce
CH<INF>4</INF> emissions from the oil and gas sector. It accomplishes
this in multiple ways. First, it provides incentives for CH<INF>4</INF>
mitigation and monitoring. Second, it establishes a waste emissions
charge for applicable facilities that exceed statutorily-specified
thresholds that vary by industry segment and are determined by the
amount of natural gas or oil sent to sale. Third, CAA section 136(h)
requires the EPA to revise subpart W. The first and second listed
aspects of CAA section 136 are outside the scope of this rulemaking.
CAA section 136 provides $1.55 billion in incentives for
CH<INF>4</INF> mitigation and monitoring, including through grants,
rebates, contracts, loans, and other activities. Of these funds, at
least $700 million is allocated to activities at marginal conventional
wells. There are several potential uses of funds. Use of funds can
include financial and technical assistance to owners and operators of
applicable facilities to prepare and submit GHG reports under subpart
W. Financial assistance can also be provided for CH<INF>4</INF>
emissions monitoring authorized under CAA section 103 subsections (a)
through (c). Additionally, financial and technical assistance can be
provided to: reduce CH<INF>4</INF> and other GHG emissions from
petroleum and natural gas systems, including to mitigate legacy air
pollution from petroleum and natural gas systems; improve climate
resilience of communities and petroleum and natural gas systems;
improve and deploy industrial equipment and processes that reduce
CH<INF>4</INF> and other GHG emissions and waste; support innovation in
reducing CH<INF>4</INF> and other GHG emissions and waste from
petroleum and natural gas systems; permanently shut in and plug wells
on non-Federal land; and mitigate health effects of CH<INF>4</INF> and
other GHG emissions and legacy air pollution from petroleum and natural
gas systems in low-income and disadvantaged communities, and support
environmental restoration.
The EPA has provided initial public engagement and input
opportunities related to the design and implementation of these
incentives. This has included issuing an RFI \3\ to inform program
design and listening sessions to enable input directly to the EPA.
Through these engagement opportunities, the EPA has heard a number of
common themes. First, the EPA has received input that the EPA should
use funding mechanisms for rapid distribution of incentives. Second,
the EPA has heard about the need for addressing critical gaps and key
opportunities to achieve maximum impact. Third, the EPA has received
input about the need to address cumulative pollution for overburdened
communities.
---------------------------------------------------------------------------

\3\ Docket ID No. EPA-HQ-OAR-2022-0875.
---------------------------------------------------------------------------

The EPA is moving expeditiously to implement the incentives for
CH<INF>4</INF> mitigation and monitoring and anticipates making
announcements regarding next steps; however, as noted, those steps are
outside the scope of this rulemaking.
CAA section 136(c) provides that the Administrator shall impose and
collect a charge on CH<INF>4</INF> emissions that exceed an applicable
waste emissions threshold under CAA section 136(f) from an owner or
operator of an applicable facility that reports more than 25,000
mtCO<INF>2</INF>e per year pursuant to subpart W. CAA section 136
provides various flexibilities and exemptions relating to the waste
emissions charge. The EPA intends to undertake one or more separate
actions in the future to implement the waste emissions charge and
intends to provide an opportunity for public comment in those actions;
therefore, as noted, implementation of the waste emissions charge is
outside the scope of this rulemaking.
As noted earlier, CAA section 136(h) requires revisions to subpart
W. The purpose of this proposed action is to meet directives set forth
in CAA section 136(h).

II. Overview and Rationale for Proposed Amendments to 40 CFR Part 98,
Subpart W

As discussed in section I of this preamble, in August 2022,
Congress passed, and President Biden signed, the IRA into law. Section
60113 of the IRA amended the CAA by adding section 136, ``Methane
Emissions and Waste Reduction Incentive Program for Petroleum and
Natural Gas Systems.'' CAA section 136(h) requires that the EPA shall,
within two years of the enactment of that section of the IRA, revise
the requirements of subpart W to ensure the reporting under that
subpart and calculation of charges under CAA section 136(e) and (f) are
based on empirical data, accurately reflect the total CH<INF>4</INF>
emissions and waste emissions from the applicable facilities, and allow
owners and operators of applicable facilities to submit empirical
emissions data, in a manner prescribed by the Administrator, to
demonstrate the extent to which a charge is owed. CAA section 136(d)
defines the term ``applicable facility'' as a facility within the
following industry segments as defined in subpart W: offshore petroleum
and natural gas production, onshore petroleum and natural gas
production, onshore natural gas processing, onshore gas transmission
compression, underground natural gas storage, liquefied natural gas
storage, liquefied natural gas import and export equipment, onshore
petroleum and natural gas gathering and boosting, and onshore natural
gas transmission pipeline.
Empirical data can be defined as data that are collected by
observation and experiment. There are many forms of empirical data that
can be used to quantify GHG emissions. For purposes of this action, the
EPA interprets empirical data to mean data that are collected by
conducting observations and experiments that could be used to
accurately calculate emissions at a facility, including direct
emissions measurements, monitoring of CH<INF>4</INF> emissions (e.g.,
leak surveys) or measurement of associated parameters (e.g., flow rate,
pressure, etc.), and published data. The EPA reviewed available
empirical data methods for accuracy and appropriateness for calculating
annual unit or facility-level GHG emissions. The review included both
the evaluation of technologies and methodologies already incorporated
in subpart W for measuring and reporting annual source- and facility-
level GHG emissions and the evaluation of the accuracy of potential
alternative technologies and methodologies, with a focus on
CH<INF>4</INF> emissions due to the directive in CAA section 136(h).
Currently, subpart W specifies emission source types to be reported
for each industry segment and provides methodologies to calculate
emissions from each source type, which are then summed to generate the
total subpart W emissions for the facility. Current calculation methods
can be grouped

[[Page 50287]]

into five categories: (1) direct emissions measurement; (2) combination
of measurement and engineering calculations; (3) engineering
calculations; (4) leak detection and use of a leaker emission factor;
and (5) population count and population emission factors. Subpart W
emission factors (both population and leaker emission factors) include
both those developed from published empirical data and those developed
from site-specific data collected by the reporting facility. The EPA
developed the current subpart W monitoring and reporting requirements
to use the most appropriate monitoring and calculation methods,
considering both the accuracy of the emissions calculated by the
proposed method and the size of the emission source based on the
methods and data available at the time of the applicable rule
promulgation. Considering the directives set forth in CAA section 136,
the EPA re-evaluated the existing methodologies to determine if they
are likely to accurately reflect CH<INF>4</INF> and waste emissions at
an individual facility, whether the existing methodologies used
empirical data, and whether the existing methodologies should be
modified or replaced to meet CAA section 136 directives. In cases where
source-level emissions were determined to be highly variable, not well
characterized by an available method in subpart W, and a more accurate
method, such as direct emissions measurement, is available, the EPA is
proposing to update reporting requirements to reflect only
methodologies that have been determined to likely accurately
characterize unit or facility-level emissions. For example,
intermittent bleed pneumatic devices are designed to vent during
actuation only, but these devices are known to often malfunction and
operate incorrectly which causes them to release gas to the atmosphere
when idle, leading to high degree of variance in emissions from
pneumatic devices between facilities (see Greenhouse Gas Reporting
Rule: Technical Support for Revisions and Confidentiality
Determinations for Data Elements Under the Greenhouse Gas Reporting
Rule; Proposed Rule--Petroleum and Natural Gas Systems, hereafter
referred to as the ``subpart W TSD,'' available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234, for more information).
The EPA welcomes comments on all aspects of this technical support
document. Even in cases where the EPA considers an existing method that
is not based on direct measurement or emission monitoring provides a
reasonably accurate calculation of emissions for a facility, we also
reviewed whether a direct emission measurement or emission monitoring
method could be added to subpart W, if one was not already available,
to give owners and operators the opportunity to submit empirical data.
The EPA also evaluated whether there were gaps in the emission source
types reporting CH<INF>4</INF> emissions under subpart W and whether
there were methodologies available to calculate those emissions.
The proposed amendments include:
<bullet> Revisions to expand reporting to include new emission
sources, in order to accurately reflect total CH<INF>4</INF> emissions
reported to the GHGRP.
<bullet> Revisions to add emissions calculation methodologies to
incorporate additional empirical data and improve the accuracy of
reported emission data.
<bullet> Revisions to refine existing emissions calculation
methodologies to reflect an improved understanding of emissions or to
incorporate more recent research on GHG emissions to improve the
accuracy of reported emission data.
<bullet> Revisions to remove calculation methodologies in cases
where it was determined that more accurate calculation methodologies
were available.
The EPA has also identified additional areas where revisions to
part 98 would improve the EPA's ability to verify the accuracy of
reported emissions and improve data transparency and alignment with
other EPA programs and regulations. The EPA also identified areas where
additional data or revised data elements may be necessary for future
implementation of the waste emissions charge under CAA section 136. The
proposed revisions include:
<bullet> Revisions to report emissions from facilities in the
Onshore Petroleum and Natural Gas Production and Onshore Petroleum and
Natural Gas Gathering and Boosting industry segments at the site level
instead of at the basin level, sub-basin level, or county level.
<bullet> Addition of data elements related to emissions from
plugged wells.
<bullet> Addition or clarification of throughput-related data
elements for subpart W industry segments.
<bullet> Revisions to data elements or recordkeeping where the
current requirements are redundant or alternative data would be more
appropriate for verification of emission data.
<bullet> Revisions that provide additional information for
reporters to better or more fully understand their compliance
obligations, revisions that emphasize the EPA's intent for requirements
that reporters appear to have previously misinterpreted to ensure that
accurate data are being collected, and editorial corrections or
harmonizing changes that would improve the public's understanding of
the rule.
Sections II.A through II.D of this preamble describe the above
changes in more detail and provide the EPA's rationale for the changes
included in each category. Additional details for the specific
amendments proposed for each subpart are included in section III of
this preamble. We are seeking public comment only on the proposed
revisions and issues specifically identified in this document for the
identified subparts. We expect to deem any comments received addressing
other aspects of 40 CFR part 98 or other rulemakings to be outside of
the scope of this proposed rulemaking.
In addition, on November 15, 2021 (86 FR 63110), the EPA proposed
under CAA section 111(b) standards of performance for certain new,
reconstructed, and modified oil and natural gas sources (40 CFR part
60, subpart OOOOb) (hereafter referred to as ``NSPS OOOOb''), as well
as emissions guidelines under CAA section 111(d) for certain existing
oil and natural gas sources (40 CFR part 60, subpart OOOOc) (hereafter
referred to as ``EG OOOOc'') (the sources affected by these two
proposed subparts are collectively referred to in this preamble as
``affected sources''). On December 6, 2022, the EPA issued a
supplemental proposal to update, strengthen and expand the standards
proposed on November 15, 2021 (87 FR 74702). While the standards in
proposed NSPS OOOOb would directly apply to new, reconstructed, and
modified sources when finalized, the final EG OOOOc would not impose
binding requirements directly on sources; rather it would contain
guidelines, including presumptive standards, for states to follow in
developing, submitting, and implementing plans to establish standards
of performance to limit GHGs (in the form of CH4 limitations) from
existing oil and gas sources within their own states. If a state does
not submit a plan to the EPA for approval in response to the final
emission guidelines, or if the EPA disapproves a state's plan, then the
EPA must establish a Federal plan. In addition, a Federal plan could
apply to sources located on Tribal lands where the tribe does not
request approval to develop a tribal implementation plan similar to a
state plan. Once the Administrator approves a state plan under CAA
section 111(d), the plan is

[[Page 50288]]

codified in 40 CFR part 62 (Approval and Promulgation of State Plans
for Designated Facilities and Pollutants) within the relevant subpart
for that state.\4\ 40 CFR part 62 also includes all Federal plans
promulgated pursuant to CAA section 111(d). Therefore, rather than
referencing the presumptive standards in EG OOOOc, which would not
directly apply to sources, the proposed amendments to subpart W
reference 40 CFR part 62.
---------------------------------------------------------------------------

\4\ 40 CFR part 62 contains a subpart for each of the 50 states,
District of Columbia, American Samoa, Puerto Rico, Virgin Islands,
and Northern Mariana Islands.
---------------------------------------------------------------------------

Similar to the 2016 amendments to align subpart W requirements with
certain requirements in 40 CFR part 60, subpart OOOOa (hereafter
referred to as ``NSPS OOOOa'') (81 FR 86500, November 30, 2016), we are
proposing revisions to certain requirements in subpart W relative to
the requirements proposed for NSPS OOOOb and the presumptive standards
proposed in EG OOOOc (which would inform the standards to be developed
and codified at 40 CFR part 62). As in the 2016 rule, the proposed
amendments would also allow facilities to use a consistent method to
demonstrate compliance with multiple EPA programs. This proposal would
limit burden for subpart W facilities with affected sources that would
also be required to comply with the proposed NSPS OOOOb or a State or
Federal plan in part 62 implementing EG OOOOc by allowing them to use
data derived from the implementation of the NSPS OOOOb to calculate
emissions for the GHGRP rather than requiring the use of different
monitoring methods. Consistent with that goal, the EPA expects that the
final amendments to subpart W would reference the final version of the
method(s) in the NSPS OOOOb and EG OOOOc. These amendments would also
improve the emission calculations reported under the GHGRP.
Specifically, we are proposing amendments to the subpart W calculation
methodologies for flares, centrifugal and reciprocating compressors,
and equipment leak surveys related to the proposed NSPS OOOOb and
presumptive standards in EG OOOOc, and we are proposing new reporting
requirements for ``other large release events'' as defined in subpart W
that would reference the NSPS OOOOb and approved state plans or
applicable Federal plan in 40 CFR part 62. These proposed amendments
are described in sections III.B, N, O, and P. If finalized, the
provisions of these proposed amendments that reference the NSPS OOOOb
and approved state plans or applicable Federal plan in 40 CFR part 62
would not apply to individual reporters unless and until their emission
sources are required to comply with either the final NSPS OOOOb or an
approved state plan or applicable Federal plan in 40 CFR part 62. In
the meantime, reporters would have the option to comply with the
calculation methodologies that would be required for sources subject to
NSPS OOOOb or 40 CFR part 62, or they would comply instead with the
applicable provisions of subpart W that apply to sources not subject to
NSPS OOOOb or 40 CFR part 62. For example, for flare sources subject to
NSPS OOOOb, facilities would have the option to comply with the flare
monitoring requirements in NSPS OOOOb even if the source is not yet
subject to or will not be subject to those provisions. For the ``other
large release events'' source category, emissions from other large
release events would be required to be calculated and reported starting
in Reporting Year (RY) 2025; the requirements to calculate and report
these emissions is not dependent on whether a source is subject to NSPS
OOOOb or 40 CFR part 62.
The specific changes that we are proposing, as described in this
section, are described in detail in section III of this preamble.

A. Revisions To Address Potential Gaps in Reporting of Emissions Data
for Specific Sectors

We are proposing several amendments to include reporting of
additional emissions or emissions sources to address potential gaps in
the total CH4 emissions reported per facility to subpart W. In
particular, based on recent analyses such as those conducted for the
annual Inventory of U.S. Greenhouse Gas Emissions and Sinks (U.S. GHG
Inventory), and data newly available from atmospheric observations, we
have become aware of potentially significant sources of emissions for
which there are no current emission estimation methods or reporting
requirements within part 98. For subpart W, we are proposing to add
calculation methodologies and requirements to report GHG emissions for
several additional sources. We are proposing to add a new emissions
source, referred to as ``other large release events,'' to capture
abnormal emission events that are not accurately accounted for using
existing methods in subpart W. This additional source would cover
events such as storage wellhead leaks, well blowouts,\5\ and other
large, atypical release events and would apply to all types of
facilities subject to subpart W. Reporters would calculate GHG
emissions using measurement data or engineering estimates of the amount
of gas released and measurement data, if available, or process
knowledge (best available data) to estimate the composition of the
released gas. We are also proposing to add calculation methodologies
and requirements to report GHG emissions for several other new emission
sources, including nitrogen removal units, produced water tanks, mud
degassing and crankcase venting. None of these sources are currently
accounted for in subpart W, and the EPA is proposing to include them
because they are likely to have a meaningful impact on reported CH4
emissions. We are also proposing to revise the existing methodologies
and add new measurement-based methodologies, consistent with section
II.B., for determining combustion emissions from reciprocating internal
combustion engines (RICE) and gas turbines (GT), including those that
drive compressors, to account for combustion slip, which is not
currently accounted for under the existing calculation methodologies
for combustion emissions. We are also proposing to require reporting of
existing emission sources by additional industry segments. For example,
we are proposing to require liquefied natural gas (LNG) import/export
facilities to begin calculating and reporting emissions from acid gas
removal unit (AGR) vents. Additional details of these types of proposed
changes may be found in section III of this preamble.
---------------------------------------------------------------------------

\5\ We are proposing to define a well blowout in 40 CFR 98.238
as a complete loss of well control for a long duration of time
resulting in an emissions release.
---------------------------------------------------------------------------

The proposed changes would ensure that the reporting under subpart
W accurately reflects the total CH<INF>4</INF> emissions and waste
emissions as required by CAA section 136(h).

B. Revisions To Add New Emissions Calculation Methodologies or Improve
Existing Emissions Calculation Methodologies

We are proposing several revisions to add new or revise existing
calculation methodologies to improve the accuracy of emissions data
reported to the GHGRP, incorporate additional empirical data and to
allow owners and operators of applicable facilities to submit empirical
emissions data that appropriately could demonstrate the extent to which
a charge is owed in

[[Page 50289]]

future implementation of CAA section 136, as directed by CAA section
136(h). Currently, subpart W specifies emission source types to be
reported for each industry segment and provides methodologies to
calculate emissions from each source type, which are then summed to
generate the total subpart W emissions for the facility. Considering
the directives set forth in CAA section 136, the EPA re-evaluated the
existing methodologies for each source to determine if they are likely
to accurately reflect CH<INF>4</INF> and waste emissions at an
individual facility, whether the existing methodologies used empirical
data, e.g., direct emissions measurements or monitoring of
CH<INF>4</INF> emissions or measurement of associated parameters, and
whether the existing methodologies should be modified or replaced to
meet CAA section 136 directives. A summary list of the emissions
sources proposed to be reported with the corresponding proposed
monitoring and emissions calculation methods is available in the
subpart W TSD, available in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2023-0234. Many sources in subpart W already have or
require calculation methodologies that use direct emission measurement
including AGR vents, large reciprocating compressor rod packing vents,
large compressor blowdown vent valve leaks, and large compressor
blowdown vent (unit isolation valve leaks), the latter two when leakage
is detected via screening. Currently, subpart W has required direct
measurement when the magnitude of emissions are potentially large and
no credible engineering calculation methods or emission factors existed
to accurately characterize emissions. In this proposal, the EPA is
proposing new calculation methodologies to allow for the use of direct
measurement, including for equipment leaks and natural gas pneumatic
devices. The EPA is also proposing new calculation methodologies to
allow for the development of site-specific emission factors for
equipment leaks and pneumatic devices based on data collected from
direct measurement at the facility.
We are proposing several revisions to modify calculation equations
to incorporate refinements to methodologies based on an improved
understanding of emission sources. In some cases, we have become aware
of discrepancies between assumptions in the current emission estimation
methods and the processes or activities conducted at specific
facilities, where the proposed revisions would reduce reporter errors.
In other cases, we are proposing to revise the emissions estimation
methodologies to incorporate recent studies on GHG emissions or
formation that reflect updates to scientific understanding of GHG
emissions sources. The proposed changes would improve the quality and
accuracy of the data collected under the GHGRP.
We are also proposing to revise several existing calculation
methodologies to incorporate empirical data obtained at the facility.
Emissions can be reliably calculated for sources such as tanks and
glycol dehydrators using standard engineering first principle methods
such as those available in API 4697 E&P Tanks \6\ and GRI-
GLYCalcTM.\7\ Using such software also addresses safety
concerns that are associated with direct emissions measurement from
these sources. For example, sometimes the temperature of the emissions
stream for glycol dehydrator vent stacks is too high for operators to
safely measure emissions. However, currently in subpart W, these
methods allow for use of best available data for inputs to the model.
The EPA has noted that in some cases, such as with reporting of
emissions from some dehydrators, the data used to calculate emissions
are not based on actual operating conditions but instead based on
``worst-case scenarios'' or other estimates. In these cases, the
accuracy of the reported emissions would be improved by using actual
operating conditions as measured at the unit. In this proposal, for
large glycol dehydrators and AGRs, we are proposing to require that
certain input parameters are based on actual measurements at the unit
level in order to improve the accuracy of the reported emissions for
these sources.
---------------------------------------------------------------------------

\6\ E&P Tanks v3.0 software and the user guide (Publication
4697) formerly available from the American Petroleum Institute (API)
website.
\7\ GRI-GLYCalcTM software available from Gas
Technology Institute website (<a href="https://sales.gastechnology.org/">https://sales.gastechnology.org/</a>).
---------------------------------------------------------------------------

In order to improve the accuracy of the data collected under the
GHGRP, we are proposing to revise emission factors where improved
measurement data has become available or we have received additional
information from stakeholders. Some of the calculation methodologies
provided in the GHGRP rely on the use of emission factors that are
based on published empirical data. The use of default emission factors
decreases the need for additional monitoring or measurements from
individual facilities, while in many cases still providing a reasonably
accurate estimate of facility-level emissions. The proposed rule
includes revisions to emission factors for a number of emission source
types, where we have received or identified updated measurement data.
In cases where there is significant variability in source-level
emissions and the default emission factors are thus not appropriately
representative of facility-level emissions, and other calculation
methodologies are available that are representative of facility-level
emissions, we are proposing to remove default emission factors. For
example, for intermittent bleed pneumatics, we are proposing three new
methodologies for measuring emissions and are therefore proposing to
remove use of default population emission factors for calculating
emissions.
We are proposing to update the emission factors for continuous low
and high bleed natural gas pneumatic devices and for equipment leaks
from natural gas distribution sources (including pipeline mains and
services, below grade transmission-distribution transfer stations, and
below grade metering-regulating stations) and equipment at onshore
petroleum and natural gas production and onshore petroleum and natural
gas gathering and boosting facilities in subpart W. The proposed
emission factors are more representative of GHG emissions sources and
would improve the overall accuracy of the emission data collected under
the GHGRP. Additional details of these types of proposed changes may be
found in section III of this preamble.
In addition to the methods discussed above, we reviewed measurement
approaches that utilize information from satellite, aerial, and
continuous monitoring (``top-down approaches'') to detect and/or
quantify emissions from petroleum and natural gas systems for the
purposes of subpart W reporting. Top-down technologies have been a
focus for research and emission monitoring strategies, and the
technologies have progressed in recent years to provide reliable
CH<INF>4</INF> emission monitoring and quantification in many cases.
Top-down technologies include instruments located on satellites,
aircraft, and mobile platforms. These technologies can also include
Advanced Mobile Leak Detection (AMLD) and other continuous monitoring
sensors. Top-down approaches have certain benefits related to
geographic coverage, repeatability, and periodic measurements.
Depending on the technology (satellite, aircraft, drone), the scale of
observation can provide data useful for quantifying emissions in a
range of cases, from quantifying emissions for a single point source,
such

[[Page 50290]]

as a wellhead, to a basin-wide measurement. This data can be used to
develop emissions estimates for the duration of the observation or can
be used in combination with additional observations or other data
inputs to estimate emissions from a longer time frame. Satellite remote
sensing technologies currently take measurements of concentrations at
altitudes of 400 to 800 kilometers with CH<INF>4</INF> detection limits
of approximately 50 to 25,000 kilograms per hour (kg/hr),\8\ with one
system citing 2 parts per billion (ppb); \9\ high altitude remote
sensing (by airplane) measure at altitudes of 168 to 12,000 meters (m)
with CH<INF>4</INF> detection limits of approximately 1 to 50 kg/hr;
\10\ and low altitude aerial remote sensing (by drone) take
measurements at altitudes of 30 to 150 m with CH<INF>4</INF> detection
ranging from approximately 5 to 250 parts per million (ppm) (depending
on distance).11 12 For remote sensing technologies, the size
of the area monitored is typically inversely related to the detection
levels. Further discussion of our review of top-down technologies is
available in the subpart W TSD, available in the docket for this
rulemaking.
---------------------------------------------------------------------------

\8\ See GHGSat. GHGSat Media Kit. (2021). Available at <a href="https://www.ghgsat.com/upload/misc/GHGSAT_MEDIAKIT_2021.pdf">https://www.ghgsat.com/upload/misc/GHGSAT_MEDIAKIT_2021.pdf</a>; Pandey, S., et
al. ``Satellite observations reveal extreme methane leakage from a
natural gas well blowout.'' Proceedings of the National Academy of
Sciences, Vol. 116, no. 52. Pp. 26376-26381, December 16, 2019,
available at <a href="https://doi.org/10.1073/pnas.1908712116">https://doi.org/10.1073/pnas.1908712116</a>; Jacob, D. J.,
et al. ``Quantifying methane emissions from the global scale down to
point sources using satellite observations of atmospheric methane.''
Atmospheric Chemistry and Physics, Vol. 22, Issue 14, pp. 9617-9646,
July 29, 2022, available at <a href="https://doi.org/10.5194/acp-22-9617-2022">https://doi.org/10.5194/acp-22-9617-2022</a>; Anderson, V., et al. ``Technological opportunities for sensing
of the health effects of weather and climate change: a state-of-the-
art-review.'' International Journal of Biometeorology, Vol. 65,
Issue 6, pp. 779-803, January 11, 2021, available at <a href="https://doi.org/10.1007/s00484-020-02063-z">https://doi.org/10.1007/s00484-020-02063-z</a>. The documents are also available
in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-
0234.
\9\ Anderson et al. (2021).
\10\ See Conrad, B. M., Tyner, D. R. & Johnson, M. R. ``Robust
probabilities of detection and quantification uncertainty for aerial
methane detection: Examples for three airborne technologies.''
Remote Sensing of Environment, Vol. 288, p. 113499, available at
<a href="https://doi.org/10.1016/j.rse.2023.113499">https://doi.org/10.1016/j.rse.2023.113499</a>. 2023; Duren, R. M., et
al. ``California's methane super-emitters.'' Nature, Vol. 575, Issue
7781, pp. 180-184, available at <a href="https://doi.org/10.1038/s41586-019-1720-3">https://doi.org/10.1038/s41586-019-1720-3</a>. 2019; Thorpe, A.K., et al. ``Airborne DOAS retrievals of
methane, carbon dioxide, and water vapor concentrations at high
spatial resolution: application to AVIRIS-NG.'' Atmos. Meas. Tech.,
10, 3833-3850, available at <a href="https://doi.org/10.5194/amt-10-3833-2017">https://doi.org/10.5194/amt-10-3833-2017</a>. 2017; Staebell, C., et al. ``Spectral calibration of the
MethaneAIR instrument.'' Atmospheric Measurement Techniques, Vol.
14, Issue 5, pp. 3737-3753, available at <a href="https://doi.org/10.5194/amt-14-3737-2021">https://doi.org/10.5194/amt-14-3737-2021</a>. 2021. The documents are also available in the
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
\11\ Morales, R., et al. ``Controlled-release experiment to
investigate uncertainties in UAV-based emission quantification for
methane point sources.'' Atmos. Meas. Tech., 15, 2177-2198, <a href="https://doi.org/10.5194/amt-15-2177-2022">https://doi.org/10.5194/amt-15-2177-2022</a>, 2022. Available in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
\12\ Ravikumar, A. P., et al. ``Single-blind inter-comparison of
methane detection technologies--results from the Stanford/EDF Mobile
Monitoring Challenge.'' Elementa: Science of the Anthropocene 1
January 2019; 7 37. doi: <a href="https://doi.org/10.1525/elementa.373">https://doi.org/10.1525/elementa.373</a>.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
---------------------------------------------------------------------------

There have been several studies asserting that bottom-up
CH<INF>4</INF> emission estimates reported by subpart W facilities
underestimate annual CH<INF>4</INF> emissions.\13\ This underestimate
is often attributed to large, often episodic emissions (i.e., super-
emitters).\14\ Emissions estimates developed with remote sensing data
may be more likely to include super-emitters, and therefore, to the
extent that they capture emissions that would not have otherwise been
included under prior GHGRP regulations, they can demonstrate where
existing reporting data may underestimate total emissions. Some top-
down approaches have a demonstrated ability to provide data useful for
quantifying emissions from very large, distinct emission events, such
as production well blowouts. In the U.S. GHG Inventory, the EPA has
already incorporated emissions estimates developed from such approaches
to calculate emissions from well blowouts.\15\ In this proposal, data
from such approaches could be used to identify and/or calculate
emission rates of other large release events (see section III.B of this
preamble).
---------------------------------------------------------------------------

\13\ See, e.g., Caulton, et al. ``Toward a better understanding
and quantification of methane emissions from shale gas
development.'' Proceedings of the National Academy of Sciences, Vol.
111, Issue 17, pp. 6237-6242, available at <a href="https://doi.org/10.1073/pnas.1316546111">https://doi.org/10.1073/pnas.1316546111</a>. 2014; Alvarez, et al. ``Quantifying Regional
Methane Emissions in the New Mexico Permian Basin with a
Comprehensive Aerial Survey.'' Environmental Science & Technology,
Vol. 56, Issue 7, pp. 4317-4323, available at <a href="https://doi.org/10.1126/science.aar7204">https://doi.org/10.1126/science.aar7204</a>. 2018; Zhang, et al. ``Quantifying methane
emissions from the largest oil-producing basin in the United States
from space.'' Science Advances, Vol. 6, Issue 17, available at
<a href="https://doi.org/10.1126/sciadv.aaz5120">https://doi.org/10.1126/sciadv.aaz5120</a>. 2020. The documents are also
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
\14\ See, e.g., Zavala-Ariaza, et al. ``Reconciling divergent
estimates of oil and gas methane emissions.'' Proceedings of the
National Academy of Sciences, Vol. 112, Issue 51, pp. 15597-15602,
available at <a href="https://doi.org/10.1073/pnas.1522126112">https://doi.org/10.1073/pnas.1522126112</a>. 2017;
Cusworth, et al. ``Intermittency of Large Methane Emitters in the
Permian Basin.'' Environmental Science & Technology Letters, Vol. 8,
Issue 7, pp. 567-573, available at <a href="https://doi.org/10.1021/acs.estlett.1c00173">https://doi.org/10.1021/acs.estlett.1c00173</a>. 2021; Chen, et al. ``Quantifying Regional
Methane Emissions in the New Mexico Permian Basin with a
Comprehensive Aerial Survey.'' Environmental Science & Technology,
Vol. 56, Issue 7, pp. 4317-4323, available at <a href="https://doi.org/10.1021/acs.est.1c06458">https://doi.org/10.1021/acs.est.1c06458</a>. 2022; Wang, et al. ``Multiscale Methane
Measurements at Oil and Gas Facilities Reveal Necessary Frameworks
for Improved Emissions Accounting.'' Environmental Science &
Technology, Vol. 56, Issue 20, pp. 14743-14752, available at <a href="https://doi.org/10.1021/acs.est.2c06211">https://doi.org/10.1021/acs.est.2c06211</a>. 2022. The documents are also
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
\15\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2020: Updates for Anomalous Events including Well Blowout
and Well Release Emissions. April 2022. Available at <a href="https://www.epa.gov/system/files/documents/2022-04/2022_ghgi_update_-_blowouts.pdf">https://www.epa.gov/system/files/documents/2022-04/2022_ghgi_update_-_blowouts.pdf</a> and in the docket for this rulemaking, Docket Id. No.
EPA-HQ-OAR-2023-0234.
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In this proposal, the EPA is proposing to include emissions from
large emissions events and super-emitters in the subpart W reporting
program. This proposed addition would directly address the concerns
identified by a multitude of studies about the contribution of super-
emitters to total emissions and help to ensure the completeness and
accuracy of emissions reporting data. The top-down monitoring
approaches that have demonstrated their accuracy and ability to
identify such events are a central feature of the proposed changes.
This top-down data may also help to flag areas where there is a large
gap between the bottom-up CH<INF>4</INF> emissions estimates and the
top-down measurement data, requiring facilities to revise emission
estimates. In this proposal, we are proposing to require facilities to
consider notifications of potential super-emitter emissions event under
the super-emitter provisions of NSPS OOOOb at 40 CFR 60.5371b and
calculate associated events when they exceed our proposed thresholds if
they are not already accounted for under another source category in
subpart W. We expect that under the proposed methodology for other
large release events in this proposal, data from some top-down
approaches, including data derived from equipment leak and fugitive
emissions monitoring using advanced screening methods which is
conducted under NSPS OOOOb or the applicable approved state plan or
applicable Federal plan in 40 CFR part 62, in combination with other
empirical data, could be used by reporters to calculate the total
emissions from these events and/or estimate duration of such an event.
While this top-down data is very useful in identifying possible
large emissions events that are not captured by other reporting
obligations, it is not presently able to provide annual emissions data
to the degree of accuracy and certainty required by other provisions of
this rulemaking. It is not

[[Page 50291]]

currently possible to use remote sensing data as the only basis to
extrapolate annual emissions data. Most top-down, facility measurements
are taken over limited durations (a few minutes to a few hours)
typically during the daylight hours and limited to times when specific
meteorological conditions exist (e.g., no cloud cover for satellites;
specific atmospheric stability and wind speed ranges for aerial
measurements). These direct measurement data taken at a single moment
in time may not be representative of the annual CH<INF>4</INF>
emissions from the facility, given that many emissions are episodic. If
emissions are found during a limited duration sampling, that does not
necessarily mean they are present for the entire year. And if emissions
are not found during a limited duration sampling, that does not mean
significant emissions are not occurring at other times. Extrapolating
from limited measurements to an entire year therefore creates risk of
either over or under counting actual emissions.
While top-down measurement methods, including satellite and aerial
methods, have proven their ability to identify and measure large
emissions events, their detection limits may be too high to detect
emissions from sources with relatively low emission rates.\16\ The data
provided by some of these technologies are at large spatial scales,
with limited ability to disaggregate to the facility- or emission
source-level and have high minimum detection limits. So while these
technologies can provide very useful information about emissions during
snapshots in time, and thus help to greatly improve the completeness
and accuracy of emission reporting, they generally cannot by themselves
estimate annual emissions. This rule proposes to use these top-down
methods to supplement the other requirements for periodic measurement
and calculation of annual emissions.
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\16\ Duren, et al. ``California's methane super-emitters.''
Nature, Vol. 575, Issue 7781, pp. 180-184, available at <a href="https://doi.org/10.1038/s41586-019-1720-3">https://doi.org/10.1038/s41586-019-1720-3</a>. 2019. Available in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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In addition to the proposed use of top-down data to help identify
and quantify super-emitter and other large emissions events, we invite
comment on whether there are other appropriate uses of top-down data
for the purposes of reporting under subpart W of the GHGRP, including
what types of emission sources and emission events, what specific top-
down methods may be appropriate, especially in terms of spatial scale
and minimum detection limits. As described above, the different types
of top-down data have a wide range of detection limits and spatial
resolution, which makes it difficult to reliably convert point
estimates to an annual emissions estimate as required by the GHGRP.
Therefore, this proposal does not propose using top-down approaches for
sources other than besides other large release events due to the
limitations described earlier in this section. However, we invite
comment on whether there are top-down approaches that could be used to
estimate annual emissions for any source categories under subpart W or
for facility-level emissions, what level of accuracy should be required
for such use, and whether the development of standards (either by the
EPA or third-party organizations) could help inform this determination.
We also invite comment on how frequently measurements would need to be
conducted to be considered reliable or representative of annual
emissions for reporting purposes.
We invite comment on how best to combine top-down data with bottom-
up methods in a way that avoids double counting of emissions. For
example, top-down data may be used to refine emission estimates for
particular sources or for the facility. We also seek comment on the
best methods to estimate duration of events measured using top-down
measurements and extrapolation to annual emissions. We also invite
comment on the associated modeling necessary to incorporate top-down
data and the associated uncertainties for calculating facility-level
emissions. We also request comment on how to account for the types of
limitations described in this section.

C. Revisions to Reporting Requirements To Improve Verification and
Transparency of the Data Collected

The EPA is proposing several revisions to existing reporting
requirements to collect data that would improve verification of
reported data and ensure accurate reporting of emissions or improve the
transparency of the data collected. Such revisions would better enable
the EPA to obtain data that is of sufficient quality and granularity
that it can be used to support a range of future climate change
policies and regulations under the CAA, including but not limited to
information relevant to carrying out CAA section 136, provisions
involving research, evaluating and setting standards, endangerment
determinations, or informing EPA non-regulatory programs under the CAA.
We are proposing to add or revise reporting requirements to better
characterize the emissions for several emission sources. For example,
we are proposing to collect additional information from facilities with
liquids unloadings to differentiate between manual and automated
unloadings.
Other proposed revisions to the rule include changes that would
better align reporting with the calculation methods in the rule. For
example, we are proposing to revise reporting requirements related to
atmospheric pressure fixed roof storage tanks receiving hydrocarbon
liquids that follow the methodology specified in 40 CFR 98.233(j)(3)
and equation W-15. The current calculation methodology uses population
emission factors and the count of applicable separators, wells, or non-
separator equipment to determine the annual total volumetric GHG
emissions at standard conditions. The associated reporting requirements
in existing 40 CFR 98.236(j)(2)(i)(E) and (F) require reporters to
delineate the counts used in equation W-15. Based on feedback from
reporters, the EPA's assessment in this proposal is that the reporting
requirements are inconsistent with the language used in the calculation
methodology and are not inclusive of all equipment to be included.
Therefore, we are proposing to revise the reporting requirements to
better align the requirement with the calculation methodology and
streamline the requirements for all facilities reporting atmospheric
storage tanks emissions using the methodology in 40 CFR 98.233(j)(3).
In some cases, we are proposing to remove duplicative reporting
elements within or across GHGRP subparts to reduce data inconsistencies
and reporting errors. For example, we are proposing to eliminate
duplicative reporting between subpart NN (Suppliers of Natural Gas and
Natural Gas Liquids) and subpart W where both subparts require similar
data elements to be reported to the electronic Greenhouse Gas Reporting
Tool (e-GGRT). For instance, for fractionators of natural gas liquids
(NGLs), both subpart W (under the Onshore Natural Gas Processing
segment) and subpart NN require reporting of the volume of natural gas
received and the volume of NGLs received. The proposed amendments would
limit the reporting of these data elements to facilities that do not
report under subpart NN, thus removing the duplicative requirements
from subpart W for facilities that report to both subparts. This would
improve the EPA's ability to verify the reported data across subparts.

[[Page 50292]]

D. Technical Amendments, Clarifications, and Corrections

We are proposing other technical amendments, corrections, and
clarifications that would improve understanding of the rule. These
revisions primarily include revisions of requirements to better reflect
the EPA's intent or editorial changes. Some of these proposed changes
result from consideration of questions raised by reporters through the
GHGRP Help Desk or e-GGRT. In particular, we are proposing amendments
for several source types that would emphasize the original intent of
certain rule requirements, such as reported data elements that have
been misinterpreted by reporters. In several cases, the
misinterpretation of these provisions may have resulted in reporting
that is inconsistent with the rule requirements. The proposed
clarifications would increase the likelihood that reporters will submit
accurate reports the first time. For example, the EPA is proposing to
revise the definition of variable ``T<INF>t</INF>'' in existing
equation W-1 (proposed equation W-1B) in 40 CFR 98.233 and the
corresponding reporting requirements in proposed 40 CFR
98.236(b)(4)(ii)(C)(4), (b)(4)(iii)(C)(3), and (b)(5)(i)(C)(2) to use
the term ``in service (i.e., supplied with natural gas)'' rather than
``operational'' or ``operating.'' This proposed revision would
emphasize the EPA's intent that the average number of hours used in
equation W-1 should be the number of hours that the devices of a
particular type are in service (i.e., the devices are receiving a
measurement signal and connected to a natural gas supply that is
capable of actuating a valve or other device as needed). These proposed
clarifications and corrections would also reduce the burden associated
with reporting, data verification, and EPA review. Additional details
of these types of proposed changes are discussed in section III of this
preamble.
We are also proposing to revise applicability provisions for
certain industry segments and applicable calculation methods. For
example, we are proposing to revise the definition of the Onshore
Natural Gas Processing industry segment to remove the gas throughput
threshold so that the applicable industry segment and calculation
methods are defined from the beginning of the year. The current
definition of the Onshore Natural Gas Processing industry segment
includes processing plants that fractionate gas liquids and processing
plants that do not fractionate gas liquids but have an annual average
throughput of 25 million standard cubic feet (MMscf) per day or
greater. Processing plants that do not fractionate gas liquids and have
an annual average throughput of less than 25 MMscf per day may be part
of a facility in the Onshore Petroleum and Natural Gas Gathering and
Boosting industry segment. Processing plants that do not fractionate
gas liquids and generally operate close to the 25 MMscf per day
threshold do not know until the end of the year whether they will be
above or below the threshold, so they must be prepared to report under
whichever industry segment is ultimately applicable. Therefore, as
discussed in greater detail in section III.A.3 of this preamble, we are
proposing to revise the Onshore Natural Gas Processing industry segment
definition in 40 CFR 98.230(a)(3) to remove the 25 MMscf per day
threshold and more closely align subpart W with the definitions of
natural gas processing in other rules (e.g., NSPS OOOOa). This proposed
revision to the Onshore Natural Gas Processing industry segment
definition would better define whether a processing plant would be
classified as an Onshore Natural Gas Processing facility or as part of
an Onshore Petroleum and Natural Gas Gathering and Boosting facility,
and the applicable segment would not have the potential to change from
one year to the next simply based on the facility throughput.
Additional details of these types of proposed changes may be found
in section III of this preamble.
Other minor changes being proposed include correction edits to fix
typos, minor clarifications such as adding a missing word, harmonizing
changes to match other proposed revisions, reordering of paragraphs so
that a larger number of paragraphs need not be renumbered, and others
as reflected in the draft proposed redline regulatory text in the
docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-2023-0234).

III. Proposed Amendments to 40 CFR Part 98

This section summarizes the specific substantive amendments
proposed for subpart W (as well as subparts A and C), as generally
described in section II of this preamble. Section III.A describes
amendments that affect reporting responsibility or applicability.
Sections III.B through III.U of this preamble describe proposed
technical amendments that would affect specific source types or
industry segments. We are also proposing the miscellaneous subpart W
technical corrections and clarifications listed in section III.V of
this preamble. We are also proposing related confidentiality
determinations for new or revised data elements that result from these
proposed amendments, as discussed in section V of this preamble. The
impacts of the proposed revisions are summarized in section VI of this
preamble. A full discussion of the cost impacts for the proposed
revisions may be found in the memorandum, Assessment of Burden Impacts
for Proposed Revisions for the Greenhouse Gas Reporting Rule available
in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.

A. General and Applicability Amendments

1. Ownership Transfer
When there is a change in ownership for facilities reported under
the GHGRP, the provisions of existing 40 CFR 98.4(h) describe the
responsibilities of the owners and operators. However, asset
transactions between owners and operators sometimes involve only some
emission sources at the facility rather than the entire facility,
particularly in the Onshore Petroleum and Natural Gas Production and
Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments in subpart W (which are two of the industry segments that have
unique definitions of ``facility''). In those cases, reporters have
submitted numerous questions to the GHGRP Help Desk requesting guidance
regarding which owner or operator should report for the year in which
the transaction occurred as well as which owner or operator is
responsible for submitting revisions and responding to questions from
the EPA regarding previous annual GHG reports. To assist manufacturers
regarding some of these questions, the EPA previously developed
Frequently Asked Questions (FAQ) Q749.\17\ However, neither the FAQ nor
the existing requirements in subpart A explicitly explain the
responsibilities for the situations for which reporters have requested
guidance.
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\17\ U.S. EPA. Q749: ``What are the notification requirements
when an Onshore Petroleum and Natural Gas Production facility,
reporting under subpart W, sells wells and associated equipment in a
basin?'' September 26, 2019. <a href="https://ccdsupport.com/confluence/pages/viewpage.action?pageId=198705183">https://ccdsupport.com/confluence/pages/viewpage.action?pageId=198705183</a>. Note that although FAQ Q749
specifically describes facilities in the Onshore Petroleum and
Natural Gas Production segment, the EPA does consider the scenarios
described to be relevant to the Onshore Petroleum and Natural Gas
Gathering and Boosting industry segment as well, because facilities
in both segments are defined at the basin level rather than at the
level of the subpart A definition of facility.
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Therefore, the EPA is proposing to add specific provisions to
subpart A in

[[Page 50293]]

a proposed new paragraph 40 CFR 98.4(n) that would apply in lieu of
existing 40 CFR 98.4(h) for changes in the owner or operator of a
facility in the four industry segments in subpart W (Petroleum and
Natural Gas Systems) that have unique definitions of facility. The
proposed provisions would define which owner or operator is responsible
for current and future reporting years' reports and clarify how to
determine responsibility for revisions to annual reports for reporting
years prior to owner or operator changes for specific industry segments
in subpart W, beginning with RY2025 reports. The proposed provisions
would also specify when an owner or operator would submit an annual
report using an e-GGRT identifier assigned to an existing facility and
when an owner or operator would register a new facility in e-GGRT. As
described in more detail in this section, the provisions would vary
based upon whether the selling owner or operator would retain any
emission sources, the number of purchasing owners or operators, and
whether the purchasing owners or operators already report to the GHGRP
in the same industry segment and basin or state (as applicable). These
proposed revisions are expected to improve data quality as described in
section II.C of this preamble by ensuring that the EPA receives a more
complete data set, and they are also expected to improve understanding
of the rule, as described in section II.D of this preamble.
We expect all the transactions fall into one of four general
categories, and we are proposing provisions that would define the
responsibilities for reporting for each of those general categories.
First, if the entire facility is sold to a single purchaser and the
purchasing owner or operator does not already report to the GHGRP in
that industry segment (and basin or state, as applicable), then we are
proposing that the facility's certificate of representation must be
updated within 90 days of the transaction to reflect the new owner or
operator. In other words, the e-GGRT identifier and associated facility
within e-GGRT would be transferred from the seller to the purchaser.
The purchasing owner or operator would be responsible for submitting
the facility's annual report for the entire reporting year in which the
acquisition occurred (i.e., the owner or operator as of December 31
would be responsible for the report for that entire reporting year) and
each reporting year thereafter. In addition, because the definitions of
facility for each of these segments encompass all of the emission
sources in a particular geographic area (i.e., basin, state, or
nation), the purchasing owner or operator would include any other
applicable emission sources already owned by that purchasing owner or
operator in the same geographic area as part of the purchased facility
beginning with the reporting year in which the acquisition occurred.
The purchasing owner or operator would also become responsible for
responding to EPA questions and making any necessary revisions to
annual GHG reports for reporting years prior to the reporting year in
which the acquisition occurred. This scenario is the most similar to
ownership transfer for facilities in other subparts, and this proposed
amendment would specify that the responsibility for reporting should be
similar to the existing requirements for all subparts.
Second, if the entire facility is sold to a single purchaser and
the purchasing owner or operator already reports to the GHGRP in that
industry segment (and basin or state, as applicable), then we are
proposing that the purchasing owner or operator would merge the
acquired facility with their existing facility for purposes of
reporting under the GHGRP. In other words, the acquired facility would
become part of the purchaser's existing facility under the GHGRP and
emissions for the combined facility would be reported under the e-GGRT
identifier for the purchaser's existing facility. The purchaser would
update the acquired facility's certificate of representation within 90
days of the transaction to reflect the new owner or operator. The
purchaser would then follow the provisions of 40 CFR 98.2(i)(6) to
notify the EPA that the purchased facility has merged with their
existing facility and would provide the e-GGRT identifier for the
merged, or reconstituted, facility. Finally, the purchaser would be
responsible for submitting the merged facility's annual report for the
entire reporting year in which the acquisition occurred (i.e., the
owner or operator as of December 31 would be responsible for the report
for that entire reporting year) and each reporting year thereafter. The
purchasing owner or operator would also become responsible for
responding to EPA questions and making any necessary revisions to
annual GHG reports for the purchased facility for reporting years prior
to the reporting year in which the acquisition occurred. In this
scenario, an entire facility is changing ownership, and this proposed
amendment would specify that the responsibility for reporting should be
similar to the existing requirements for all subparts.
Third, if the selling owner or operator retains some of the
emission sources and sells the other emission sources of the seller's
facility to one or more purchasing owners or operators, we are
proposing that the selling owner or operator would continue to report
under subpart W for the retained emission sources unless and until that
facility meets one of the criteria in 40 CFR 98.2(i) and complies with
those provisions. Each purchasing owner or operator that does not
already report to the GHGRP in that industry segment (and basin or
state, as applicable) would begin reporting as a new facility for the
entire reporting year beginning with the reporting year in which the
acquisition occurred. The new facility would include the acquired
applicable emission sources as well as any previously owned applicable
emission sources. We note that, under the proposed provisions, because
the new facility would contain acquired emission sources that were part
of a facility that was subject to the requirements of part 98 and
already reporting to the GHGRP, the purchasing owner or operator would
follow the provisions of 40 CFR 98.2(i) and continue to report unless
and until one of the criteria in 40 CFR 98.2(i)(1) through (6) are met,
instead of comparing the facility's emissions to the reporting
threshold in 40 CFR 98.231(a) to determine if they should begin
reporting. Each purchasing owner or operator that already reports to
the GHGRP in that industry segment (and basin or state, as applicable)
would add the acquired applicable emission sources to their existing
facility for purposes of reporting under subpart W and would be
responsible for submitting the annual report for their entire facility,
including the acquired emission sources, for the entire reporting year
beginning with the reporting year in which the acquisition occurred.
Fourth, if the selling owner or operator does not retain any of the
emission sources and sells all of the facility's emission sources to
more than one purchasing owner or operator, we are proposing that the
selling owner or operator for the existing facility would notify the
EPA within 90 days of the transaction that all of the facility's
emission sources were acquired by multiple purchasers. The purchasing
owners or operators would begin submitting annual reports for the
acquired emission sources for the reporting year in which the
acquisition occurred following the same provisions as in the third
scenario. In other words, each owner or operator would either

[[Page 50294]]

begin reporting their acquired applicable emission sources as a new
facility or add the acquired applicable emission sources to their
existing facility.
Finally, for the third and fourth types of transactions, we are
proposing one set of provisions to clarify responsibility for annual
GHG reports for reporting years prior to the reporting year in which
the acquisition occurred. This set of proposed provisions would apply
to annual GHG reports for facilities where these types of transactions
occur after the effective date of the final amendments, if adopted. In
other words, if the effective date of the final amendments is January
1, 2025, as described in section V of this preamble, then for ownership
transactions that occur on or after January 1, 2025, we are proposing
that the proposed requirements for the current and future reporting
years described in the previous paragraphs would apply. In addition,
the proposed provisions for annual GHG reports for reporting years
prior to the transaction would also apply. For example, if an ownership
transaction occurs on June 30, 2027, then the selling owner or operator
and purchasing owner or operator would follow the proposed applicable
provisions previously described in this section for the RY2027 report
and for future reporting years. In this example scenario, the proposed
provisions described in the next paragraph would apply for RY2026 and
prior years' reports.
Specifically, we are proposing that as part of the third and fourth
types of ownership change described previously in this section, the
selling owner or operator and each purchasing owner or operator would
be required to select by an agreement binding on the owners and
operators (following the procedures specified in 40 CFR 98.4(b)) a
``historic reporting representative'' that would be responsible for
revisions to annual GHG reports for previous reporting years within 90
days of the transaction. The EPA expects that the agreement regarding
the historic reporting representative would be entered into at the time
of the acquisition and that if the representative responsible for
revisions to annual GHG reports is not employed by the selling owner or
operator, copies of the records required to be retained per 40 CFR
98.3(g) and (h) would be transferred to the historic reporting
representative at that time. The historic reporting representative for
each facility that would respond to any EPA questions regarding GHG
reports for previous reporting years and would submit corrected
versions of GHG reports for previous reporting years as needed. In many
situations, the EPA expects that the purchaser would agree to select a
historic reporting representative to address revisions to previous
years' annual GHG reports. In particular, there may be cases in which
the selling owner or operator's company will no longer be operating
after the transaction, so it may be appropriate for one of the
purchasing owners or operators to select that historic reporting
representative. In other situations, the parties may determine that it
is appropriate for the seller to select the historic reporting
representative to address revisions to annual GHG reports for reporting
years prior to the reporting year in which the acquisition occurred. In
the 2022 Proposed Rule, the EPA proposed that if this historic
reporting representative is not the current designated representative
for the facility, the historic reporting representative would need to
be appointed as the alternate designated representative or an agent for
the facility. However, in some cases this could provide that individual
with access to the facility's data for reporting years other than the
previous reporting years for which that individual is responsible,
including potentially confidential or sensitive information and
correspondence. Therefore, the EPA is not proposing to specify that the
historic reporting representative would be required to be appointed as
the alternate designated representative or an agent for the facility.
Finally, we are proposing to amend 40 CFR 98.2(i)(3), the current
provision that allows an owner or operator to discontinue reporting to
the GHGRP when all applicable processes and operations cease to
operate. Through correspondence with reporters via e-GGRT, we are aware
that there have been times that an owner or operator divested a
facility and was therefore no longer required to report the emissions
from that facility, but even though the facility changed owners and did
not cease operating, the selling owner or operator chose the provisions
of existing 40 CFR 98.2(i)(3) as the reason they were ceasing to report
because none of the other options fit the situation. The EPA's intent
is that this reason for no longer reporting to the GHGRP should only be
used in cases in which all the applicable sources permanently ceased
operation. Therefore, we are proposing to clarify that 40 CFR
98.2(i)(3) would not apply when there is a change in the owner or
operator for facilities in these four industry segments, unless the
changes result in permanent cessation of all applicable processes and
operations.
2. Definition of ``Owner'' and ``Operator''
We are also proposing to amend 40 CFR 98.1(c) to clarify that the
terms ``owner'' and ``operator'' used in subpart A have the same
meaning as the terms ``gathering and boosting system owner or
operator'' and ``onshore natural gas transmission pipeline owner or
operator'' for the Onshore Petroleum and Natural Gas Gathering and
Boosting and Onshore Natural Gas Transmission Pipeline industry
segments of subpart W, respectively. This paragraph was inadvertently
not amended when those two industry segments and the industry segment-
specific definitions of owner or operator were added to subpart W (80
FR 64275, October 22, 2015), and this proposed amendment would correct
that oversight, consistent with section II.D of this preamble.
3. Onshore Natural Gas Processing Industry Segment Definition
According to existing 40 CFR 98.230(a)(3), the Onshore Natural Gas
Processing industry segment currently includes all facilities that
fractionate NGLs. The industry segment also includes all facilities
that separate NGLs from natural gas or remove sulfur and carbon dioxide
(CO<INF>2</INF>) from natural gas, provided the annual average
throughput at the facility is 25 MMscf per day or greater. The industry
segment also includes all residue gas compression equipment owned or
operated by natural gas processing facilities that is not located
within the facility boundaries.
One stakeholder expressed concern that the current definition of
the Onshore Natural Gas Processing industry segment applies to some
compressor stations simply because they have an amine unit that is used
to remove sulfur and CO<INF>2</INF> from natural gas.\18\ According to
this stakeholder, it would be more appropriate for such facilities to
be in the Onshore Petroleum and Natural Gas Gathering and Boosting
industry segment. This stakeholder also explained that the 25 MMscf per
day threshold creates additional burden and uncertainty for these
compressor station facilities because they do not know until the end of
the year whether they will be above or below the threshold. Thus,

[[Page 50295]]

they need to collect the applicable data for both the Onshore Natural
Gas Processing industry segment and the Onshore Petroleum and Natural
Gas Gathering and Boosting industry segment so that they will have the
required data for whichever industry segment ultimately applies to
them. To resolve this issue and to promote consistency among regulatory
programs, this stakeholder recommended replacing the onshore natural
gas processing definition in subpart W with the natural gas processing
plant definition in NSPS OOOOa.
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\18\ Letter from Matt Hite, GPA Midstream Association, to Mark
de Figueiredo, U.S. EPA, Re: Additional Information on Suggested
Part 98, Subpart W Rule Revisions to Reduce Burden. September 13,
2019. Available in the docket for this rulemaking, Docket Id. No.
EPA-HQ-OAR-2023-0234.
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After consideration of this issue, we are proposing to replace the
definition of ``Onshore natural gas processing'' in 40 CFR 98.230(a)(3)
with language similar to the definition of ``natural gas processing
plant'' in NSPS OOOOa. This proposed amendment would improve the
verification and transparency of the data, particularly across
reporting years, consistent with section II.C of this preamble, and it
would provide reporters with certainty about the applicable industry
segment for the reporting year, consistent with section II.D of this
preamble, allowing them to focus their efforts on collecting accurate
monitoring data and emissions information needed for one applicable
industry segment. As explained later in this section, while we expect
that the proposed revisions would result in some facilities reporting
under a different industry segment, we do not expect that the overall
coverage of the GHGRP would decrease. Further, as the stakeholder
noted, the two potentially applicable segments currently report
emissions from different sources and with different calculation
methods. For example, facilities in the Onshore Natural Gas Processing
industry segment are currently not required to report emissions from
natural gas pneumatic devices or atmospheric storage tanks and are
currently required to measure leaks from individual compressors, while
facilities in the Onshore Petroleum and Natural Gas Gathering and
Boosting industry segment are currently required to report emissions
from natural gas pneumatic devices or atmospheric storage tanks but
currently use population emission factors to calculate emissions from
all compressors rather than conducting measurements. However, the
proposed addition of emission sources to the Onshore Natural Gas
Processing industry segment (as described in section III.C.1 of this
preamble) would remove the differences in the emission sources reported
by facilities in one industry segment and not the other. The addition
of calculation methodologies for specific emission sources that would
be calculated and reported by facilities in both industry segments
would result in fewer differences between the emissions reported under
the two industry segments.\19\
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\19\ Proposed amendments described throughout the remainder of
this preamble would reduce the differences in calculation
methodologies (e.g., see sections III.O and III.P of this preamble),
but there are still expected to be differences even if all the
proposed amendments are finalized. The differences in calculation
methodologies that would remain are due to differences in the types
of operations and other factors such as the size of the ``facility''
between the two industry segments. In particular, facilities in the
Onshore Petroleum and Natural Gas Gathering and Boosting industry
segment can be geographically dispersed, and as such, some
measurement methodologies may be optional rather than required. In
addition, the combustion emissions for facilities in the Onshore
Natural Gas Processing industry segment are reported under subpart
C, while the combustion emissions for facilities in the Onshore
Petroleum and Natural Gas Gathering and Boosting industry segment
are reported under subpart W.
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NSPS OOOOa defines ``natural gas processing plant (gas plant)'' as
any processing site engaged in the extraction of NGLs from field gas,
fractionation of mixed NGLs to natural gas products, or both. The
definition specifies that a Joule-Thompson valve, a dew point
depression valve, or an isolated or standalone Joule-Thompson skid is
not a natural gas processing plant. There are two minor editorial
differences between the proposed definition in 40 CFR 98.230(a) and the
definition in NSPS OOOOa. First, instead of defining a natural gas
processing ``plant,'' as in the definition in NSPS OOOOa, we are
proposing to describe what is meant by ``natural gas processing'' so
that the structure of 40 CFR 98.230(a)(3) is consistent with the
structure of all of the other industry segment definitions in 40 CFR
98.230(a). Second, the definition in NSPS OOOOa refers to
``extraction'' of NGLs from natural gas, but this term is not defined.
Thus, we are proposing to retain the term ``forced extraction'' in the
current provisions of 40 CFR 98.230(a)(3) and proposing to revise the
definition of this term slightly in 40 CFR 98.238. The current
definition of ``forced extraction'' specifies that forced extraction
does not include ``portable dewpoint suppression skids.'' We are
proposing to revise the definition to indicate instead that forced
extraction does not include ``a Joule-Thomson valve, a dewpoint
depression valve, or an isolated or standalone Joule-Thomson skid.''
These changes would make the definition of ``forced extraction'' in
subpart W consistent with the language in the definition of a natural
gas processing plant in NSPS OOOOa.
The proposed amendments to the processes that are considered
``onshore natural gas processing'' are not expected to decrease overall
coverage of the GHGRP for the petroleum and natural gas systems
industry, although we anticipate that some operations currently being
reported as standalone facilities under the Onshore Natural Gas
Processing industry segment would transition to reporting as part of
either existing or new facilities under the Onshore Petroleum and
Natural Gas Gathering and Boosting industry segment, while some
operations currently being reported as part of Onshore Petroleum and
Natural Gas Gathering and Boosting facilities would transition to
reporting as standalone facilities under the Onshore Natural Gas
Processing industry segment. For example, based on reported data for
RY2020, about 19 percent of facilities reporting in the Onshore Natural
Gas Processing industry segment do not fractionate NGLs and report zero
NGLs received and leaving the facility. These facilities meet the
current definition of natural gas processing because they are
separating CO<INF>2</INF> and/or hydrogen sulfide and/or they are
capturing CO<INF>2</INF> separated from natural gas. These facilities
would not meet the proposed revised definition for natural gas
processing and instead, their emissions would be reported as part of
either existing or new onshore petroleum and natural gas gathering and
boosting facilities. In most cases, we anticipate that operations at a
facility that was previously classified by a reporter as a gas
processing facility would be incorporated into an existing gathering
and boosting facility that has been subject to reporting, and the total
emissions from the expanded gathering and boosting facility would be
similar to the emissions that would have been reported by the separate
facilities under the existing industry segment definitions. In cases
where a former gas processing facility is located in a basin where the
owner or operator does not have an existing reporting gathering and
boosting facility, we expect that a new gathering and boosting facility
including the former gas processing facility would be created because
the emissions from the former gas processing facility alone would
exceed the reporting threshold of 25,000 mtCO<INF>2</INF>e. If the same
owner or operator has other gathering and boosting operations in the
same basin that have emissions less than 25,000 mtCO<INF>2</INF>e, then
the new gathering and boosting facility could result in increased
coverage of the industry segment and greater total reported emissions
than would be reported under

[[Page 50296]]

the current industry segment definitions.
The proposed revised definition for natural gas processing also
does not include the 25 MMscf per day threshold for facilities that
separate NGLs from natural gas using forced extraction but do not
fractionate NGLs. Under the current definition of onshore natural gas
processing, processing plants that do not fractionate gas liquids and
generally operate close to the 25 MMscf per day threshold may be
natural gas processing facilities one year and then part of an onshore
petroleum and natural gas gathering and boosting facility the next
year. As noted earlier in this section, the two potentially applicable
segments currently report emissions from different sources and with
different calculation methods. As a result of the current definition,
it can be difficult to track the reporting status of a facility from
one year to the next, and it can be difficult to assess and verify
reporting trends for an individual facility across reporting years.
Under the revised proposed definition, these sites that separate NGLs
from natural gas using forced extraction but do not fractionate NGLs
and generally operate close to 25 MMscf per day would be considered
natural gas processing regardless of their throughput level, so they
would have the certainty of knowing they would be subject to reporting
as natural gas processing facilities every year. As a result, removing
the 25 MMscf per day threshold is expected to increase the number of
sites that consistently report as facilities under the Onshore Natural
Gas Processing industry segment instead of sometimes reporting as part
of a facility that reports under the Onshore Petroleum and Natural Gas
Gathering and Boosting industry segment. We request comment on the
impact the proposed changes would have on the number of reporting
facilities and emissions from both the Onshore Natural Gas Processing
and Onshore Petroleum and Natural Gas Gathering and Boosting industry
segments. We also request comment on any other advantages or
disadvantages to finalizing the proposed changes.
4. Applicability of Proposed Subpart B to Subpart W Facilities
In the supplemental proposal to the 2022 Proposed Rule (88 FR
32852, May 22, 2023), the EPA is proposing to add subpart B to part 98
(Metered, Non-fuel, Purchased Energy Consumption by Stationary Sources)
for reporting the quantity of metered electricity and thermal energy
purchased. The EPA's intent is for this new subpart to apply to
facilities that are required to report direct emissions under another
subpart of the GHGRP, including those facilities in subpart W industry
segments that have a unique definition of facility in 40 CFR 98.238 and
a reporting threshold specified in 40 CFR 98.231. Therefore, the EPA is
proposing to add 40 CFR 98.232(n) (and a reference to this new
paragraph from the introductory text of 40 CFR 98.232) to clarify the
intent for subpart W reporters to also report under subpart B,
consistent with section II.D of this preamble.

B. Other Large Release Events

We are proposing to add an additional emissions source, referred to
as ``other large release events,'' to capture maintenance or abnormal
emission events that are not fully accounted for using existing methods
in subpart W, consistent with section II.A of this preamble. Numerous
studies have indicated that other large release events, commonly
referred to as ``super-emitters,'' significantly contribute to the
emissions from oil and gas facilities and that the current subpart W
understates oil and gas emissions because there is a lack of
calculation and reporting requirements for many of these large
events.\20\ We proposed to include calculation and reporting
requirements for other large release events in the 2022 Proposed Rule,
and this proposal regarding other large release events is very similar
to the 2022 Proposed Rule. The primary difference in this proposal is
that we are including an instantaneous CH<INF>4</INF> emission rate
threshold of 100 kg/hr, in addition to the 250 mtCO<INF>2</INF>e per
event threshold we previously proposed, so there are two proposed
emissions thresholds for determining whether emissions from other large
release events must be reported. We are also proposing to expand the
definition of other large release events to include planned releases,
such as those associated with maintenance activities for which there
are not emission calculation procedures in subpart W. Emptying,
degassing, and cleaning a tank is an example of a maintenance activity
for which emissions would need to be reported under this proposal (if
the emissions exceed the thresholds for an other large release event)
that would not have been required to report under the 2022 Proposed
Rule's definition of other large release event.
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\20\ See, e.g., Zavala-Araiza, D., et al., 2017, Super-emitters
in natural gas infrastructure are caused by abnormal process
conditions, Nat. Commun. 8, 14012, <a href="https://doi.org/10.1038/ncomms14012">https://doi.org/10.1038/ncomms14012</a>; Alavarez, R.A., et al., 2018, Assessment of methane
emissions from the U.S. oil and gas supply chain, Science 361(6398)
186-188, <a href="https://www.science.org/doi/10.1126/science.aar7204">https://www.science.org/doi/10.1126/science.aar7204</a>; Chen,
Y., et al., 2022, Quantifying regional methane emissions in the New
Mexico Permian Basin with a comprehensive aerial survey,
Environmental Science & Technology 56(7) 4317-4323, <a href="https://doi.org/10.1021/acs.est.1c06458">https://doi.org/10.1021/acs.est.1c06458</a>. Available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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Most of the emission sources and methodologies included in subpart
W characterize emissions that routinely occur at oil and gas facilities
as part of their normal operations, including routinely occurring large
emission events, such as blowdowns. While some sources covered by
subpart W methodologies, such as equipment leaks, may represent
``malfunctioning'' equipment, these sources are ubiquitous across the
oil and gas sector and have been studied and characterized and these
types of events have been incorporated into existing subpart W source
methodologies. On the other hand, there have been several large,
atypical release events at oil and gas facilities over the last few
years where it was difficult to sufficiently include these emissions in
annual GHGRP reports. For example, a storage wellhead leak at Aliso
Canyon released approximately 100,000 metric tons (mt) of
CH<INF>4</INF> between October 2015 and February 2016 \21\ and a well
blowout in Ohio released an estimated 40,000 to 60,000 tons of
CH<INF>4</INF> in a 20-day period in 2018.\22\ The emissions from these
types of releases were not well represented using the existing
calculation methodologies in subpart W because these were not common or
predictable events.\23\ For example, subpart W includes a default
emission factor for underground gas storage wellheads to estimate
emissions from leaking storage wellheads; however, the data upon which
that emission factor is based do not include a release of the magnitude
estimated for Aliso Canyon

[[Page 50297]]

because this type of malfunction did not occur during the measurement
study. Recent data summarizing release events from underground storage
facilities indicate that while the Aliso Canyon release was large, it
was not the largest release event from an underground storage facility
and that, over the past 75 years, there have been 129 release events
from underground storage facilities.\24\ The data showed emissions from
these release events are heavy-tailed with event emissions spanning 6
orders of magnitude, indicating that they would not likely be
accurately described by an emission factor. Rather than escalating the
population emission factor for all storage wellheads to account for
these releases, our assessment is that it would be more accurate for
the population emission factor to be based on typical frequency and
size of leaks that commonly occur and to track these uncommon, large
releases separately. Because these events can significantly contribute
to the total GHG emissions from this sector, we are proposing to add,
at 40 CFR 98.232, other large release events as an emission source for
which emissions must be calculated for every industry segment. We are
also proposing new calculation methods for estimating the GHG emissions
from other large release events in 40 CFR 98.233(y) and requirements
for reporting other large release events in 40 CFR 98.236(y). These
proposed additional calculation and reporting requirements would apply
to all subpart W industry segments and would improve the accuracy of
emissions reported under subpart W and enhance the overall quality of
the data collected under the GHGRP.
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\21\ California Air Resources Board. 2016. Determination of
Total Methane Emissions from the Aliso Canyon Natural Gas Leak
Incident. Available at <a href="https://ww2.arb.ca.gov/sites/default/files/2020-07/aliso_canyon_methane_emissions-arb_final.pdf">https://ww2.arb.ca.gov/sites/default/files/2020-07/aliso_canyon_methane_emissions-arb_final.pdf</a>. Available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
\22\ Pandey, S., et al., 2019. Satellite observations reveal
extreme methane leakage from a natural gas well blowout. Proceedings
of the National Academy of Sciences 116(52), 26376-26381. <a href="https://doi.org/10.1073/pnas.1908712116">https://doi.org/10.1073/pnas.1908712116</a>. Available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
\23\ The EPA notes that the full emissions from these events
were included in the U.S. GHG Inventory based on the results of
multiple measurement studies. See U.S. EPA. Inventory of U.S.
Greenhouse Gas Emissions and Sinks 1990-2020: Updates for Anomalous
Events including Well Blowout and Well Release Emissions. April
2022. Available at <a href="https://www.epa.gov/system/files/documents/2022-04/2022_ghgi_update_-_blowouts.pdf">https://www.epa.gov/system/files/documents/2022-04/2022_ghgi_update_-_blowouts.pdf</a> and in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
\24\ Li, H.Z., et al., 2022. A national estimate of U.S.
underground natural gas storage incident emissions. Environ. Res.
Lett. 17(8) 084013. <a href="https://doi.org/10.1088/1748-9326/ac8069">https://doi.org/10.1088/1748-9326/ac8069</a>.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
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The new calculation requirements being proposed rely on measurement
data, if available, or a combination of engineering estimates, process
knowledge, and best available data, when measurement data are not
available. The proposed calculation procedure consists of estimating
the amount of gas released and the composition of the released gas. The
amount of gas released would generally be calculated based on a
measured or estimated emission rate(s) and an event duration. We are
proposing that the start time of the duration must be determined based
on monitored process parameters, such as pressure or temperature, for
which sudden changes in the monitored parameter signals the start of
the event. If the monitored process parameters cannot identify the
start of the event, we are proposing that reporters must assume the
release started on the date of the most recent monitoring or
measurement survey that confirms the source was not emitting at the
rates above the other large release event reporting thresholds or
assume the duration of the event was 182 days (six months), whichever
duration is shorter. We are proposing the end time of the release must
be the date of the confirmed repair or confirmed cessation of
emissions. There may be events that span across two separate reporting
years. In this case, we are proposing that the volume of gas released
specific to each reporting year would be calculated and reported for
that reporting year starting with RY2025.
We request comment on the proposed default duration of 182 days (in
the absence of information on the start time). Studies on large
releases from oil and gas facilities commonly report that these
emissions are intermittent, with typical durations of several hours to
several days,\25\ but in many cases they may be significantly longer,
occurring for weeks or months.\26\ For many releases, such as
maintenance events, fires, explosions, and well blowouts, the reporter
would be able to identify the start and end time of an event. Other
releases may be identified via monitoring surveys or site inspections.
For these the start date can often be identified from process operating
records or previous monitoring results. For identifying the start date,
we are specifically proposing to allow monitoring or measurement
surveys to include methods specified in 40 CFR 98.234(a) through (d) as
well as advanced screening methods such as monitoring systems mounted
on vehicles, drones, helicopters, airplanes, or satellites capable of
identifying emissions at the thresholds specified for an other large
release event. However, there will be some releases for which the start
date cannot be determined. We selected a 182-day default duration as
this duration would include the majority of these types of events. We
expect that facilities will typically estimate durations based on the
monitoring of operating conditions, with more frequent monitoring or
measurement surveys, as described above, resulting in infrequent use of
the default. We recognize that the 182-day default duration may cause
revisions to reports submitted for previous reporting years in some
cases; however, we expect that these revisions would be made prior to
the final verification of the reports for a given reporting year and
should not have significant implications on being able to calculate the
event emissions and submit revised reports, if needed, prior to the
time waste emission filings, if applicable, are due. We request comment
on the 182-day default duration and ability to revise, if necessary,
subpart W reports prior to the final verification of reports for a
given reporting year.
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\25\ See, e.g., Chen, et al., Quantifying Regional Methane
Emissions in the New Mexico Permian Basin with a Comprehensive
Aerial Survey. Environmental Science & Technology (Vol. 56, Issue 7,
pp. 4317-4323), available at <a href="https://doi.org/10.1021/acs.est.1c06458">https://doi.org/10.1021/acs.est.1c06458</a>. 2022; Wang, et al., Multiscale Methane Measurements
at Oil and Gas Facilities Reveal Necessary Frameworks for Improved
Emissions Accounting. Environmental Science & Technology (Vol. 56,
Issue 20, pp. 14743-14752), available at <a href="https://doi.org/10.1021/acs.est.2c06211">https://doi.org/10.1021/acs.est.2c06211</a>. 2022. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
\26\ See, e.g., Frequently Asked Questions: Aliso Canyon Gas
Storage Facility. Public Utilities Commission, State of California,
January 26, 2021. <a href="https://www.cpuc.ca.gov/regulatory-services/safety/gas-safety-and-reliability-branch/aliso-canyon-well-failure">https://www.cpuc.ca.gov/regulatory-services/safety/gas-safety-and-reliability-branch/aliso-canyon-well-failure</a>;
Cusworth, et al., 2021, Multisatellite imaging of a gas well blowout
enables quantification of total methane emissions. Geophysical
Research Letters, 48, e2020GL090864. <a href="https://doi.org/10.1029/2020GL090864">https://doi.org/10.1029/2020GL090864</a>; and Maasakkers, J.D., et al., 2019. Reconstructing and
quantifying methane emissions from the full duration of a 38-day
natural gas well blowout using space-based observations. Remote
Sensing of Environment. 112755. <a href="https://doi.org/10.1016/j.rse.2021.112755">https://doi.org/10.1016/j.rse.2021.112755</a>. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
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We also request comment on using other default durations.
Specifically, we request comment on using a 91-day (3-month) default
duration rather than 182-day duration, as well as on other potential
default durations. We seek information to support default duration
assumptions. We request comment on whether a 91-day default duration
would be reasonable. We also request comment on using the beginning of
the calendar year as the default duration. Using the beginning of the
year as the default duration would eliminate issues regarding potential
revisions to previously submitted reports, but it would lead to
inconsistent reporting of emissions from similar types of events based
on when the event occurred (or was identified) in the calendar year.
For other large release events with an identifiable start date in
reporting year 1 and identifiable end date in reporting year 2, some
reporters may know of the release on the day it started and other
reporters may not identify the release until late in the overall
duration. If the reporter knows of the event in reporting year 1, then
the reporter would be obligated to report the emissions that occurred
from this event in each

[[Page 50298]]

reporting year. However, if the reporter does not become aware of the
release until the second reporting year, using the start of the year as
the beginning of the default duration would result in the reporter only
being required to report the emissions from the other large release
event that occurred in reporting year 2, resulting in underreported
emissions.
We also considered hybrid alternatives where the reporter would
have to evaluate company records to identify the start date and use the
actual start date if known but use the start of the calendar year if
not known. While there is an incentive for the reporter to review
records in reporting year 2 to identify if the release event began
prior to the first day of the calendar year, there would not be a
similar incentive for the reporter to review records in the previous
reporting year (reporting year 1). Instead, if waste emission charges
may apply, there would be an incentive to simply use the default of the
beginning of the year and not review records past this date. Under this
hybrid alternative, we would need to specify how many months of records
reporters would be required to review to determine the start date of
the event. We considered both 182 and 365 days of records required to
be reviewed under this alternative hybrid approach. After considering
these various scenarios, we selected the 182-day maximum duration and
event reporting across reporting years to be the most accurate and
reasonable option, but we request comment on the other options
considered as described in this section. We also seek comment on other
options that may be used to obtain accurate reporting of other large
release event emissions that span reporting years.
We recognize that some natural gas releases, such as explosions or
fires, will combust or partially combust the natural gas released. We
are proposing that reporters must estimate the portion of the total
volume of natural gas released that was combusted in the explosion or
fire in order to determine the average composition of GHG released to
the atmosphere during the event. For the portion of natural gas
released via combustion in an explosion or fire, we are proposing a
maximum combustion efficiency of 92 percent be assumed. This maximum
combustion efficiency is consistent with the combustion efficiency we
are proposing for flares that are not continuously monitored as
described in section III.N.1 of this preamble. We recognize that
because these releases are not through engineered nozzles that can be
designed to promote mixing and combustion efficiency, the combustion
efficiency of these releases can be highly variable. Reporters may use
a lower combustion efficiency but may not use higher combustion
efficiency than 92 percent for natural gas released directly in an
explosion or fire. We request comment on these proposed provisions. We
request comment and supporting data on the proposed maximum combustion
efficiency of 92 percent for the portion of the total volume of natural
gas released via explosion or fire.
The proposed requirement to calculate and report GHG emissions from
other large release events would be limited to events that release at
least 250 mtCO<INF>2</INF>e per event or have a CH<INF>4</INF> emission
rate of 100 kg/hr or greater at any point in time. The 250
mtCO<INF>2</INF>e per event threshold is equivalent to approximately
500,000 standard cubic feet (scf) of pipeline quality natural gas. For
events that span two reporting years, we are proposing that these
thresholds apply to the event, not a portion of the event within a
given reporting year. We selected these proposed thresholds to capture
reporting for large emission events, such as well blowouts, well
releases, and large pressure relief venting.
In order to establish the mass CO<INF>2</INF>e per event reporting
threshold, we assessed other emission sources that could qualify as
large. Specifically, we considered completions of hydraulically
fractured wells that are not controlled (i.e., not performed using
reduced emission completions (RECs)) to be large emissions events. RECs
are completions where gas flowback emissions from the gas outlet of the
separator that are otherwise vented are captured, cleaned, and routed
to the flow line or collection system, re-injected into the well or
another well, used as an on-site fuel source, or used for other useful
purpose that a purchased fuel or raw material would serve, with de
minimis direct venting to the atmosphere. Based on analysis of GHGRP
data for wells that are not RECs and that vent, the U.S. GHG Inventory
developed an average emission factor of about 360 mtCO<INF>2</INF>e per
event for these completions.\27\ Because this is an average emission
factor, some uncontrolled hydraulically fractured completions will be
below this average and some above. From this assessment, we considered
250 mtCO<INF>2</INF>e to be a reasonable emissions threshold for a
``large'' event.
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\27\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2014. EPA 430-R-16-002. April 2016. Available at <a href="https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2014">https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2014</a> and in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2023-0234.
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While 250 mtCO<INF>2</INF>e is much lower than the emissions from
the Aliso Canyon or Ohio well blowout releases, we determined that a
250 mtCO<INF>2</INF>e threshold would be needed to capture most well
blowouts. There are limited data to quantify an ``average'' well
blowout, but the 2021 U.S. GHG Inventory uses an oil well blowout
emission factor of 2.5 MMscf per event. As this is an average, many
well blowouts may be less than this average value. The 250
mtCO<INF>2</INF>e threshold is approximately equivalent to 500,000 scf
of natural gas, which aligns with the lower range of well blowouts
expected based on the average emission factor of 2.5 MMscf per event.
This value also aligns with the definitions of ``major release'' in New
Mexico Administrative Code (NMAC) section 19.15.29.7, which requires
reporting under NMAC section 19.15.29.10.
We also tentatively find that the proposed 250 mtCO<INF>2</INF>e
threshold (approximately equivalent to 500,000 scf natural gas release)
is a reasonable threshold for requiring individual assessments of
releases. In subpart Y (Petroleum Refineries), we established event-
specific emission calculation requirements for startup, shutdown, or
malfunction releases to a flare exceeding 500,000 scf per day (40 CFR
98.253(b)(1)(iii)). While the subpart Y threshold is per day rather
than per event, it is also specific to flared emissions. For flared
emissions to exceed a 250 mtCO<INF>2</INF>e threshold, approximately 4
MMscf of natural gas would have to be released to the flare, which is
well above the subpart Y ``per day'' threshold for flares. Thus, we
propose that the 250 mtCO<INF>2</INF>e per event threshold is an
appropriate size threshold for requiring event-specific emission
calculations to be performed. More information regarding our review and
characterization of types of other large release events is included in
the subpart W TSD, available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2023-0234. Emissions from smaller or routine release
events would still be reported, as applicable, under the source-
specific calculation and reporting requirements in subpart W.
We are also proposing a 100 kg/hr CH<INF>4</INF> emission threshold
to align with the super-emitter response program proposed in the NSPS
OOOOb. These emissions are generally intermittent, with widely varying
durations. Releases from maintenance activities, for example, may occur
for only a few hours, but these large, short events can

[[Page 50299]]

significantly contribute to a facility's emissions. The proposed
emission rate threshold for a super-emitter emissions event under NSPS
OOOOb provides a means to get information for these large, shorter
duration releases. Therefore, we are proposing that the 100 kg/hr
CH<INF>4</INF> emission threshold be applied as an instantaneous
emissions rate threshold, such that any emissions from any other large
release event that emits CH<INF>4</INF> at a rate of 100 kg/hr or more
at any point in time must be reported.
With a combination of both a cumulative mass emissions per event
threshold and the instantaneous 100 kg/hr CH<INF>4</INF> emission rate
threshold, the EPA is requesting comment whether a larger cumulative
mass emissions per event threshold is reasonable. Specifically, we
understand that the Pipeline and Hazardous Materials Safety
Administration (PHMSA) includes, in the definition of ``incident'' at
49 CFR 191.3, an ``unintentional estimated loss of three million cubic
feet or more.'' As many subpart W facilities are required to keep
records of these incidents, we request comment on the use of a 1,500
mtCO<INF>2</INF>e per event threshold, which would be approximately
equivalent to a 3 million cubic feet release of natural gas. We request
comment on whether the CO<INF>2</INF>e mass threshold is appropriate
for considering emissions from events such as fires, or if the
threshold should be expressed as a loss of 3 million cubic feet or more
of natural gas, whether directly emitted or partially burned via a
fire. We also request comment on whether these thresholds should be
assessed per event within the calendar year, rather than just per
event. We propose that the thresholds for other large release events
would be evaluated on a per event basis because then all events are
considered consistently regardless of when they occur. For example,
consider a 400 mtCO<INF>2</INF>e event that spans two calendar years,
with 200 mtCO<INF>2</INF>e released in each calendar year. As proposed,
the reporter would be required to report the other large release event
in each of the corresponding reporting years. If, however, the
thresholds were instead evaluated on a per event within a calendar year
basis, this emissions event would not qualify as an other large release
event in either reporting year. There may be cases where limiting the
thresholds to events to within a calendar year could reduce the number
of events reported without significantly missing emissions and
potentially limiting the number of report resubmissions. For example,
if the 400 mtCO<INF>2</INF>e event that spanned 2 calendar years
resulted in 40 mtCO<INF>2</INF>e of emission in reporting year 1 and
360 mtCO<INF>2</INF>e of emissions in reporting year 2, then if the
thresholds were evaluated on a per event per calendar year basis, only
the emissions in reporting year 2 would be required to be reported.
Under the thresholds as proposed, the 40 mtCO<INF>2</INF>e of emission
in reporting year 1 would be required to be reported. Depending on when
the other large release event was identified and start date determined,
this may require resubmission of a previously submitted subpart W
report. We request comment on whether the other large release event
thresholds should be limited to releases within a single calendar year.
We are proposing a definition of ``other large release events'' in
40 CFR 98.238 to clarify the types of releases that must be
characterized for this new emissions source and specify that other
large release events include, but are not limited to, maintenance
events, well blowouts, well releases, releases from equipment rupture,
fire, or explosions. Currently, there are no calculation methodologies
or reporting requirements for these types of large releases in subpart
W. The proposed definition would also include large pressure relief
valve releases from process equipment other than onshore production and
onshore petroleum and natural gas gathering and boosting storage tanks
that are not included in the blowdown definition. The proposed
definition of other large release events excludes pressure relief valve
releases from hydrocarbon liquids storage tanks because the calculation
methodology for storage tanks is expected to account for these releases
via either the proposed requirements to account for collection
efficiency when emissions are observed from the thief hatch or the
additional term in the emissions equation for when there is a stuck
dump valve. While subpart W currently includes emission factors for
pressure relief devices, these equipment leak emission factors only
account for leaks past a pressure relief valve that is in the closed
position, not releases from the complete opening of these valves. The
proposed definition specifies that pressure relief valve releases from
onshore production and onshore petroleum and natural gas gathering and
boosting storage tanks would not be considered other large release
events because the calculation methodology for these storage tanks
currently assumes all flash gas will be emitted. As noted in section
III.K of this preamble, pressure relief emission releases from onshore
production and onshore petroleum and natural gas gathering and boosting
storage tanks generally occur from the thief hatch and these releases
must be accounted for when calculating the fraction of flash gas that
is recovered or sent to a flare, if applicable. A more detailed
discussion of certain other emissions events we have identified and
expect to be subject to the ``other large release events'' proposed
amendments is included in the subpart W TSD available in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
As part of the proposed definition of ``other large release
events'' in 40 CFR 98.238, we are also proposing that other large
release events include releases from equipment for which the existing
calculation methodologies in subpart W would significantly
underestimate the episodic nature of these emissions. For example,
subpart W contains population emission factors and leaker emission
factors for estimating equipment leak emissions for storage wellheads.
Thus, it is possible to argue that subpart W includes calculation
methodologies for the equipment responsible for the Aliso Canyon
release. However, the calculation methodologies in subpart W do not
accurately estimate emissions from such an uncharacteristically large
release event because such events are infrequent such that they may not
exist when measurement studies are conducted. Additionally, if we
proposed to instead revise the emission factors under the existing
methodologies to account for such an event, the resulting calculation
would likely yield erroneously high emissions from normal operations
for most reporting facilities. Thus, we determined that it is more
accurate for facility-specific reporting to account for these large
releases on a per event basis. Therefore, if a single leak or event has
emissions that exceed the emissions estimated by an applicable
methodology included in subpart W by 250 mtCO<INF>2</INF>e or more on a
per event basis, or 100 kg/hr of CH<INF>4</INF> or more as an
instantaneous rate at any time during an event, we are proposing that
such releases would be included in the definition of ``other large
release events'' and that reporters would be required to calculate and
report the GHG emissions from these events using the proposed
requirements for other large release events. We are proposing in 40 CFR
98.233(y)(1)(ii) that this provision does not require the direct
measurement of every release, such as measurement of every leak
identified during an equipment leak monitoring survey. However, we are
proposing to require that if the owner or operator has credible
information that demonstrates

[[Page 50300]]

that the release meets or exceeds or may reasonably be anticipated to
meet or exceed (or to have met or have exceeded) the emissions
calculated by the source-specific methodology by 250 mtCO<INF>2</INF>e
or more, or 100 kg/hr of CH<INF>4</INF> or more, then the release must
be quantified and, if the thresholds are confirmed to be exceeded,
reported as an other large release event. We consider credible
information would include, but is not limited to, data from monitoring
or measurement data completed by the facility, information from
notifications as a potential super-emitter emissions event under the
super-emitter provisions of NSPS OOOOb at proposed 40 CFR 60.5371b or
data of similar quality as that provided through the provisions of NSPS
OOOOb at proposed 40 CFR 60.5371b that is received by the facility. We
anticipate that we would take into consideration what is included in
the final NSPS OOOOb regarding such notifications in the types of
information that would be considered credible for these provisions in
subpart W, if finalized. The owner or operator would be required to
consider all credible information they have regarding the release in
complying with this requirement.
Further, we are proposing to define the terms ``well release'' and
``well blowout'' in 40 CFR 98.238 to assist reporting facilities with
differentiating between these types of release events that could
potentially occur at wells. We find that a well blowout is generally
distinguished by a complete loss of well control for a long duration of
time and a well release is characterized as a short period of
uncontrolled release (not the controlled pre-separation stage of well
flowback in a hydraulically fractured completion) followed by a period
of controlled release in which control techniques were successfully
implemented.
Finally, we are proposing a series of reporting requirements in 40
CFR 98.236(y) related to the type, location, duration, calculations,
and emissions of each ``other large release event.'' Specifically, we
are proposing that reporters provide the location, a description of the
release (from a specified list that includes an ``other (specify)''
option for releases that are not described well with the list
provided), a description of the technology or method used to identify
the release, volume of gas released, volume fractions of CO<INF>2</INF>
and CH<INF>4</INF> in the gas released, and CO<INF>2</INF> and
CH<INF>4</INF> emissions for each ``other large release event.'' We are
also proposing that reporters would provide the start date and time of
the release, duration of the release, and the method used to determine
the start date and time (options would include a pressure monitor, a
temperature monitor, other monitored process parameter, most recent
monitoring or measurement survey showing no large release, or the
default assumption that the release started 182 days prior to the
documented end of the release (this would be the required assumption if
they do not have monitored data associated with the release). We are
also proposing that reporters provide a general description of the
event and indicate whether the ``other large release event'' was also
identified as a potential super-emitter emissions event under the
super-emitter provisions of NSPS OOOOb at 40 CFR 60.5371b or an
applicable approved state plan or applicable Federal plan in 40 CFR
part 62.
We are proposing that reporters that received super-emitter
emissions event notifications would be required to report information
on each release notification received, including latitude and longitude
of the release, whether the release was received under the super-
emitter provisions of NSPS OOOOb at 40 CFR 60.5371b or an applicable
approved state plan or applicable Federal plan in 40 CFR part 62 or
another notifier. If the notification is from another notifier, the
reporter would provide the name of the notifier, the remote sensing
method used, the date and time of the measurement, the measured
emission rate, and uncertainty bounds on the emission rate, if provided
by the notifier. We are also proposing that, for each notification
received, facilities would report the type of event resulting in the
emissions (e.g., normal operations, a planned maintenance event,
leaking equipment, malfunctioning equipment or device, or undetermined
cause) and an indication of whether the emissions identified from the
event are included as an other large release event or as another source
required to be reported under subpart W. If the emissions identified
via the notification are not included in emissions reported under
subpart W, we are proposing that the reporter provide a reason (e.g.,
the location of the emissions as provided in the notification do not
belong to the facility; the emissions could not be verified or
corroborated during site inspection or facility data records;
information was determined to not be credible and basis for the
determination). This information would support EPA verification and
ensure accuracy of the emissions reported under other large release
events.
As part of the GHGRP verification process, the EPA reviews data
provided in submitted reports to identify potential errors in the
reported data based on the different values reported and the
calculation methodology. The EPA requests comment on the need to
establish additional requirements for third-party notifiers and the
verification of third-party notifications. Generally, verification of
GHGRP reports is conducted while a facility is entering data into the
e-GGRT system and after the report is officially submitted. The EPA
requests comment on the need for EPA verification support or an advance
verification process during the reporting year for assessments of
third-party notifications. Currently, facilities with questions about
reporting requirements submit inquiries via the e-GGRT Help Desk to get
questions answered regarding monitoring or reporting requirements. We
request comment on whether this existing process is adequate for
supporting questions regarding individual third-party notifications
received by a reporter and request suggestions on how the EPA
verification process could better support the other large release event
calculation and reporting requirements.
The supplemental proposal for NSPS OOOOb and EG OOOOc, as described
in section II of this preamble, included a matrix for alternative
screening approaches for fugitive emissions from well sites and
compressor stations that would allow the use of advanced measurement
technologies to detect emissions under the proposed NSPS OOOOb and EG
OOOOc. As part of that proposal, the EPA also requested comment on how
to evaluate and design a requirement for owners and operators to
investigate and remediate large emission events, which could include
the use of alternative screening techniques and advanced measurement
technologies, all of which, if finalized, could potentially be used to
identify ``other large release events'' under subpart W. While some
methods that could be used to identify and estimate the magnitude of
these ``other large release events,'' such as monitors installed on
mobile vehicles or aircraft or CH<INF>4</INF> satellite imagery, would
not be specifically included as measurement methods listed in 40 CFR
98.234 of subpart W, these methods may be used to quantify the
emissions release for ``other large release events'' under the
``engineering estimates'' and ``best available data'' provisions of the
proposed calculation methodology. To improve the EPA's understanding of
the

[[Page 50301]]

technologies and methods used to identify reported ``other large
release events,'' including the impact of periodic screenings with
advanced measurement technologies on the identification of large
release events, we are proposing reporting provisions that would
require reporters to indicate whether each ``other large release
event'' was identified as part of compliance with NSPS OOOOb or the
applicable state plan or applicable Federal plan in 40 CFR part 62.

C. New and Additional Emission Sources

Sources of emissions that are required to be reported to subpart W
are listed in 40 CFR 98.232 for each industry segment, with the
methodology and reporting requirements for each source provided in 40
CFR 98.233 and 98.236, respectively. The EPA finalized this list of
emission sources for each of the eight original industry segments as
part of the 2010 Final Rule and identified emission sources for the
Onshore Petroleum and Natural Gas Gathering and Boosting and Onshore
Natural Gas Transmission Pipeline industry segments when those segments
were added to subpart W in 2015 (80 FR 64262, October 22, 2015). Per
the TSD for the 2010 Final Rule (hereafter referred to as the ``2010
subpart W TSD''),\28\ there were several factors that impacted the
EPA's decision on whether an emissions source should be included for
reporting. These factors included how significant the contribution of
the source was to the U.S. GHG Inventory, the type of emission expected
from the source (vented versus fugitive), the best practice monitoring
methods available to measure emissions from the source, accessibility
of the emission source, geographical dispersion of the emission source,
and the applicability of population versus leaker factors.
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\28\ Greenhouse Gas Emissions Reporting from the Petroleum and
Natural Gas Systems Industry: Background Technical Support. November
2010. Docket Id. No. EPA-HQ-OAR-2009-0923-3610; also available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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The EPA has evaluated the sources covered under subpart W in
comparison with present-day inventories of the oil and gas industry,
such as the 2022 U.S. GHG Inventory \29\ and the American Petroleum
Institute (API) 2021 Compendium of Greenhouse Gas Emissions
Methodologies for the Natural Gas and Oil Industry (2021 API
Compendium).\30\ The EPA also reviewed stakeholder feedback, including
public comments from the 2022 Proposed Rule, on missing sources of
emissions from subpart W. As a result, the EPA is proposing to add
several emission sources identified in this review that are anticipated
to have a meaningful impact on reported emissions, are commonplace in
the oil and gas industry, and/or have existing emission calculation
methodologies and reporting provisions in the current subpart W
regulatory text. For some of these emission sources, discussed in
additional detail in section III.C.1 of this preamble, reporting is
currently required for some, but not all, industry segments in which
they exist. Other proposed emission sources, discussed in additional
detail in sections III.C.2 through 5 of this preamble, are not
currently required to be reported for any industry segments in which
they exist. The proposed addition of sources to subpart W would be
expected to enhance the overall quality of the data collected under the
GHGRP and improve the accuracy of total emissions reported from
facilities, consistent with Congress' direction in the IRA and section
II.A of this preamble.
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\29\ Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-
2020. U.S. EPA. April 2022. Available at <a href="https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2020">https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2020</a> and in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
\30\ Compendium of Greenhouse Gas Emissions Methodologies For
The Natural Gas And Oil Industry. Produced by URS Corporation for
American Petroleum Institute. November 2021. Available at <a href="https://www.api.org/-/media/files/policy/esg/ghg/2021-api-ghg-compendium-110921.pdf">https://www.api.org/-/media/files/policy/esg/ghg/2021-api-ghg-compendium-110921.pdf</a>. Available in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2023-0234.
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The following sections detail the proposed additions of emission
sources to subpart W.
1. Current Subpart W Emission Sources Proposed for Additional Industry
Segments
Upon review of the U.S. GHG Inventory and the 2021 API Compendium,
as well as other publications,\31\ the EPA determined that several of
the emission sources included in at least one industry segment in
subpart W are not currently required to be reported by facilities in
all the industry segments in which those sources exist. As such,
consistent with section II.A of this preamble, we are proposing to add
requirements to report CO<INF>2</INF>, CH<INF>4</INF>, and nitrous
oxide (N<INF>2</INF>O) emissions (as applicable for the source type)
from the following sources under 40 CFR 98.232 and 98.236(a): \32\
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\31\ For example, American Petroleum Institute (API). Liquefied
Natural Gas (LNG) Operations Consistent Methodology for Estimating
Greenhouse Gas Emissions. Prepared for API by The LEVON Group, LLC.
Version 1.0, May 2015. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
\32\ It should be noted that the EPA did not identify any
subpart W emission sources missing from the Onshore Petroleum and
Natural Gas Gathering and Boosting industry segment.

<bullet> Onshore petroleum and natural gas production: Blowdown vent
stacks
<bullet> Onshore natural gas processing: Natural gas pneumatic device
venting, Hydrocarbon liquids and produced water storage tank emissions
<bullet> Onshore natural gas transmission compression: Dehydrator vents
<bullet> Underground natural gas storage: Dehydrator vents, Blowdown
vent stacks, Condensate storage tanks
<bullet> LNG storage: Blowdown vent stacks, Acid gas removal unit vents
<bullet> LNG import and export equipment: Acid gas removal unit vents
<bullet> Natural gas distribution: Natural gas pneumatic device
venting, Blowdown vent stacks
<bullet> Onshore natural gas transmission pipeline: Equipment leaks at
transmission company interconnect metering-regulating stations,
Equipment leaks at farm tap and/or direct sale metering-regulating
stations, Transmission pipeline equipment leaks

We are also proposing several revisions that would facilitate
implementation of the proposal to require reporting of these emission
sources from additional industry segments. We are proposing to revise
the name of the current emission source type ``onshore production and
onshore petroleum and natural gas gathering and boosting storage
tanks'' to ``hydrocarbon liquids and produced water storage tanks'' and
revise ``storage tank vented emissions'' to ``hydrocarbon liquids and
produced water storage tank emissions'' throughout subpart W. The
proposed removal of the reference to ``onshore production and onshore
petroleum and natural gas gathering and boosting'' would reflect a more
appropriate name corresponding to the proposed addition of the
reporting of these storage tank emissions for the Onshore Natural Gas
Processing industry segment; the addition of ``produced water'' to the
name is discussed in detail in section III.C.3 of this preamble.
Additionally, we are proposing to revise the emission source type name
in 40 CFR 98.233(k) and 98.236(k) from ``transmission storage tanks''
to ``condensate storage tanks,'' which would reflect a more appropriate
name corresponding to the proposed addition of the reporting of these
storage tank emissions for the

[[Page 50302]]

Underground Natural Gas Storage industry segment.\33\
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\33\ Revisions are also proposed to 40 CFR 98.232(e)(3) to
reference the source as ``condensate storage tanks.''
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We are also proposing revisions to the calculation methodologies
and/or emissions reporting structure for each of these emission source/
industry segment combinations that would be needed in 40 CFR 98.233 and
98.236, respectively. For industry segments for which we are proposing
to additionally require reporting of emissions from AGR vents,
dehydrator vents, hydrocarbon liquids and produced water storage tank
emissions, and condensate storage tank emissions, we are proposing that
reporters would use the same calculation methods and report the same
information as reporters in the industry segments in which those source
types are already reported. For these sources, the EPA is not aware of
differences in the operation of the emission sources between industry
segments that would necessitate separate calculation methodologies. The
remainder of this section describes additional proposed amendments to
40 CFR 98.233.
For the proposed addition of natural gas pneumatic device venting
as an emission source for the Onshore Natural Gas Processing industry
segment, we are proposing that those facilities would use the proposed
calculation methodologies as described in section III.E of this
preamble. For any reporters to the Onshore Natural Gas Processing
industry segment that would use proposed Calculation Methodology 3, the
emission factors we are proposing are the same as the proposed revised
emission factors for the Onshore Natural Gas Transmission Compression
and Underground Natural Gas Storage industry segments. As noted in the
subpart W TSD (available in the docket), the data available to develop
emission factors for the Onshore Natural Gas Processing industry
segment are limited, and because operations defined as being part of
these three industry segments are similar and can occur at the same
facilities, the EPA has historically applied the same population and
leaker emission factors to these three segments (e.g., equipment
leaks). See section III.E of this preamble for additional details about
the proposed calculation methodologies.
As noted earlier in this section, we are proposing to add blowdown
vent stack reporting to the Onshore Petroleum and Natural Gas
Production, Underground Natural Gas Storage, LNG Storage, and Natural
Gas Distribution industry segments. Subpart W currently requires
reporting of blowdowns either using flow meter measurements (existing
40 CFR 98.233(i)(3)) or using unique physical volume calculations by
equipment or event types (existing 40 CFR 98.233(i)(2)). There are two
lists of equipment or event types. One applies to the Onshore Natural
Gas Processing, Onshore Natural Gas Transmission Compression, LNG
Import and Export Equipment, and Onshore Petroleum and Natural Gas
Gathering and Boosting segments (proposed 40 CFR 98.233(i)(2)(iv)(A),
as discussed in section III.J.2 of this preamble). The other list of
equipment or event types (in proposed 40 CFR 98.233(i)(2)(iv)(B), as
discussed in section III.J.2 of this preamble) was developed for the
Onshore Natural Gas Transmission Pipeline industry segment when that
segment was added to subpart W in 2015 (80 FR 64275, October 22, 2015).
To allow reporters in the new industry segments to calculate emissions
by equipment or event types, the EPA is proposing to specify the
appropriate list of equipment or event types. We are proposing that
facilities in the Onshore Petroleum and Natural Gas Production,
Underground Natural Gas Storage, and LNG Storage industry segments
following the methodology in 40 CFR 98.233(i)(2) would be required to
categorize blowdown vent stack emission events into the seven
categories provided in proposed 40 CFR 98.233(i)(2)(iv)(A), as the
types of blowdown vent stack emission events for these segments are
similar to those for the segments currently required to categorize
under this provision.
We are proposing that facilities in the Natural Gas Distribution
industry segment would be required to categorize blowdowns into the
eight categories listed in proposed 40 CFR 98.233(i)(2)(iv)(B), as the
types of blowdowns that occur in the Natural Gas Distribution industry
segment are expected to be pipeline blowdowns similar to those in the
Onshore Natural Gas Transmission Pipeline industry segment. We note
that during the early stages of our review of potential new sources, we
considered whether to add emissions from mishaps (dig-ins) in the
Natural Gas Distribution industry segment as a new emission source.
However, mishaps (dig-ins) are already included on the list of
equipment and event types in proposed 40 CFR 98.233(i)(2)(iv)(B),
specifically emergency shutdowns including pipeline incidents as
defined in 49 CFR 191.3. Therefore, a proposed amendment is not
necessary to include those events.
We are proposing one other amendment related to the calculation of
emissions from blowdown vent stacks. The EPA previously determined that
for reporters in the Onshore Petroleum and Natural Gas Gathering and
Boosting industry segment using the methodology provided in existing 40
CFR 98.233(i)(2) and equation W-14A, it is reasonable to allow
engineering estimates based on best available information when
determining temperature and pressure for emergency blowdowns, due to
the geographically dispersed nature of the facilities in this industry
segment. As discussed in section III.J.3 of this preamble, we are
proposing to also allow engineering estimates based on best available
information when determining temperature and pressure for emergency
blowdowns for the Onshore Natural Gas Transmission Pipeline industry
segment, as facilities in this industry segment are also geographically
dispersed. Due to the fact that facilities in the Onshore Petroleum and
Natural Gas Production and Natural Gas Distribution industry segments
are similarly geographically dispersed, we are proposing that reporters
in those industry segments using the methodology provided in 40 CFR
98.233(i)(2) and equation W-14A would also be allowed to use
engineering estimates based on best available information available
when determining temperature and pressure for emergency blowdowns.
For the Onshore Natural Gas Transmission Pipeline industry segment,
as noted earlier in this section, we are proposing to add reporting of
emissions from equipment leaks from transmission pipelines,
transmission company interconnect metering-regulating stations, and
farm tap and/or direct sale stations. The EPA proposes to add these
sources to the calculation methodologies provided in 40 CFR 98.233(r),
with associated proposed updates to the variable definitions in
equation W-32A to include components in the Onshore Natural Gas
Transmission Pipeline industry segment. We are also proposing to add
default CH4 population emission factors for the components specified in
this paragraph at facilities in the Onshore Natural Gas Transmission
Pipeline industry segment in proposed Table W-5 of subpart W. The EPA
derived these proposed emission factors from the 1996 Gas Research
Institute (GRI)/EPA study Methane Emissions from the Natural Gas
Industry (hereafter referred to as ``the 1996 GRI/EPA study''),
specifically

[[Page 50303]]

Volumes 9 and 10.\34\ The precise derivation of the proposed emission
factors is discussed in more detail in the subpart W TSD, available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234. We
are proposing that emissions from these components would be reported
using population emission factors, as we are not aware of any currently
available information or data that could be used to develop leaker
emission factors from transmission pipelines, transmission company
interconnect metering-regulating stations, or farm tap and/or direct
sale stations. We are seeking comments on whether there are study data
available which could be used to develop default leaker factors whereby
subpart W could include the use of equipment leak surveys, default
component-specific leaker emission factors, and the calculation method
in 40 CFR 98.233(q) an as option for transmission pipeline facilities
to quantify emissions from transmission company interconnect metering-
regulating stations, or farm tap and/or direct sale stations.
Similarly, we are seeking comment on whether an option to survey
components at transmission company interconnect metering-regulating
stations, or farm tap and/or direct sale stations using the existing
methods in subpart W in 40 CFR 98.234 (e.g., EPA Method 21, optical gas
imaging (OGI)) and directly measuring and reporting emissions
consistent with proposed 40 CFR 98.233(q)(3) should be provided; or
whether a methodology in which a multi-year leak survey cycle and the
application of either default emission factors or measurements used
with the methods provided in 40 CFR 98.233(q) should be provided
analogous to the methodology provided for above grade transmission-
distribution transfer stations should be provided. We are specifically
interested in comments on which approach would be preferred and the
supporting rationale.
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\34\ Methane Emissions from the Natural Gas Industry, Volume 9:
Underground Pipelines, Final Report (GRI-94/0257.26 and EPA-600/R-
96-080i) and Volume 10: Metering and Pressure Regulating Stations in
Natural Gas Transmission and Distribution, Final Report (GRI-94/
0257.27 and EPA-600/R-96-080j). Gas Research Institute and U.S.
Environmental Protection Agency. June 1996. Available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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Separately, concerning the quantification of emissions from
transmission pipelines, we are seeking comments on alternative methods
for surveying for equipment leaks as well as quantifying and reporting
emissions from these emission sources. We are specifically interested
in what survey techniques would be appropriate and why, including
supporting information on specific instruments and their detection
capabilities and whether certain methods would be more suitable for the
survey of pipeline leaks than others. We are also seeking comment on
what quantification techniques would be best suited for measuring
emissions from pipeline leaks and whether these techniques require
digging down to the pipeline in order to quantify emissions and also
verify pipeline characteristics. As an example, the EPA performed a
review of recent study data (Weller et al. 2020) that used an
alternative technology, namely AMLD, for the purposes of performing
surveys to identify leaks and as a method to quantify emissions from
pipeline leaks. For the reasons discussed in section III.Q.2 of this
preamble and discussed in more detail in the subpart W TSD, available
in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234,
we are not proposing amendments based on that study or use of that
technology. Instead, we are seeking comment on the scope and frequency
of leak detection surveys and measurements for transmission pipelines.
We are considering whether we should require annual surveys of the
entire pipeline system or whether a reduced frequency of survey (i.e.,
partial surveys over a multi-year survey cycle in which the entire
system is surveyed during the survey cycle and approximately equal
portions of the system are surveyed each year of the multi-year survey
cycle) is more appropriate and why. Finally, we are seeking comment on
whether facilities should be permitted to develop facility-specific
pipeline emission factors based on direct measurements and if so, what
the appropriate number of measurements should be for determining a
representative emission factor for each pipeline material including
supporting rationale.
2. Nitrogen Removal Units
The EPA is proposing to revise existing 40 CFR 98.232, 98.233(d),
and 98.236(d) to add calculation and reporting requirements for
CH<INF>4</INF> emissions from nitrogen removal units used in the
Onshore Petroleum and Natural Gas Production, Onshore Natural Gas
Processing, Onshore Petroleum Natural Gas Gathering and Boosting, LNG
Storage, and LNG Import and Export Equipment industry segments.
Nitrogen removal units remove nitrogen from the raw natural gas stream
to meet pipeline requirements and for compressing natural gas into
LNG.35 36 The nitrogen removal unit typically follows in
series after other process units that remove acid gas (e.g., CO2,
hydrogen sulfide), water, and heavy hydrocarbons. It is estimated that
11 percent of current daily production and 16 percent of known gas
reserves in the U.S. contain some nitrogen.\37\ Methane emissions from
nitrogen removal units occur from the vent and as fugitives. A nitrogen
removal unit separates the nitrogen gas from the CH<INF>4</INF>
resulting in an outlet CH4 stream that contains approximately 2 to 5
percent nitrogen\38\ and an outlet nitrogen stream that can contain 1
to 5 percent CH<INF>4</INF> (EPA 2005).\39\ Optimization of the
nitrogen removal unit can reduce CH<INF>4</INF> in the outlet nitrogen
stream to 2 percent (EPA 2005) and even to 1 percent CH<INF>4</INF> by
volume.\40\ The EPA GasSTAR program already accounts for CH<INF>4</INF>
emissions from nitrogen removal unit vents and fugitives.
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\35\ Kuo, J.C., K.H. Wang, C. Chen. Pros and cons of different
Nitrogen Removal Unit (NRU) technology. 7 (2012) 52-59. Journal of
Natural Gas Science and Engineering. July 2012. Available in the
docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
\36\ Park, J., D. Cho. Decision methodology for nitrogen removal
process in the LNG plant using analytic hierarchy process. Journal
of Industrial and Engineering Chemistry. 37 (2016) 75-83. 2016.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
\37\ Kuo 2012.
\38\ Weidert, D.J., and R.B. Hopewell. Holding the Key.
Hydrocarbon Engineering. August 2016. Available in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
\39\ EPA 2005. Optimizing Nitrogen Rejection Units, Lessons
Learned from Natural Gas STAR. Gas Processors Association, Devon
Energy, Enogex, Dynegy Midstream Services, and EPA's Natural Gas
STAR Program. Presented at Processors Technology Transfer Workshop.
April 22, 2005. Available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2023-0234.
\40\ Nitrogen Rejection Unit Optimization, PRO Fact Sheet No.
905. U.S. Environmental Protection Agency, Partner Reported
Opportunities (PROs) for Reducing Methane Emissions. 2011. Available
in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-
0234.
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Based upon a 2002 field study conducted at four natural gas
processing plants,\41\ the EPA estimates that emissions from nitrogen
removal unit vents that would be reported to the GHGRP would be
approximately 2,400 mt CH<INF>4</INF> per year. For more information on
the estimation of potential CH<INF>4</INF> emissions from nitrogen
removal unit venting see the subpart W TSD, available in the docket for
this

[[Page 50304]]

rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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\41\ Identification and Evaluation of Opportunities to Reduce
Methane Losses at Four Gas Processing Plants. Prepared for Gas
Technology Institute under U.S. EPA Grant No. 827754-01-0.
Clearstone Engineering. June 20, 2002. Available in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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The EPA is proposing to define ``nitrogen removal unit'' in 40 CFR
98.238 as a process unit that separates nitrogen from natural gas using
various separation processes (e.g., cryogenic units, membrane units)
and ``nitrogen removal unit vent emissions'' as the nitrogen gas
separated from the natural gas and released with CH<INF>4</INF> and
other gases to the atmosphere, flare, or other combustion unit. The EPA
is proposing to amend 40 CFR 98.232(c)(17), 98.232(d)(5),
98.232(g)(10), 98.232(h)(9), and 98.232(j)(3) to add nitrogen removal
unit vents to the list of source types for which the industry segments
previously specified would be required to report emissions.
Corresponding additions are proposed at 40 CFR 98.236(a) to add
nitrogen removal units to the list of equipment and activities that
would be reported for each of these industry segments.
The EPA is proposing CH<INF>4</INF> emission calculation
methodologies for nitrogen removal units that are identical to the
existing calculation methodologies in 40 CFR 98.233(d) for AGRs (which
currently apply to calculating emissions of CO<INF>2</INF>). These
methods include use of vent meters, engineering calculations based upon
flowrate of gas streams, or calculation using simulation software.
Further, the EPA is proposing to add relevant reporting elements for
CH<INF>4</INF> emissions from nitrogen removal units to 40 CFR
98.236(d) for each of the proposed allowable calculation methodologies.
As a part of this proposed rulemaking, the EPA is also proposing to
require the reporting of CH<INF>4</INF> emissions from AGR vents. Refer
to section III.F.1 of this preamble for more detailed discussion of the
calculation methodologies, including additional revisions proposed as
part of this rulemaking and which we propose would also apply to
nitrogen removal units.
The EPA is proposing that nitrogen removal unit vents routed to a
flare would follow the same calculation requirements as other flared
emission source types in proposed 40 CFR 98.233(n) and that flared
nitrogen removal unit emissions (CO<INF>2</INF>, CH<INF>4</INF>, and
N<INF>2</INF>O) would be reported under proposed 40 CFR 98.236(n)
separately from vented nitrogen removal unit emissions
(CH<INF>4</INF>). The flared nitrogen removal unit emissions would be
included with ``other'' flared source types for purposes of the
proposed disaggregation provisions in proposed 40 CFR 98.233(n)(10) and
proposed 40 CFR 98.236(n)(19). See section III.N of this preamble for
more information on the proposed flaring calculation and reporting
provisions.
The EPA is seeking comment on the proposal to require reporting of
CH<INF>4</INF> emissions from nitrogen removal unit venting, including
the estimated magnitude of emissions, which industry segments, if any,
should be required to report nitrogen removal unit vent emissions, and
whether the existing calculation methods for AGR vents are appropriate
and if there are other methods the EPA should consider.
3. Produced Water Tanks
The EPA is proposing to add CH<INF>4</INF> emissions from produced
water tanks to subpart W. The EPA is proposing to define ``produced
water'' consistent with the definition in the effluent guidelines for
the oil and gas extraction point source category (40 CFR 435.11(bb)),
which is the water (brine) brought up from the hydrocarbon-bearing
strata during the extraction of oil and gas, and can include formation
water, injection water, and any chemicals added downhole or during the
oil/water separation process. Produced water is the largest wastewater
source by volume generated during oil and gas extraction.\42\ The ratio
of produced water to recovered hydrocarbon is extremely variable across
the U.S., ranging from less than 1:1 to more than 100:1.\43\ In the
2022 U.S. GHG Inventory emissions estimate for 2020, the EPA estimated
approximately 140,300 mt CH<INF>4</INF> emissions from produced water
tanks associated with natural gas wells and 88,600 mt CH<INF>4</INF>
emissions from produced water tanks associated with oil wells.
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\42\ Summary of Input on Oil and Gas Extraction Wastewater
Management Practices Under the Clean Water Act. Final Report. EPA-
821-S19-001. U.S. Environmental Protection Agency, Engineering and
Analysis Division, Office of Water. Washington, DC May 2020.
\43\ Ibid.
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The EPA is proposing amendments to 40 CFR 98.233(j) to require
reporters with atmospheric pressure storage tanks receiving produced
water to calculate CH<INF>4</INF> emissions using any of the three
calculation methodologies specified in 40 CFR 98.233(j)(1) through
(3).\44\ For facilities with produced water storage tanks electing to
model their CH<INF>4</INF> emissions consistent with 40 CFR
98.233(j)(1), the EPA is proposing to allow facilities to select any
software option that meets the requirements currently stated in 40 CFR
98.233(j)(1) (i.e., to select a modeling software that uses the Peng-
Robinson equation of state, models flashing emissions from produced
water, and speciates CH<INF>4</INF> emissions that result when the
produced water from the separator or non-separator equipment enters an
atmospheric pressure storage tank), but we request comment on whether
the Peng-Robinson equation of state should be used for produced water
tanks and whether there are other parameters that should be considered
requirements for modeling emissions from produced water tanks. We
expect that modeling flashing emissions from produced water tanks would
calculate accurate estimates of CH<INF>4</INF> emissions, as it is
widely accepted that these models provide accurate estimates of
flashing emissions from hydrocarbon liquids atmospheric storage tanks.
Therefore, we expect process simulation software options such as Bryan
Research & Engineering (BRE)'s ProMax[supreg] \45\ (ProMax) would be
appropriate for modeling produced water CH<INF>4</INF> emissions. For
example, BRE has produced a white paper regarding ProMax's accuracy in
predicting produced water emissions.\46\ However, per the 2021 API
Compendium, the EPA is aware that API 4697 E&P Tanks v3.0 program \47\
is not appropriate for determining emissions from produced water tanks,
as the program's methodology is based on properties specific to crude
oil. Given that API's E&P Tanks software cannot model produced water
tanks, we are proposing to specifically state in 40 CFR 98.233(j)(1)
that API's E&P Tanks should only be used for modeling atmospheric
storage tanks receiving hydrocarbon liquids.
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\44\ As part of the proposed amendment to require reporters to
calculate and report emissions from produced water tanks, we are
also proposing conforming edits throughout subpart W to refer to
hydrocarbon liquids and produced water instead of just hydrocarbon
liquids.
\45\ BRE Promax[supreg] software available from BRE website
(<a href="https://www.bre.com/">https://www.bre.com/</a>).
\46\ Are Produced Water Emission Factors Accurate? Bryan
Research & Engineering, Inc. Available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
\47\ E&P Tanks v3.0 software and the user guide (Publication
4697) formerly available from the API website.
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There are several documents that address produced water emissions;
however, the emission factors used in all of these documents all
ultimately trace back to the 1996 GRI/EPA study.\48\

[[Page 50305]]

Therefore, the EPA is proposing to add CH<INF>4</INF> emission factors
to 40 CFR 98.233(j)(3) that were developed as part of the 1996 GRI/EPA
study,\49\ which is consistent with the factors used by the U.S. GHG
Inventory.\50\ The emission estimates from the 1996 GRI/EPA study were
estimated using an ASPEN PLUS process simulation assuming the natural
gas industry produces 497 million barrels of salt water annually,
including approximately 100 million barrels from coal bed
CH<INF>4</INF> wells; 70 percent of the water from gas wells is
reinjected with the remaining 30 percent stored in atmospheric tanks;
and hydrocarbon composition is 100 percent CH<INF>4</INF>.\51\ The 1996
GRI/EPA study estimated produced water emissions for salt contents of
2, 10, and 20 percent, and pressures of 50, 250, and 1,000 pounds per
square inch. The 2021 API Compendium (Table 6-26) provides the 1996
GRI/EPA emission factors converted from units of million pounds per
year to units of metric tons per thousand barrels (based upon the
assumption of 497 million barrels of produced water annual production).
In addition, average emission factors were calculated for each
pressure.
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\48\ Studies referencing the 1996 GRI/EPA study produced water
emission factors include: (1) 2021 API Compendium; (2) Oil & Gas
Production Protocol, Annex II to the General Reporting Protocol,
Version 1.0. The Climate Registry. February 2010; (3) 2011 Oil and
Gas Emission Inventory Enhancement Project for CenSARA States.
Produced by ENVIRON International Corporation and Eastern Research
Group, Inc. (ERG) for Central States Air Resources Agencies
(CenSARA). December 2012; and (4) Instructions for Using the 2017
EPA Nonpoint Oil and Gas Emissions Estimation Tool, Production
Module. Produced by Eastern Research Group, Inc. (ERG) for U.S.
Environmental Protection Agency. October 2019.
\49\ Methane Emissions from the Natural Gas Industry, Volume 6:
Vented and Combustion Source Summary, Final Report. GRI-94/0257.23
and EPA-600/R-96-080f. Gas Research Institute and U.S. Environmental
Protection Agency. June 1996. Available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
\50\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2019: Updates for Produced Water Emissions. April 2021.
Available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2023-0234.
\51\ Atlas of Gas Related Produced Water for 1990. 95/0016.
Produced by Energy Environmental Research Center, University of
North Dakota, and ENSR Consulting and Engineering for Gas Research
Institute. May 1995. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
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We also propose to add reporting requirements for produced water
tanks. The provisions in 40 CFR 98.236(j)(1) are proposed to be revised
to refer to both hydrocarbon liquid and produced water atmospheric
storage tanks. Additionally, we are proposing to add reporting
requirements to 40 CFR 98.236(j)(2) for total annual produced water
volumes for each pressure range, estimates of the fraction of produced
water throughput that is controlled by flares and/or vapor recovery,
counts of controlled and uncontrolled produced water tanks, and annual
CH<INF>4</INF> emissions vented directly to atmosphere from produced
water tanks. Flared produced water tank emissions would be reported
under 40 CFR 98.236(n), as proposed in section III.N.2 of this
preamble. Industry segments required to report emissions from produced
water tanks would include Onshore Petroleum and Natural Gas Production,
Onshore Petroleum and Natural Gas Gathering and Boosting, and Onshore
Natural Gas Processing. The EPA is also proposing to revise the
emission source type name in 40 CFR 98.233(j) and 40 CFR 98.236(j) from
``onshore production and onshore petroleum and natural gas gathering
and boosting storage tanks'' to ``hydrocarbon liquids and produced
water storage tanks'' to reflect the proposed addition of produced
water tanks. The EPA is also proposing to revise the source type
provided in 40 CFR 98.232(c)(10) and 40 CFR 98.232(j)(6) to
``Hydrocarbon liquid and produced water storage tank emissions'' which
reflects the addition of produced water tanks.
4. Mud Degassing
The EPA is proposing to add a new emission source type to subpart W
for emissions from drilling mud degassing. The proposed amendments for
this new source type would add calculation and reporting requirements
for CH<INF>4</INF> emissions from mud degassing associated with well
drilling for onshore petroleum and natural gas production facilities in
40 CFR 98.232(c), 98.233(dd), and 98.236(dd). In this proposal, the EPA
is not proposing to require the reporting of CO<INF>2</INF> emissions
from this source. Based on available research, it appears that
CH<INF>4</INF> is the primary GHG emitted from this source, while
emissions of CO<INF>2</INF> are expected to be very small. However, as
noted later in this section, the EPA is seeking comment on requiring
reporting of CO<INF>2</INF> emissions from mud degassing, including
comment on the expected magnitude of CO<INF>2</INF> emissions from mud
degassing and appropriate calculation methods for CO<INF>2</INF>
emissions from mud degassing.
The term ``drilling mud,'' also referred to as ``drilling fluid,''
refers to a class of viscous fluids used during the drilling of oil and
gas wells. Throughout the drilling process, drilling mud is pumped
continuously through the drill string and out the bit to cool and
lubricate the drill bit, carry cuttings away from the drill bit, and to
maintain the desired pressure within the well. The three types of
drilling mud used in the oil and gas industry are water-based, oil-
based, and synthetic-based muds. The density of the mud can be
controlled to counteract formation pressure, and drilling mud adds
stability to the bore hole. During drilling, gas is freed from rock
drilled out of the wellbore and becomes entrained in the drilling mud
that is being pumped continuously through the drill string.
As drilling mud circulates through the wellbore, natural gas and
heavier hydrocarbons can become entrained in the mud. Mud degassing
refers to the practice of extracting the entrained gas from drilling
mud once it is outside the wellbore. Gas entrained in the drilling mud
is separated from the mud in a mud separator and then vented directly
to the atmosphere or flared. The entrained gas contains CH<INF>4</INF>
and can contain other pollutants such as volatile organic compounds
(VOC) and possibly CO<INF>2</INF>, depending on the gas characteristics
of the hydrocarbon-bearing zones through which the borehole is drilled,
including the target zone. Although the majority of natural gas will be
released when the mud passes through the mud separator, small
quantities of natural gas will remain entrained in the drilling mud and
in the rock cuttings after the mud passes through the traps. These
small quantities will eventually be released to the atmosphere as the
drilling mud and associated cuttings are stored, processed and
disposed.
Based on our review of the available information regarding mud
degassing emissions, we note that mud degassing has been included only
in a limited number of U.S. state-level, regional and national
inventories of the onshore oil and gas production segments, mostly due
to a lack of sufficient data to characterize the emissions. In a 1977
EPA publication titled, Atmospheric Emissions from Offshore Oil and Gas
Development and Production,\52\ the EPA estimated two total hydrocarbon
(THC) emission factors in units of emissions per drilling day, one for
water-based mud degassing and the other for oil-based mud degassing,
based on engineering calculations. The 1977 EPA publication does not
include emission factors for synthetic-based mud. Several entities,
such as the state of New York and the Central States Air Resources
Agency (CenSARA), have incorporated estimates for mud degassing in
their inventory estimates. A CenSARA study conducted in 2011 developed
default emission factors derived from the 1977 EPA report.\53\ The
CenSARA study

[[Page 50306]]

added a THC emission factor for synthetic drilling muds and also
provided emission factors in mt CH<INF>4</INF> per drilling day. The
THC emission factors are 881.84 pounds per drilling day for water-based
muds and 198.41 pounds per drilling day for oil-based and synthetic
drilling muds. The CH<INF>4</INF>-specific emission factors are 0.2605
mt CH<INF>4</INF> per drilling day for water-based muds and 0.0586 mt
per drilling day for oil-based and synthetic drilling muds; they are
based on an assumption of 83.85 percent CH<INF>4</INF> in the gas
stream vented from mud degassing. The CenSARA methodology does allow
for adjustment of the CH<INF>4</INF> default emission factors to local
conditions by multiplying the nationwide emission factor to the ratio
of the local CH<INF>4</INF> mole percent of vented gas to the mole
percent of CH<INF>4</INF> from the vented gas used to derive the
CenSARA emission factor (83.85).
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\52\ Atmospheric Emissions from Offshore Oil and Gas Development
and Production. Produced by Energy Resources Co. for Environmental
Protection Agency. Available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
\53\ 2011 Oil and Gas Emission Inventory Enhancement Project for
CenSARA States. Produced by ENVIRON International Corporation for
Central States Air Resources Agencies. November 2011. Available at
<a href="https://www.deq.ok.gov/wp-content/uploads/air-division/EI_OG_Final_Report_CenSara_122712.pdf">https://www.deq.ok.gov/wp-content/uploads/air-division/EI_OG_Final_Report_CenSara_122712.pdf</a> and in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2023-0234.
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For its emissions inventory, the state of New York based its
emission factor for mud degassing on the CenSARA study, while also
concluding that communication with experts indicated that there were
not any more recent estimates available.\54\ Furthermore, New York only
adopted the CenSARA CH<INF>4</INF> emission factor of 0.2605 mt
CH<INF>4</INF> per drilling day for water-based muds. This factor
serves as the single emission factor for New York. Unlike CenSARA, New
York's calculation methods do not provide the ability for users to make
a local adjustment to the emission factor. Both CenSARA and New York
define the number of drilling days as the completion date minus the
spud date.
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\54\ New York State Oil and Gas Sector: Methane Emissions
Inventory. Produced by Abt Associates for New York State Energy
Research and Development Authority. November 2022. Available at
<a href="https://www.nyserda.ny.gov/-/media/Project/Nyserda/Files/Publications/Energy-Analysis/22-38-New-York-State-Oil-and-Gas-Sector-Methane-Report-acc.pdf">https://www.nyserda.ny.gov/-/media/Project/Nyserda/Files/Publications/Energy-Analysis/22-38-New-York-State-Oil-and-Gas-Sector-Methane-Report-acc.pdf</a> and in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2023-0234.
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The U.S. GHG Inventory does not currently include mud degassing
emissions. In 2020, the EPA released a memorandum discussing the
potential inclusion of CH<INF>4</INF> emissions estimates for mud
degassing as an update under consideration for the U.S. GHG Inventory,
based on the THC emission factors presented in the 1977 EPA
publication.\55\ Specifically, the memorandum provided emission factors
of 0.32 mt CH<INF>4</INF> per drilling day for water-based drilling
muds and 0.07 mt CH<INF>4</INF> per drilling day for oil-based drilling
muds in the discussion. The CH4 emission factor presented for
consideration for updating the U.S. GHG Inventory assumed a default
CH<INF>4</INF> fraction (by weight) of 61.2 percent for associated gas.
The EPA has not to date incorporated the use of these emission factors,
and mud degassing is not included in the current U.S. GHG Inventory.
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\55\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks 1990-2019: Update under Consideration for Mud Degassing
Emissions. September 2020. Available at <a href="https://www.epa.gov/sites/default/files/2020-09/documents/ghgi-webinar2020-degassing.pdf">https://www.epa.gov/sites/default/files/2020-09/documents/ghgi-webinar2020-degassing.pdf</a> and
in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2023-
0234.
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Separately, API published updated CH<INF>4</INF> and whole gas
emission factors based on the emission factors from the 1977 EPA
publication in their 2021 API Compendium.\56\ API's updated
CH<INF>4</INF> emission factors are based on a gas content of 65.13
weight percent CH<INF>4</INF>, derived from sample data provided in the
1977 EPA publication. While including the same THC and CH<INF>4</INF>
emission factor

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